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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address, and Telephone Number Identification No.
- ---------------- --------------------------------------------- ---------------------
001-09120 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED 22-2625848
(A New Jersey Corporation)
80 Park Plaza
P.O. Box 1171
Newark, New Jersey 07101-1171
973 430-7000
http://www.pseg.com
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Securities registered pursuant to Section 12 (b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
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Common Stock without par value New York Stock Exchange
Trust Originated Preferred Securities (Guaranteed Preferred Beneficial
Interest in PSEG's Debentures), $25 par value at 7.44%, issued by Enterprise
Capital Trust I (Registrant).
Trust Originated Preferred Securities (Guaranteed Preferred Beneficial
Interest in PSEG's Debentures), $25 par value at 7.25%, issued by Enterprise
Capital Trust III (Registrant).
Securities registered pursuant to Section 12 (g) of the Act:
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, LIBOR plus 0.875%, Due 2002.
The aggregate market value of the Common Stock of Public Service Enterprise
Group Incorporated held by non-affiliates as of January 31, 2002 was
$8,470,188,650 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:
Class Outstanding at January 31, 2002
----- -------------------------------
Common Stock, without par value 205,839,018
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K Documents Incorporated by Reference
- ----------------- -----------------------------------------------------------
III Portions of the definitive Proxy Statement for the Annual
Meeting of Stockholders of Public Service Enterprise Group
Incorporated to be held April 16, 2002, which definitive
Proxy Statement is expected to be filed with the Securities
and Exchange Commission on or about March 6, 2002, as
specified herein.
Indicate by check mark whether the registrants (1) have
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)
have been subject to such filing requirements for the past
90 days. Yes [ X ] 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. [ ]
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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TABLE OF CONTENTS
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Page
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PART I
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Item 1. Business............................................................................................. 1
General.............................................................................................. 1
Risk Factors......................................................................................... 6
Competitive Environment.............................................................................. 13
Regulatory Issues.................................................................................... 14
Customers............................................................................................ 20
Employee Relations................................................................................... 21
Segment Information.................................................................................. 21
Environmental Matters................................................................................ 21
Item 2. Properties........................................................................................... 27
Item 3. Legal Proceedings.................................................................................... 33
Item 4. Submission of Matters to a Vote of Security Holders.................................................. 37
PART II
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Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................................ 37
Item 6. Selected Financial Data.............................................................................. 38
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 39
Corporate Structure.................................................................................. 39
Overview of 2001 and Future Outlook.................................................................. 40
Results of Operations................................................................................ 42
Liquidity and Capital Resources...................................................................... 49
Capital Requirements................................................................................. 55
Qualitative and Quantitative Disclosures About Market Risk........................................... 57
Foreign Operations................................................................................... 61
Accounting Issues.................................................................................... 61
Forward Looking Statements........................................................................... 64
Item 7A. Qualitative and Quantitative Disclosures About Market Risk........................................... 65
Item 8. Financial Statements and Supplementary Data.......................................................... 65
Consolidated Financial Statements.................................................................... 66
Notes to Consolidated Financial tatements............................................................ 71
Financial Statement Responsibility................................................................... 122
Independent Auditors' Report......................................................................... 123
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure................. 124
PART III
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Item 10. Directors and Executive Officers..................................................................... 124
Item 11. Executive Compensation............................................................................... 125
Item 12. Security Ownership of Certain Beneficial Owners and Management....................................... 125
Item 13. Certain Relationships and Related Transactions....................................................... 126
PART IV
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Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................................... 126
Schedule II--Valuation and Qualifying Accounts....................................................... 127
Signatures........................................................................................... 128
Exhibit Index........................................................................................ 129
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PART I
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ITEM 1. BUSINESS
GENERAL
PSEG
Public Service Enterprise Group Incorporated (PSEG), incorporated under the
laws of the State of New Jersey, with its principal executive offices located at
80 Park Plaza, Newark, New Jersey 07102, is an exempt public utility holding
company under the Public Utility Holding Company Act of 1935 (PUHCA). Unless the
context otherwise indicates, all references to "PSEG," "we," "us" or "our"
herein mean Public Service Enterprise Group Incorporated, and its consolidated
subsidiaries. We have four principal direct wholly-owned subsidiaries: Public
Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy
Holdings Inc. (Energy Holdings) and PSEG Services (Services).
The following organization chart shows PSEG and its principal subsidiaries,
as well as the principal operating subsidiaries of Power and Energy Holdings.
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PSEG
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PSE&G Power Energy Holdings Services
- ----- --------- ---------------------- -------------
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Fossil Global
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Nuclear Resources
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ER&T Energy Technologies
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PSE&G
PSE&G is a New Jersey corporation with 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 service in New Jersey. In August 2000, pursuant to the terms of
the Final Decision and Order (Final Order) issued by the New Jersey Board of
Public Utilities (BPU) under the New Jersey Energy Master Plan and the New
Jersey Electric Discount and Energy Competition Act (Energy Competition Act),
PSE&G transferred its electric generation-related assets and liabilities
including its wholesale power contracts to Power. PSE&G Transition Funding LLC
(Transition Funding), a bankruptcy remote subsidiary of PSE&G, was formed to
issue securitization bonds in connection with the partial recovery of its BPU
approved stranded costs.
PSE&G supplies 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
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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 corporations of national prominence. PSE&G's load requirements are
almost evenly split among residential, commercial and industrial customers.
PSE&G believes that it has all the franchises (including consents) necessary for
its electric and gas distribution operations in the territory it serves. Such
franchise rights are not exclusive.
PSE&G distributes electric energy and gas to end-use customers within its
designated service territory. All electric and gas customers in New Jersey have
the ability to choose an electric energy and/or gas supplier. PSE&G supplies
customers that are not served by a third party supplier (TPS). PSE&G's revenues
are based upon tariffs approved by the BPU for this service (see Regulatory
Issues). Pursuant to BPU requirements, PSE&G also serves as the supplier of last
resort for electric and gas customers within its service territory. PSE&G's
revenues are based upon tariffs approved by the BPU and the Federal Energy
Regulatory Commission FERC for these services (see Regulatory Issues). 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 its
control.
Electric Energy Supply
PSE&G has contracted with Power to provide the capacity and electricity
necessary to meet its needs of customers who do not choose a TPS. Power will
provide this basic generation service (BGS) obligation through July 31, 2002.
For each annual period thereafter, PSE&G is required to determine the BGS
supplier by competitive bid in accordance with BPU requirements. On June 29,
2001 PSE&G and the other three BPU regulated New Jersey electric utility
companies submitted a joint filing to the BPU setting forth an auction proposal
for the provision of BGS energy supply beginning August 1, 2002. In addition,
each company also filed specific contingency plans and information related to
the auction. On December 10, 2001 the BPU approved an Internet auction to
determine who will supply BGS to utilities, which commenced on February 4, 2002.
This competitive auction covered the BGS supply requirement for the period
August 1, 2002 to July 31, 2003. As conditions of qualification, applicants
agreed that if they became auction winners, they would execute the BGS Master
Service Agreement within two days of BPU Certification of the results and they
would demonstrate compliance with the credit worthiness requirements. In
addition, qualified bidders were required to post bid bonds. On February 15,
2002 the BPU approved the auction results under which PSE&G secured contracts
for its expected peak load of 9,600 MW.
In addition, PSE&G purchases energy under various non-utility generation
(NUG) contracts and sells such energy to Power with the costs and proceeds
applied to the non-utility generation market transition clause (NTC) component
of PSE&G's rates (see Note 3. Regulatory Assets and Liabilities of Notes to
Consolidated Financial Statements (Notes)). Rates for electricity sold in the
wholesale energy market are not subject to BPU ratemaking and are competitive in
nature. Effective August 1, 2002, PSE&G will sell the generation from the NUGs
to the wholesale market.
Gas Supply
PSE&G supplements natural gas with purchased refinery/landfill gas and
liquefied petroleum gas produced from propane. The adequacy of supply of all
types of gas is affected by the nationwide availability of all sources of fuel
for energy production.
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As of December 31, 2001, the daily gas capacity of PSE&G was as follows:
Type of Gas Therms Per Day
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Natural gas ................................................... 24,379,300
Liquefied petroleum gas ....................................... 2,200,000
Refinery/landfill gas ......................................... 123,000
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Total ................................................ 26,702,300
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About 40% of the 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/landfill gas. PSE&G's total gas sold to and
transported for its various customer classes in 2001 was 3.7 billion therms.
Included in this amount were 1 billion therms of gas delivered to customers
under PSE&G's transportation tariffs and individual cogeneration contracts.
During 2001, PSE&G purchased approximately 3.3 billion therms of gas for its gas
operations directly from natural gas producers and marketers. These supplies
were transported to New Jersey by four interstate pipeline suppliers.
The majority of PSE&G's gas transportation and supply contracts expire at
various times over the next 10 years. Since the quantities of gas available to
PSE&G under its supply contracts are more than adequate in warm months, PSE&G
nominates part of such quantities for storage, to be withdrawn during the winter
season when demand peaks. Underground storage capacity currently is
approximately 800 million therms. For a discussion of the transfer of PSE&G's
gas contracts to Power, see Regulatory Issues-Gas Contract Transfer.
The demand for gas by PSE&G's customers is affected by customer
conservation, economic conditions, weather, the price relationship between gas
and alternative fuels and other factors not within its control. Rates for gas
sold in interstate commerce are not subject to cost of service ratemaking but
are subject to competitive pricing.
PSE&G was able to meet all of the demands of its firm customers during the
2000-2001 winter season and expects to continue to meet such energy-related
demands of its firm customers during the 2001-2002 and 2002-2003 winter seasons.
However, the sufficiency of supply could be affected by several factors not
within PSE&G's control, including curtailments of natural gas by its suppliers,
the severity of the winter weather and the availability of feedstocks for the
production of supplements to its natural gas supply. PSE&G presently does not
anticipate any difficulty in obtaining adequate supplies of natural gas over the
next several years.
Power
Power is a Delaware limited liability company with its principal executive
offices at 80 Park Plaza, Newark, New Jersey 07102. Power and its three
principal direct wholly-owned subsidiaries, PSEG Fossil LLC (Fossil), PSEG
Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) were
established to acquire, own and operate the generation-related business of PSE&G
pursuant to the Final Order issued by the BPU under the Energy Competition Act
discussed below. Power also has a finance company subsidiary, PSEG Power Capital
Investment Company (Power Capital), which provides certain financing for
Power's subsidiaries.
Power is a multi-regional generating and energy trading company that
integrates its generating asset operations with its wholesale energy, fuel
supply, energy trading and risk management expertise. Power currently has two
reportable segments, generation and energy trading. The generation segment of
Power's business earns revenues by selling energy on a wholesale basis under
contract to its utility affiliate, PSE&G, and to other power marketers and load
serving entities (LSE), and by bidding energy, capacity and ancillary services
into the wholesale energy market. Power has contracted to sell to BGS suppliers
beginning August 1, 2002. The energy trading segment of Power's business earns
revenues by trading energy, capacity, fixed transmission rights, fuel and
emission allowances in the spot, forward and futures markets. The energy trading
segment also earns revenues through financial transactions, including swaps,
options and futures in the energy markets. Power's target market, which is
herein referred to as the Super
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Region, extends from Maine to the Carolinas and the Atlantic Coast to Indiana,
encompassing 37% of the nation's power consumption. Power is the single
largest power supplier in its primary market, the Pennsylvania-New
Jersey-Maryland Power Pool (PJM), which is one of the nation's largest and most
well-developed energy markets.
Power's generation portfolio consists of 11,487 megawatts (MW) of installed
capacity owned or under contract which is diversified by fuel source and market
segment. In addition, Power is currently constructing projects which will
increase capacity by over 3,500 MW, net of planned retirements. For additional
information, see Item 2 - Properties.
Power participate primarily in the PJM market, where the pricing of energy
was recently modified. Prior to April 1999, the price of energy was based upon
the requirement that limited the bid prices for electric energy offered for sale
in the PJM market to the variable cost of producing such energy. As of April 1,
1999, the Federal Energy Regulatory Commission (FERC) lifted the requirement.
However, transmission constraints have and will continue to affect energy
pricing in PJM. All power providers are now paid the locational marginal price
(LMP) set through power providers' bids. The LMP tends to be higher in congested
areas reflecting the bid prices of the higher cost units that are dispatched to
supply demand and alleviate transmission constraints when coordination is
sufficient to satisfy demand within PJM. These bids are capped at $1,000 per
mWh. In the event that available generation within PJM is insufficient to
satisfy demand, PJM may institute emergency purchases from adjoining regions for
which there is no price cap.
Electric Fuel Supply and Disposal
The following table indicates Power's megawatt hour (mWh) output by source
of energy in 2001 and its estimated mWh output by source for 2002:
Actual Estimated
Source 2001 2002 (A)
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Nuclear:
New Jersey facilities.......... 42% 40%
Pennsylvania facilities........ 21% 19%
Fossil:
Coal:
New Jersey facilities.......... 12% 13%
Pennsylvania facilities........ 13% 13%
Oil and Natural Gas ........... 11% 13%
Pumped Storage................. 1% 1%
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Total...................... 100% 100%
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(A) No assurances can be given that actual output by source will match
estimates.
Fossil
Fossil has an ownership interest in 11 fossil generating stations in New
Jersey, one fossil generating station in New York and two fossil generating
stations in Pennsylvania. Fossil also has ownership interest in one
hydroelectric pumped storage facility in New Jersey. For additional information,
see Item 2. Properties--Power--Electric Generation Properties. Fossil uses coal,
natural gas and oil for electric generation. These fuels are purchased through
various contracts and in the spot market. Fossil does not anticipate any
difficulties in obtaining adequate coal, natural gas and oil supplies over the
next several years.
Fossil owns approximately 23% of the Keystone and Conemaugh coal-fired
generating stations located in western Pennsylvania and operated by the plants'
operator. Fossil has been advised that there are presently no anticipated
difficulties in obtaining adequate coal supplies for these facilities over the
next several years.
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Nuclear
Nuclear has an ownership interest in five nuclear generating units and
operates three of them, 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 LLC
(Exelon), and the Hope Creek Nuclear Generating Station (Hope Creek), 100% owned
by Nuclear. Exelon operates the Peach Bottom Atomic Power Station Units 2 and 3
(Peach Bottom 2 and 3), each of which is 50% owned by Nuclear. For additional
information, see Item 2. Properties.
Nuclear Fuel
Nuclear has several long-term contracts with uranium ore operators,
converters, enrichers and fabricators to meet the currently projected fuel
requirements for Salem and Hope Creek. Nuclear has been advised by Exelon that
it has similar contracts to satisfy the fuel requirements of Peach Bottom.
Refueling outages which are expected to last for approximately four to six weeks
are scheduled for Salem 1 and 2 and Peach Bottom 2 in 2002.
ER&T
ER&T purchases all of the capacity and energy produced by Fossil and
Nuclear. In conjunction with these purchases ER&T uses commodity and financial
instruments designed to cover estimated commitments for BGS and other bilateral
contract agreements (see Note 8. Financial Instruments, Energy Trading and Risk
Management of Notes). ER&T also markets electricity, capacity, ancillary
services and natural gas products on a wholesale basis throughout the Super
Region. ER&T is a fully integrated energy marketing and trading organization
that is active in the long-term and spot wholesale energy markets.
Energy Holdings
Energy Holdings participates in three energy-related reportable segments
through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG
Resources Inc. (Resources), and PSEG Energy Technologies Inc. (Energy
Technologies). Energy Holdings seeks investment opportunities in the rapidly
changing global energy markets, with Global focusing on the operating segments
of the electric industry and Resources making financial investments in the
energy industry. [Energy Technologies focuses on constructing, operating and
maintaining heating, ventilating and air conditioning (HVAC) systems and
providing energy-related engineering, consulting and mechanical contracting
services to industrial and commercial customers.]
Energy Holdings also has a finance subsidiary, PSEG Capital Corporation
(PSEG Capital), which provides privately-placed debt financing to Energy
Holdings' operating subsidiaries on the basis of a minimum net worth maintenance
agreement with PSEG (see MD&A - Liquidity and Capital Resources). Energy
Holdings is also the parent of Enterprise Group Development Corporation (EGDC),
a commercial property management business which is conducting a controlled exit
from this business.
Global
Global develops, owns and operates electric generation and distribution
facilities in selected high-growth areas of the worldwide energy market,
exclusive of Power's activities in its Super Region target market. In carrying
out its strategy, Global's assessment of potential opportunities includes a
multi-faceted analysis of the country, potential partners and transaction
economics. Global identifies target markets based on economic fundamentals,
including expected growth of electricity consumption, evaluation of the social,
political and regulatory climates and the opportunities for participation by
private power developers. Following the identification of target markets, Global
evaluates the possibility of utilizing partners having local contacts and
complementary expertise. Global's strategy is to consider investments or
projects in which it is the sole or a majority owner if justified by strategic
considerations, anticipated returns and other factors. Global focuses on
projects which are expected to meet or exceed its specified risk-adjusted rate
of return and which present potential synergies with existing projects or
anticipated future investments. Global has developed or acquired interests in
electric generation and/or distribution facilities in the United States,
Argentina, Brazil, Chile, China, India, Italy, Peru, Poland and Venezuela. In
addition, projects are in
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construction or advanced development in the United States, Argentina, China,
Italy, Oman, Poland, Taiwan, Tunisia and Venezuela. Global expects that future
development of projects will take place primarily outside the United States.
Global has ownership interests in 31 operating generation projects totaling
4,992 MW (2,047 MW net) and 13 projects totaling 3,205 MW (1,399 MW net) in
construction or advanced development. Of Global's generation projects in
operation, construction or advanced development 1,350 MW net or 39% are located
in the United States. Global currently owns interests in eight distribution
companies in Argentina, Brazil, Chile and Peru. For additional information, see
Item 2. Properties - Energy Holdings.
Fuel supply arrangements are designed to balance Global's ability to meet
long-term supply needs with price considerations. Global's project affiliates
utilize long-term contracts and spot market purchases to mitigate their
exposure. Global believes that there are adequate fuel supplies for the
anticipated needs of its generating projects. Global also believes that
transmission access and capacity are sufficient at this time for its generation
projects in operation or development.
Resources
Resources focuses on providing energy infrastructure financing in developed
countries. Resources invests in energy-related financial transactions and
manages a diversified portfolio of assets, including leveraged leases, operating
leases, leveraged buyout funds, limited partnerships and marketable securities.
Resources seeks to invest in transactions where its expertise and understanding
of the inherent risks and operating characteristics of energy-related assets
provide a competitive advantage. Resources currently expects to concentrate its
future investment activity on energy-related financial transactions.
As of December 31, 2001, Resources had approximately $2.4 billion or 79% of
its total assets invested in leveraged leases of energy-related plant and
equipment. The remainder of Resources' portfolio is further diversified across a
wide spectrum of asset types and business sectors including leveraged leases of
aircraft, railcars and real estate, limited partnership interests in project
finance transactions and leveraged buyout and venture funds. Approximately 95%
of the lease investments in Resources' portfolio are with lessees that have
investment grade credit ratings. Resources does not manage any fund or
partnership in its portfolio. The timing of distributions from certain
investments is not within Resources' control.
Energy Technologies
Energy Technologies is an energy management company that constructs,
operates and maintains HVAC systems for and provides energy-related engineering,
consulting and mechanical contracting services to industrial and commercial
customers in the Northeastern and Middle Atlantic United States. As of December
31, 2001, Energy Technologies had assets of $290 million.
We are evaluating the future prospects of Energy Technologies' business
model and its fit in the PSEG portfolio given the slower pace of retail energy
deregulation in the markets in which we are active, as well as, the substandard
performance of Energy Technologies since its inception.
Services
Services is a New Jersey Corporation with its principal executive offices
at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and
administrative services to PSEG and its subsidiaries.
RISK FACTORS
The following factors should be considered when reviewing our business and
are relied upon by us in issuing any forward-looking statements. Such factors
could affect actual results and cause such results to differ materially
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from those expressed in any forward-looking statements made by, or on behalf of
us. Some or all of these factors may apply to us and our subsidiaries.
Because a Portion of Our Business is Conducted Outside the United States,
Adverse International Developments Could Negatively Impact Our Business
A key component of our business strategy is the development, acquisition
and operation of projects outside the United States. The economic and political
conditions in certain countries where Global has interests, or in which Global
is or could be exploring development or acquisition opportunities, present risks
that may be different than those found in the United States including: delays in
permitting and licensing, construction delays and interruption of business, as
well as risks of war, expropriation, nationalization, renegotiation or
nullification of existing contracts and changes in law or tax policy. Changes in
the legal environment in foreign countries in which Global may develop or
acquire projects could make it more difficult to obtain non-recourse project
refinancing on suitable terms and could impair Global's ability to enforce its
rights under agreements relating to such projects.
Operations in foreign countries also present risks associated with currency
exchange and convertibility, inflation and repatriation of earnings. In some
countries in which Global may develop or acquire projects in the future,
economic and monetary conditions and other factors could affect Global's ability
to convert its cash distributions to United States Dollars or other freely
convertible currencies, or to move funds offshore from such countries.
Furthermore, the central bank of any such country may have the authority to
suspend, restrict or otherwise impose conditions on foreign exchange
transactions or to approve distributions to foreign investors. Although Global
generally seeks to structure power purchase contracts and other project revenue
agreements to provide for payments to be made in, or indexed to, United States
Dollars or a currency freely convertible into United States Dollars, its ability
to do so in all cases may be limited.
Credit, Commodity, and Financial Market Risks May Have an Adverse Impact
The revenues generated by the operation of our generating stations are
subject to market risks that are beyond our control. Our generation output will
either be used to satisfy our wholesale contracts or be sold into the
competitive power markets or under other bilateral contracts. 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. Although a majority of our revenue is generated by
the current BGS contract with PSE&G (which expires on July 31, 2002 and is
replaced with various contracts with direct bidders of the New Jersey BGS
Auction) and from bilateral contracts for the sale of electricity with
third-party LSEs and power marketers, generation revenues and results of
operations will be dependent upon prevailing market prices for energy, capacity
and ancillary services in the markets we serve.
Among the factors that will influence the market prices for energy,
capacity and ancillary services are:
o the extent of additional supplies of capacity, energy and ancillary
services from current competitors or new market entrants, including the
development of new generation facilities that may be able to produce
electricity less expensively;
o changes in the rules set by regulatory authorities with respect to the
manner in which electricity sales will be priced;
o transmission congestion in PJM and/or other competitive markets;
o the operation of nuclear generation plants in PJM and other competitive
markets beyond their presently expected dates of decommissioning;
o prevailing market prices for enriched uranium, fuel oil, coal and
natural gas and associated transportation costs;
o fluctuating weather conditions;
o reduced growth rate in electricity usage as a result of factors such as
national and regional economic conditions and the implementation of
conservation programs; and
o changes in regulations applicable to PJM and other Independent System
Operators (ISO).
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As a result of the BGS auction, Power has entered into a contract with the
direct suppliers of the New Jersey electric utilities, including PSE&G,
commencing August 1, 2002. These bilateral contracts are subject to credit risk.
This credit risk relates to the ability of counterparties to meet their payment
obligations for the power delivered under each BGS contract. Depending upon the
creditworthiness of the counterparty, this risk may be substantially higher than
the risk associated with potential nonpayment by PSE&G under the BGS contract
expiring July 31, 2002. Any failure to collect these payments under the new BGS
contracts with counterparties could have a material impact on our results of
operations, cash flows, and financial position.
Energy Obligations, Available Supply and Trading Risks May Have an Adverse
Impact
Our energy trading and marketing business frequently involves the
establishment of energy trading positions in the wholesale energy markets on
long-term and short-term bases. To the extent that we have forward purchase
contracts to provide or purchase energy in excess of demand, a downturn in the
markets is likely to result in a loss from a decline in the value of such long
positions as we attempt to sell energy in a falling market. Conversely, to the
extent that we enter into forward sales contracts to deliver energy we do not
own, or take short positions in the energy markets, an upturn in the energy
markets is likely to expose us to losses as we attempt to cover our short
positions by acquiring energy in a rising market.
If the strategy we utilize to hedge our exposures to these various risks is
not effective, we could incur significant losses. Our substantial energy trading
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 and short-term supply and demand imbalances, which
cannot be predicted with any certainty.
In addition, we are exposed to the risk that counterparties will not
perform their obligations. Although we have devoted significant resources to
develop our risk management policies and procedures as well as counterparty
credit requirements, and will continue to do so in the future, we can give no
assurance that losses from our energy trading activities will not have a
material adverse effect on our business, prospects, results of operations,
financial condition or net cash flows.
In connection with its energy trading business, Power must meet certain
credit quality standards as are required by counterparties. Standard industry
contracts generally require trading counterparties to maintain investment grade
rating. These same contracts provide reciprocal benefits to Power. If Power
loses its investment grade credit rating, ER&T would have to provide collateral
(letters of credit or cash), which would significantly impact the energy trading
business. This would increase our costs of doing business and limit our ability
to successfully conduct our energy trading operations.
The Electric Energy Industry is Undergoing Substantial Change
The electric energy industry in the State of New Jersey, across the country
and around the world is undergoing major transformations. As a result of
deregulation and the unbundling of energy supplies and services, the electric
energy markets are now open to competition from other suppliers in most markets.
Increased competition from these suppliers could have a negative impact on our
wholesale and retail sales. We are affected by many issues that are common to
the electric industry such as:
o ability to obtain adequate and timely rate relief, cost recovery,
including unsecuritized stranded costs, and other necessary regulatory
approvals;
o deregulation, the unbundling of energy supplies and services and the
establishment of a competitive energy marketplace for products and
services;
o energy sales retention and growth;
o revenue stability and growth;
o nuclear operations and decommissioning;
o increased capital investments attributable to environmental
regulations;
o managing energy trading operations;
o ability to complete development or acquisition of current and future
investments;
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o managing electric generation and distribution operations in locations
outside of traditional utility service territory;
o exposure to market price fluctuations and volatility;
o regulatory restrictions on affiliate transactions; and
o debt and equity market concerns.
Generation Operating Performance May Fall Below Projected Levels
The risks associated with operating power generation facilities (each of
which could result in performance below expected capacity levels) include:
o breakdown or failure of equipment or processes;
o disruptions in the transmission of electricity;
o labor disputes;
o fuel supply interruptions;
o limitations which may be imposed by environmental or other regulatory
requirements;
o permit limitations; and
o operator error or catastrophic events such as fires, earthquakes,
explosions, floods, acts of war or terrorism or other similar
occurrences.
Operation below expected capacity levels may result in lost revenues,
increased expenses and penalties. Individual facilities may be unable to meet
operating and financial obligations resulting in reduced cash flow.
If Our Operating Performance or Cash Flow from Minority Interests Falls Below
Projected Levels, We May Not Be Able to Service Our Debt
The risks associated with operating power generation facilities include the
breakdown or failure of equipment or processes, labor disputes and fuel supply
interruption, each of which could result in performance below expected capacity
levels. Operation below expected capacity levels may result in lost revenues,
increased expenses, higher maintenance costs and penalties, in which case there
may not be sufficient cash available to service project debt. In addition, many
of Global's generation projects rely on a single fuel supplier and a single
customer for the purchase of the facility's output under a long term contract.
While Global generally has liquidated damage provisions in its contracts, the
default by a supplier under a fuel contract or a customer under a power purchase
contract could adversely affect the facility's cash generation and ability to
service project debt.
Countries in which Global owns and operates electric and gas distribution
facilities may impose financial penalties if reliability performance standards
are not met. In addition, inefficient operation of the facilities may cause lost
revenue and higher maintenance expenses, in which case there may not be
sufficient cash available to service project debt.
Our ability to control investments in which we own a minority interest is
limited. Assuming a minority ownership role presents additional risks, such as
not having a controlling interest over operations and material financial and
operating matters or the ability to operate the assets more efficiently. As
such, neither we nor Global are able to unilaterally cause dividends or
distributions to be made to us or Global from these operations.
Minority investments may involve risks not otherwise present for
investments made solely by us and our subsidiaries, including the possibility
that a partner, majority investor or co-venturer might become bankrupt, may have
different interests or goals, and may take action contrary to our instructions,
requests, policies or business objectives. Also, if no party has full control,
there could be an impasse on decisions. In addition, certain investments of
Resources are managed by unaffiliated entities which limits Resources' ability
to control the activities or performance of such investments and managers.
Failure to Obtain Adequate and Timely Rate Relief May Have an Adverse Impact
As a public utility, PSE&G's rates are regulated by the BPU and the FERC.
These rates are designed to recover its operating expenses and allow it to earn
a fair return on its rate base, which primarily consists of its property, plant
and equipment less various adjustments. These rates include its electric and gas
tariff rates subject to regulation by the BPU as well as its transmission rates
contained in the PJM Open Access Transmission Tariff subject to regulation by
the 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 every few years. Certain
limited categories of costs, such as societal benefits and gas residential
commodity costs, are recovered through adjustment charges that are periodically
trued-up to actual costs and reset. If these costs exceed the amount included in
PSE&G's adjustment charges, there will be a negative impact on cash flows.
PSE&G's rates for electric transmission are subject to change based on policies
and procedures established by the FERC.
If PSE&G's operating expenses (other than costs recovered through
adjustment charges) exceed the amount included in its base rates or in its FERC
jurisdictional rates, there will be a negative impact on earnings and operating
cash flows.
Certain electric and gas distribution facilities of Global are
rate-regulated enterprises. Rates charged to customers are established by
governmental authorities and are currently sufficient to cover all operating
costs and provide a return. However, in Argentina, we face considerable fiscal
and cash uncertainties, including potential asset impairments, due to the
current economic, political and social crisis. We can give no assurances that
rates will, in the future, be sufficient to cover such costs and provide a
return on Global's investment. In addition, future rates may not be adequate to
provide cash flow to pay principal and interest on Global's subsidiaries' and
affiliates' debt and to enable such subsidiaries and affiliates to comply with
the terms of debt agreements.
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We and Our Subsidiaries are Subject to Substantial Competition From Well
Capitalized Participants in the Worldwide Energy Markets
We and our subsidiaries are subject to substantial competition in the
United States and in international markets from merchant generators, domestic
and multi-national utility generators, fuel supply companies, engineering
companies, equipment manufacturers and affiliates of other industrial companies.
Restructuring of worldwide energy markets, including the privatization of
government-owned utilities and the sale of utility-owned assets, is creating
opportunities for, and substantial competition from, well-capitalized entities
which may adversely affect our ability to make investments on favorable terms
and achieve our growth objectives. Increased competition could contribute to a
reduction in prices offered for power and could result in lower returns which
may affect our ability to service our outstanding indebtedness, including
short-term debt.
Deregulation may continue to accelerate the current trend toward
consolidation among domestic utilities and could also result in the splitting of
vertically-integrated utilities into separate generation, transmission and
distribution businesses. As a result, additional competitors could become active
in the merchant generation business. Resources faces competition from numerous
well-capitalized investment and finance company affiliates of banks, utilities
and industrial companies. Energy Technologies faces substantial competition from
utilities and their affiliates, and HVAC and mechanical contractors.
Our Ability to Service Our Debt Could Be Limited
We are a holding company with no material assets other than the stock of
our subsidiaries and project affiliates. Accordingly, all of our operations are
conducted by our subsidiaries and project affiliates which are separate and
distinct legal entities that have no obligation, contingent or otherwise, to pay
any amounts when due on our debt or to make any funds available to us to pay
such amounts. As a result, our debt will effectively be subordinated to all
existing and future debt, trade creditors, and other liabilities of our
subsidiaries and project affiliates and our rights and hence the rights of our
creditors to participate in any distribution of assets of any such subsidiary or
project affiliate upon its liquidation or reorganization or otherwise would be
subject to the prior claims of such subsidiary's or project affiliate's
creditors, except to the extent that our claims as a creditor of such subsidiary
or project affiliate may be recognized.
We depend on our subsidiaries' and project affiliates' cash flow and our
access to capital in order to service our indebtedness. The project-related debt
agreements of subsidiaries and project affiliates generally restrict their
ability to pay dividends, make cash distributions or otherwise transfer funds to
us. 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.
Our subsidiaries have financed some investments using non-recourse project
level financing. Each non-recourse project financing is structured to be repaid
out of cash flows provided by the investment. In the event of a default under a
financing agreement which is not cured, the lenders would generally have rights
to the related assets. In the event of foreclosure after a default, our
subsidiary may lose its equity in the asset or may not be entitled to any cash
that the asset may generate. Although a default under a project financing
agreement will not cause a default with respect to our debt and that of our
subsidiaries, it may materially affect our ability to service our outstanding
indebtedness.
We can give no assurances that our current and future capital structure,
operating performance or financial condition will permit us to access the
capital markets or to obtain other financing at the times, in the amounts and on
the terms necessary or advisable for us to successfully carry out our business
strategy or to service our indebtedness.
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Power Transmission Facilities May Impact Our Ability to Deliver Our Output to
Customers
If transmission is disrupted, or if transmission capacity is inadequate,
our ability to sell and deliver our electric energy products and grow our
business may be adversely impacted. If a region's power transmission
infrastructure is inadequate, our ability to generate revenues may be limited.
Regulatory Issues Significantly Impact Our Operations
The electric power generation business is subject to substantial regulation
and permitting requirements from federal, state and local authorities. We are
required to comply with numerous laws and regulations and to obtain numerous
governmental permits in order to operate our generation stations.
We believe that we have obtained all material energy-related federal, state
and local approvals including those required by the Nuclear Regulatory
Commission (NRC), currently required to operate our generation stations.
Although not currently required, additional regulatory approvals may be required
in the future due to a change in laws and regulations or for other reasons. No
assurance can be given that we will be able to obtain any required regulatory
approval that we may require in the future, or that we will be able to obtain
any necessary extension in receiving any required regulatory approvals. If we
fail to obtain or comply with any required regulatory approvals, there could be
a material adverse effect on our ability to operate our generation stations or
to sell electricity to third parties.
We are subject to pervasive regulation by the NRC with respect to the
operation of our nuclear generation stations. Such regulation involves testing,
evaluation and modification of all aspects of plant operation in light of NRC
safety and environmental requirements. Continuous demonstrations to the NRC that
plant operations meet applicable requirements are also required. The NRC has the
ultimate authority to determine whether any nuclear generation unit may operate.
We 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 to us or any of our generation stations or that future changes in
laws and regulations will not have a detrimental effect on our business.
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Environmental Regulation May Limit Our Operations
We 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 we believe that we have obtained all
material environmental-related approvals required as of the date hereof to own
and operate our facilities or that such approvals have been applied for and will
be issued in a timely manner, we may incur significant additional costs because
of compliance with these requirements. Failure to comply with environmental
statutes, regulations and ordinances could have a material effect on us,
including potential civil or criminal liability and the imposition of clean-up
liens or fines and expenditures of funds to bring our facilities into
compliance.
We can give no assurance that we will be able to:
o obtain all required environmental approvals that we do not yet have or
that may be required in the future;
o obtain any necessary modifications to existing environmental approvals;
o 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 such environmental approvals, or delay or failure to satisfy any
applicable environmental regulatory requirements, could prevent construction of
new facilities, operation of our existing facilities or sale of energy there
from or could result in significant additional cost to us.
We Are Subject to More Stringent Environmental Regulation than Many of Our
Competitors
Our facilities are subject to both federal and state pollution control
requirements. Most of our generating facilities are located in the State of New
Jersey. In particular, New Jersey's 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.
Insurance Coverage May Not Be Sufficient
We have insurance for our facilities, including all-risk property damage
insurance, commercial general public liability insurance, boiler and machinery
coverage, nuclear liability and, for our nuclear generating units, replacement
power and business interruption insurance in amounts and with deductibles that
we consider appropriate. We can give no assurance that such insurance coverage
will be available in the future on commercially reasonable terms nor that the
insurance proceeds received for any loss of or any damage to any of our
facilities will be sufficient to permit us to continue to make payments on our
debt. Additionally, certain properties that we own may not be insured in the
event of a terrorist activity.
Acquisition, Construction and Development Activities May Not Be Successful
We may seek to acquire, develop and construct new energy projects, the
completion of any of which is subject to substantial risk. Such activity
requires a significant lead time and requires us to expend significant sums for
preliminary engineering, permitting, fuel supply, resource exploration, legal
and other development expenses in preparation for competitive bids or before it
can be established whether a project is economically feasible.
The construction, expansion or refurbishment of a generation, transmission
or distribution facility may involve equipment and material supply
interruptions, labor disputes, unforeseen engineering, environmental and
geological problems and unanticipated cost overruns. The proceeds of any
insurance, vendor warranties or performance guarantees may not be adequate to
cover lost revenues, increased expenses or payments of liquidated damages. In
addition, some power purchase contracts permit the customer to terminate the
related contract, retain security posted by the developer as liquidated damages
or change the payments to be made to the subsidiary or the project affiliate in
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the event certain milestones, such as commencing commercial operation of the
project, are not met by specified dates. If project start-up is delayed and the
customer exercises these rights, the project may be unable to fund principal and
interest payments under its project financing agreements. We can give no
assurance that we will obtain access to the substantial debt and equity capital
required to develop and construct new generation projects or to refinance
existing projects to supply anticipated future demand.
Changes in Technology May Make our Power Generation Assets Less Competitive
A key element of our business plan is that generating power at central
power plants produces electricity at relatively low cost. There are other
technologies that produce electricity, 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, our market share could be eroded and the
value of our power plants could be significantly impaired. Changes in technology
could also alter the channels through which retail electric customers buy
electricity, thereby affecting our financial results.
Recession, Acts of War or Terrorism Could Have an Adverse Impact
Consequences of the September 11, 2001 terrorist attacks on the United
States are difficult to predict. The consequences of a prolonged recession and
market conditions may include the continued uncertainty of energy prices and the
capital and commodity markets. We cannot predict the impact of any continued
economic slowdown or fluctuating energy prices; however, such impact could have
a material adverse effect on its financial condition, results of operations and
net cash flows.
Like other operators of major industrial facilities, our generation plants,
fuel storage facilities and transmission and distribution facilities may be
targets of terrorist activities that could result in disruption of our ability
to produce or distribute some portion of our 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 our
financial condition, results of operation and net cash flows.
COMPETITIVE ENVIRONMENT
The regulatory structure which has historically governed the electric and
gas utility industries in the United States continues to be in transition.
Deregulation is essentially complete in New Jersey and is complete or underway
in certain other states in the Northeast and across the United States. States
have acted independently to deregulate the electric and gas utility industries.
Recent experience in California, with energy shortages, high costs and financial
difficulties of utilities and the Enron bankruptcy have caused some states to
re-evaluate and, in some cases, stop the move toward deregulation. The
deregulation and restructuring of the nation's energy markets, the unbundling of
energy and related services, the diverse strategies within the industry related
to holding, buying or selling generation capacity and the anticipated resulting
industry consolidation have a profound effect on us and our subsidiaries,
providing us with new opportunities and exposing us to new risks (see Risk
Factors and Overview of 2001 and Future Outlook of MD&A).
The National Energy Policy Act of 1992 (Energy Policy Act) laid the
groundwork for competition in the wholesale electricity markets in the United
States. This legislation expanded the FERC's authority to order electric
utilities to open their transmission systems to allow third-party suppliers to
transmit, or "wheel," electricity over their lines. In 1996, FERC issued an
order that resulted in expanded access to transmission lines, providing eligible
third-party wholesale marketers clear transmission access. These actions have
enabled power marketers, merchant generators, Exempt Wholesale Generators (EWGs)
and utilities to compete actively in wholesale energy markets, consumers to have
the right to choose their energy suppliers and competition to set the price of
the generation component of electricity bills in deregulated areas.
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Internationally, many countries continue to privatize their electric and
gas industries. These efforts include selling of government-owned transmission
and distribution and gas assets. In addition, various countries have encouraged
private foreign development of generating facilities.
PSE&G
As a regulated monopoly, PSE&G's electric and gas transmission and
distribution business has minimal risks from competition. Also, there has been
minimal financial impact on PSE&G's transmission and distribution business due
to customers choosing an alternate electric or gas suppliers.
Power
In the regions where Power is the most active, most states have already
begun the process of restructuring their electricity markets. As markets
continue to evolve, several types of competitors have or will emerge in the
markets in which Power participates. These competitors include merchant
generators with or without trading capabilities, other utility affiliates that
have formed generation and/or trading affiliates, aggregators, wholesale power
marketers or combinations thereof. These participants will compete with one
another buying and selling in wholesale power pools, entering into bilateral
contracts and/or selling to aggregated retail customers. Power believes that its
asset size and location, regional market knowledge and integrated functions will
allow it to compete effectively in its selected markets.
Energy Holdings
Energy Holdings and its subsidiaries are subject to substantial competition
in the United States as well as in the international markets from merchant
generators, domestic and multi-national utility generators, fuel supply
companies, energy marketers, engineering companies, equipment manufacturers,
well capitalized investment and finance companies and affiliates of other
industrial companies. Restructuring of worldwide energy markets, including the
privatization of government-owned utilities and the sale of utility-owned
assets, is creating opportunities for Energy Holdings, and likewise is creating
substantial competition from well-capitalized entities which may adversely
affect Energy Holdings' ability to make investments on favorable terms and
achieve its growth objectives.
REGULATORY ISSUES
State Regulation
As a New Jersey public utility, PSE&G has been subject to comprehensive
regulation by the BPU including, among other matters, regulation of intrastate
rates and service and the issuance and sale of securities. As a participant in
the ownership of certain transmission facilities in Pennsylvania, PSE&G is
subject to regulation by the Pennsylvania Public Utility Commission (PPUC) in
limited respects in regard to such facilities. PSEG, Power and Energy Holdings
are not subject to direct regulation by the BPU, except potentially with respect
to certain asset sales, transfers of control, reporting requirements and
affiliate standards.
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PSE&G
New Jersey Energy Master Plan Proceedings, Securitization and Related
Orders
Following the enactment of the Energy Competition Act, the BPU rendered its
Final Order relating to PSE&G's rate unbundling, stranded costs and
restructuring proceedings providing, among other things, for the transfer to an
affiliate of all of PSE&G's electric generation facilities, plant and equipment
for $2.443 billion and all other related property, including materials, supplies
and fuel at the net book value thereof, together with associated rights and
liabilities. PSE&G, pursuant to the Final Order, transferred its electric
generating facilities and wholesale power contracts to Power and its
subsidiaries on August 21, 2000 in exchange for a promissory note from Power in
an amount equal to the purchase price of $2.786 billion. Power paid the
promissory note on January 31, 2001 at which time the transferred assets were
released from the lien of PSE&G's First and Refunding Mortgage (Mortgage).
The Energy Competition Act and the related BPU proceedings, including the
Final Order, referred to as the Energy Master Plan Proceedings, opened the New
Jersey energy markets to competition by allowing all New Jersey retail electric
and gas customers to select their suppliers. For further discussion of the
Energy Master Plan Proceedings, see Note 3. Regulatory Issues and Accounting
Impacts of Deregulation of Notes.
In accordance with the Final Order, PSE&G reduced customer rates by 5% in
August 1999, an additional 2% after the securitization transaction in February
of 2001, another 2% in August 2001, and PSE&G is scheduled to reduce rates 4.9%
in August 2002, for a total 13.9% rate reduction since August 1999. These rate
reductions reduce the market transition charge (MTC) revenues that PSE&G remits
to Power as part of its BGS contract.
BGS Auction
The BPU approved an auction to identify energy suppliers for our obligation
beginning on August 1, 2002. On February 15, 2002 the BPU approved the BGS
auction results and PSE&G secured contracts from a number of suppliers for its
expected peak load of 9,600 MW. Under the BPU approved supply contracts, PSE&G
will pay $.0511 per kWh to obtain electricity for customers for the period from
August 1, 2002 to July 31, 2003. Customers will continue to pay below-market
regulated rates (BGS shopping credit) for this one-year period. Under our
current rate structure, the difference will be deferred and is expected to be
recovered with interest in the future. PSE&G will sell the power it receives
from NUG contracts into the wholesale energy market, which should offset this
underrecovery. PSE&G estimates that the underrecovery relating to the BGS for
the period ending July 31, 2003 will amount to approximately $250 million, with
a net amount of $125 million after factoring in sales of power relating to NUG
contracts.
If a supplier defaults on its obligation to provide energy to PSE&G, the
energy needed for PSE&G to meets its requirements will be purchased at market
prices in accordance with the procedures approved by the BPU. To the extent that
the market prices exceed the auction contract price, the difference will be
deferred and collected from PSE&G customers as provided in the BPU Order
approving the auction process.
Electric Base Rate Case
In accordance with the Final Order, PSE&G is expected to file an electric
base rate case during 2002 that would be effective on August 1, 2003. This case
may impact our earnings and cash flows; however, PSE&G cannot predict the actual
effects at this time.
Affiliate Standards
In February 2000, the BPU approved affiliate standards and fair competition
standards which apply to transactions between a public utility and those of its
affiliates that provide competitive services to retail customers in New Jersey.
In March 2000, the BPU issued a written order (Affiliate Standards) related to
these matters. PSE&G filed a compliance plan in June 2000 to describe the
internal policy and procedures necessary to ensure compliance with such
Affiliate Standards. The BPU has conducted an audit of New Jersey utilities'
competitive activities and compliance with such Affiliate Standards and is
expected to issue an order on the audit in 2002. The
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adoption of Affiliate Standards did not have a material adverse effect on our
financial condition, results of operations or net cash flows.
Gas Unbundling
The Energy Competition Act also required that all customers have the
ability to choose a competitive gas supplier. In 2000, the BPU issued a written
order providing for the unbundling of firm rate schedules into commodity and
transportation components and for changes in existing rate schedules. The new
rates were implemented for all service provided on and after August 1, 2000.
The main features of the gas unbundling are: the development of a Societal
Benefits Clause (SBC) to recover specific costs including, social programs,
Demand Side Management costs (DSM), Remediation Adjustment Clause (RAC) and
consumer education; the development of a Realignment Adjustment Charge to
recover lost revenues incurred by PSE&G (subject to certain criteria) as a
result of customers switching from commodity service to transportation service;
the reallocation of approximately $40 million from transportation rates to
commodity and balancing rates; an incentive of approximately 0.9 cents per therm
for all customers who leave PSE&G to shop with a TPS and an additional incentive
of 1.4 cents per therm for residential customers who leave PSE&G to shop with a
TPS.
Gas Contract Transfer
On August 11, 2000, PSE&G filed a gas merchant restructuring plan with the
BPU. On January 9, 2002, the BPU approved an amended stipulation which
authorized the transfer of PSE&G's gas supply business, including its interstate
capacity, storage and gas supply contracts to ER&T which will, under a
requirements contract, provide gas supply to PSE&G to serve its Basic Gas Supply
Service (BGSS) customers. The transfer is anticipated to take place in April
2002.
The gas contract transfer is expected to reduce volatility in PSE&G's cash
flows. Gas residential commodity costs, are currently recovered through
adjustment charges that are periodically trued-up to actual costs and reset.
After the gas contract transfer, PSE&G will pay ER&T the amount PSE&G charges
its gas distribution customers for the commodity. Industrial and commercial BGSS
customers will be priced under PSE&G's Market Priced Gas Service (MPGS).
Residential BGSS customers will remain under current pricing until April 1,
2004, after which, subject to further BPU approval, those residential gas
customers would also move to MPGS service.
Gas Base Rate Case and Commodity Charges
The BPU has granted PSE&G authority to change the Monthly Pricing Mechanism
(MPM) in its levelized gas adjustment clause (LGAC) to cover currently estimated
gas price increases on a per month basis, exercisable in any month without an
annual limit.
In May 2001, PSE&G filed a petition with the BPU for authority to revise
its gas property depreciation rates (Depreciation Case). In this filing, PSE&G
requested authority to implement its proposed depreciation rates simultaneously
for book purposes and ratemaking purposes when the BPU implements new tariffs
designed to recover the additional annual revenues resulting from the gas base
rate case discussed below.
In May 2001, PSE&G filed a petition with the BPU requesting an increase in
gas base rates of $171 million for gas delivery service (Gas Base Rate Case).
The requested increase was for an overall gas revenue increase of 7.06% to
reflect current costs. PSE&G filed the Gas Base Rate Case because the gas base
rates, in effect since November 1991, did not reasonably reflect capital
investments and other costs required to maintain the gas utility infrastructure.
The BPU consolidated the Depreciation Case and the Gas Base Rate Case.
In November 2001, PSE&G filed and served its 2001 LGAC filing, requesting
approximately a 10% reduction. PSE&G requested that such filing be retained by
the BPU and implemented simultaneously with the order in the Gas
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Base Rate Case. Also in November 2001, PSE&G made a compliance filing with the
BPU to implement an approximate 3% increase through the Gas Cost Underrecovery
Adjustment (GCUA) surcharge effective December 1, 2001. This surcharge is
designed to recover its October 2001 gas underrecovery balance of $130 million.
In January 2002, the BPU issued an order approving the increase.
In January 2002, the BPU issued an order approving a Settlement under which
PSE&G will receive an additional $90 million of gas base rate revenues,
approximately $8 million of which results from gas depreciation rate changes.
This will occur simultaneously with PSE&G's implementation of its previously
approved GCUA surcharge to recover the October 31, 2001 gas cost underrecovery
balance of approximately $130 million over a three-year period with interest and
with PSE&G's reduction of its 2001-2003 Commodity Charges (formerly LGAC) by
approximately $140 million.
The $8 million gas depreciation rate changes are due primarily to the
shortening of the useful lives for general plant and equipment. This adjustment
will have no impact on earnings as it will be offset by increased operating cash
flows in a normal business environment. Assuming current cost levels and a
normal business environment, the $82 million balance of PSE&G's gas base rate
increase will have a positive impact on earnings and operating cash flows. The
settlement set PSE&G's gas rate base at approximately $1.6 billion, its rate of
return on this rate base at 8.27% and its cost of capital or total return on
equity of its gas operations at 10%. As a result of the settlement, PSE&G agreed
not to request another gas base rate increase that would take effect prior to
September 1, 2004.
The $130 million rate increase relating to the GCUA will have no impact on
earnings and will increase operating cash flows in a normal business
environment. The reduction in PSE&G's 2001-2003 commodity charges relates to its
residential customers and will have no impact on earnings and will decrease
operating cash flows assuming current cost levels and a normal business
environment.
Focused Audit
For information regarding the 1992 BPU proceeding concerning the
relationship of PSE&G to our non-utility businesses (Focused Audit), see
Liquidity and Capital Resources of Management's Discussion and Analysis of
Financial Condition and Results of Operations (MD&A).
Federal Regulation
Certain of our subsidiaries' domestic operations are subject to regulation
by FERC with respect to certain matters, including interstate sales and
exchanges of electric transmission, capacity and energy. We have claimed an
exemption from regulation by the Securities and Exchange Commission (SEC) as a
registered holding company under the Public Utility Holding Company Act of 1935
(PUHCA), except for Section 9(a)(2), which relates to the acquisition of 5% or
more of the voting securities of an electric or gas utility company. Fossil and
Nuclear are EWGs and Global's investments include EWGs and foreign utility
companies (FUCOs) under PUHCA. Failure to maintain status of these plants as
EWGs or FUCOs could subject PSEG and its subsidiaries to regulation by the SEC
under PUHCA.
If we were no longer exempt from PUHCA, we and our subsidiaries would be
subject to additional regulation by the SEC with respect to their financing and
investing activities, including the amount and type of non-utility investments.
We believe, however, that this would not have a material adverse effect on us
and our subsidiaries.
PSE&G, Fossil, Nuclear and Global are also subject to the rules and
regulation of the United States Environmental Protection Agency (EPA), U.S.
Department of Transportation (DOT) and U.S. Department of Energy (DOE). For
information on environmental regulation, see Environmental Matters.
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FERC RTO Orders
In December 1999, FERC promulgated a Final Rule (Order 2000) in the
Regional Transmission Organization (RTO) rulemaking proceeding. In October 2000,
PJM and nine PJM transmission owners, including us, made a filing with FERC
stating that PJM is an RTO that meets or exceeds the requirements of Order 2000.
Included in this filing was a PJM rate proposal designed to provide for deferral
recovery of reasonable, risk-adjusted returns on new transmission investments in
the PJM region, an accelerated recovery period for such new investments, and a
rate moratorium of current charges through December 31, 2004.
In July 2001, FERC issued a series of orders that, amongst other things,
rejected the rate design proposal established generation interconnection
proceedings and called for the creation of RTOs to facilitate competitive
regional markets in the U.S. FERC rejected several smaller RTO proposals and
directed transmission owners and independent system operators (ISOs) to combine
into much larger RTOs, dramatically altering their proposed geographic size and
configuration. In August 2001, the PJM transmission owners requested a rehearing
of the PJM RTO Order. The matter is still pending.
In the Northeast region, FERC conditionally approved the PJM RTO proposal
(subject to several modifications and compliance filings) and rejected the New
York ISO and ISO-New England RTO proposals. FERC directed that the three
existing ISOs for PJM, New York and New England, as well as the systems involved
in PJM West, form a single Northeast RTO, based on the "PJM platform" and "best
practices" of all three ISO's. FERC directed that the parties in the region
engage in mediation (with FERC oversight) to prepare a proposal and timetable
for the merger of the ISOs into a single RTO. At the end of the 45-day mediation
period, the Administrative Law Judge assigned to the matter submitted a report
to the Commission with an attached business plan for implementation of the
single northeast RTO possibly as soon as the fourth quarter of 2003.
In the Southeast region, FERC rejected two separate RTO proposals and
directed parties to engage in mediation under the supervision of an
Administrative Law Judge to pursue the goal of creating a single Southeast RTO
using the proposed "Grid South platform." We participated in this discussion.
Another a model for forming a market for the Southeast region continues to
evolve.
In January 2002, PJM and the Midwest ISO announced that they had entered
into negotiations to create a virtual uniform seamless market encompassing their
two RTOs, shortly after the FERC approved the Midwest ISO as an RTO. In
addition, the ISO New England and the New York ISO agreed to jointly develop a
common electricity market and evaluate a New England-New York RTO. The impact of
these developments on us is uncertain because specific rules will not be known
for some time and are subject to FERC approval, which cannot be assured.
FERC has started a series of conferences to discuss the technical issues
related to its consideration of a standard market design - products and
protocols - for wholesale electric power markets. The goal of these conferences
is to gain a mutual understanding of similarities and differences between
various market designs and to allow participants to provide further detail on
market operations. We have been supportive of the incorporation of both capacity
and spot energy markets as part of any standardized market design. The
information from these conferences will be used to issue a formal Notice of
Proposed Rulemaking (NOPR) on a standard market design later this year.
FERC issued an advance notice of proposed rulemaking seeking comments to
help form the basis for a proposed rule to standardize power-plant
interconnection requirements to ease market entry for new generation. FERC also
will, as part of the rulemaking, reconsider its policy addressing how
transmission owners treat the cost of system upgrades necessary to accommodate
new generation, potentially resulting in a new methodology. The ultimate outcome
of this rulemaking and its impact upon us cannot be predicted.
The impact of these developments on us is uncertain because specific rules
will not be known for some time and are subject to FERC approval, which cannot
be assured.
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Nuclear Regulatory Commission (NRC)
Operation of nuclear generating units involves continuous close regulation
by the NRC. Such regulation involves testing, evaluation and modification of all
aspects of plant operation in light of NRC safety and environmental
requirements. Continuous demonstrations to the NRC that plant operations meet
requirements are also necessary. The NRC has the ultimate authority to determine
whether any nuclear generating unit may operate. [Nuclear Regulatory Commission
has issued Orders dated February 25, 2002 to all nuclear power plants to
implement interim compensatory security measures. Some of the requirements
formalize a series of security measures that licensees had taken in response to
advisories issued by the NRC in the aftermath of the September 11 terrorist
attacks. Power has evaluated the Orders for the Salem and Hope Creek facilities
and considers the implementation of the NRC measures to be without adverse
material consequence to the NRC operating license or business interests.
In accordance with NRC requirements, nuclear plants utilize various fire
barrier systems to protect equipment necessary for the safe shutdown of the
plant in the event of a fire. The NRC has identified certain issues at Salem and
Power is in the process of making the necessary modifications to comply with
these requirements, the cost of which are not expected to be material. Failure
to resolve fire barrier issues could result in potential NRC violations, fines
and/or plant shutdown which could have a material adverse impact to our
financial condition, results of operations and net cash flows.
Exelon has informed Power that on July 3, 2001 an application was submitted
to the NRC to renew the operating licenses for Peach Bottom Units 2 and 3. If
approved, the current licenses would be extended by 20 years, to 2033 and 2034
for Units 2 and 3 respectively. NRC review of the application is expected to
take approximately two years.
For certain litigation relating to Salem, see Item 3. Legal Proceedings.
For discussion of the renewal of New Jersey Pollutant Discharge Elimination
System (NJPDES) permit related to Salem and its operations, see Environmental
Matters - Water Pollution Control.
Other Regulatory Issues
Tax Sharing Agreement
The issue of our sharing the benefits of consolidated tax savings with
PSE&G or its customers was addressed by the BPU in 1995 in a letter which
informed PSE&G that the issue of consolidated tax savings can be discussed in
the context of a future base rate case or plan for an alternative form of
regulation. We believe that PSE&G's taxes should be treated on a stand-alone
basis for rate making purposes, based on the separate nature of the utility and
non-utility businesses. Neither we nor PSE&G is able to predict what action, if
any, the BPU may take concerning consolidated tax savings in future proceedings.
International
Energy Holdings' foreign subsidiaries generally are subject to regulation
in the countries in which they operate. Global's electric and gas distribution
facilities in South America are rate-regulated enterprises. Rates charged to
customers are established by governmental authorities and are currently
sufficient to cover all operating costs and provide a risk adjusted fair return,
except in Argentina. See Note 9. Commitments and Contingent Liabilities and Note
18. Subsequent Events of Notes. Energy Holdings can give no assurances that
future rates will be established at levels sufficient to cover such costs,
provide a return on its investment or generate adequate cash flow to pay
principal and interest on its debt or to enable it to comply with the terms of
debt agreements. Global's South American facilities are also subject to quality
of service standards. Global intends to manage its capital improvement budgets
within these quality of service standards. Failure to meet required standards
could result in penalties which are not expected to have a material adverse
impact on these investments, although no assurances can be given.
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CUSTOMERS
PSE&G
As of December 31, 2001, PSE&G provided service to approximately 2.0
million electric customers and approximately 1.6 million gas customers. PSE&G's
service territory contains a diversified mix of commerce and industry, including
major facilities of many corporations of national prominence. PSE&G's load
requirements are almost evenly split among residential, commercial and
industrial customers.
Power
Pursuant to the BGS contract, PSE&G will be the primary customer for
Power's generation business through July 31, 2002. PSE&G, under the terms of the
Final Order, is required to provide basic generation service to all retail
customers in its service area that either do not choose to buy their power from
alternative suppliers or are not being served by their alternative energy
supplier for any reason. PSE&G will pay Power the full amount charged to BGS
customers, or the retail tariff rate on file at the BPU, less any sales and use
taxes. In addition, PSE&G pays Power a price stability charge to compensate them
for ensuring the reliability of BGS service and minimizing PSE&G's exposure to
price volatility risk. The charge is equal to the full amount collected by PSE&G
for its unsecuritized generation stranded costs per billing period, also known
as a Market Transition Charge (MTC). As of December 31, 2001, PSE&G provided
service to approximately 99% of its traditional load. For the year ended
December 31, 2001, Power's electric operating revenues associated with this
customer base aggregated approximately $1.8 billion. PSE&G's peak load during
the summer of 2001 was 10,425 MW.
Power has entered into one-year contracts commencing August 1, 2002 with
various direct bidders in the New Jersey BGS Auction, which was approved by the
BPU on February 15, 2002. Power believes that its obligations under these
contracts are reasonably balanced by its available supply.
Power continues to supply certain municipal and electric cooperative
customers and one public utility a total of 489 MW of capacity, including some
other obligations, such as energy, under the terms of existing contracts for the
remaining one to five years of those contracts.
Wholesale energy and related product trading have been growing business
opportunities throughout the Super Region over the last ten years and we have
been in the forefront as an active participant. Trading relationships have been
developed with most of the larger and more successful power marketers and
existing trading relationships have been strengthened with the region's
utilities. More recently, new relationships have developed with companies that
are focused on aggregating retail customers in states that have deregulated.
Power currently has over 100 active trading counterparties, which have passed a
rigorous credit analysis and contracting process. These include investor owned
utilities, retail aggregators and marketers.
For a discussion of Power's future strategy and the auction impact, refer
to Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations. Additionally, for risks associated with Power's new
counterparties, as a result of the auction, see Risk Factors discussed above.
Energy Holdings
Global
Global has ownership interests in eight distribution companies which serve
approximately 3.6 million customers and has developed or acquired interests in
electric generation facilities which sell energy, capacity and ancillary
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services to numerous customers through power purchase agreements (PPAs) as well
as into the wholesale market. For additional information on distribution
customers, see Item 2. Properties-Electric Distribution Facilities.
Energy Technologies
Energy Technologies currently provides services to approximately 8,500
customers.
EMPLOYEE RELATIONS
PSEG has no employees. As of December 31, 2001, PSE&G had 6,554 employees,
Power had 3,143 employees, Energy Holdings had 2,590 employees, and Services had
1,104 employees. PSE&G has a three-year collective bargaining agreement in place
with three of its union groups, covering 3,636 employees, which expires on April
30, 2005. PSE&G also has a collective bargaining agreement with the Utility
Co-Workers Association, covering 1,397 employees, that expires on April 30, 2002
and plans to negotiate a new agreement, which cannot be assured. Power has
collective bargaining agreements, which expire on April 30, 2005, in place with
three union groups, representing 1,597 employees (774 employees, or
approximately 80% of the workforce in Fossil and 823 employees, or approximately
45% of the workforce in Nuclear). Energy Technologies and its operating
subsidiaries are party to agreements with various trade unions through
multi-employer associations. PSE&G, Power, Services and Energy Holdings believe
that they maintain satisfactory relationships with their employees.
For information concerning employee pension plans and other postretirement
benefits, see Note 12. Pension, Other Postretirement Benefit and Savings Plans
of Notes.
SEGMENT INFORMATION
Financial information with respect to our business segments is set forth in
Note 14. Financial Information by Business Segments of Notes.
ENVIRONMENTAL MATTERS
Federal, regional, state and local authorities regulate the environmental
impacts of our operations. Areas of regulation include air quality, water
quality, site remediation, land use, waste disposal, aesthetics and other
matters.
Compliance with environmental requirements has caused us and our
subsidiaries to modify the day-to-day operation of our facilities, to
participate in the cleanup of various properties that have been contaminated and
to modify, supplement and replace existing equipment and facilities. During
2001, PSE&G and Power expended approximately $18 million for capital related
expenditures to improve the environment and comply with laws and regulations and
estimates that they will expend approximately $61 million, $76 million and $37
million in the years 2002 through 2004, respectively, including such amounts
discussed in the PSD/New Source Review section below.
Air Pollution Control
Federal air pollution laws (such as the Federal Clean Air Act (CAA) and the
regulations implementing those laws, require controls of emissions from sources
of air pollution, and also impose record keeping, reporting and permit
requirements. Facilities that Power operates or in which it has 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 2004 are included in our estimate of construction
expenditures in MD&A.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In November 1999, the federal government announced the filing of lawsuits
by several states against seven companies operating power plants in the Midwest
and Southeast, charging that 32 coal-fired plants in ten states violated the
PSD/NSR requirements of the CAA. Generally, these regulations 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. Various environmental and
public interest organizations have given notice of their intent to file similar
lawsuits. The Federal government is seeking to order these companies to install
the best available air pollution control technology at the affected plants and
to pay monetary penalties of up to $27,500 for each day of continued violation.
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The EPA and the New Jersey Department of Environmental Protection (NJDEP)
issued a demand in March 2000 under section 114 of the CAA requiring information
to assess whether projects completed since 1978 at the Hudson and Mercer coal
burning units were implemented in accordance with applicable PSD/NSR
regulations. Power completed its response to the section 114 information request
in November 2000. In January 2002, Power reached an agreement with the state and
federal governments to resolve allegations of noncompliance with federal and
State of New Jersey PSD/NSR regulations. Under that agreement, over the course
of 10 years Power will install advanced air pollution controls that will
dramatically reduce emissions of nitrogen oxides (NOx), sulfur dioxides (SO2),
particulate matter, and mercury from the Hudson and Mercer coal units. The
estimated cost of the program is $337 million to be incurred through 2011. Power
also will pay a $1.4 million civil penalty and spend up to $6 million on
supplemental environmental projects. Capital costs of complying with these and
other air pollution control requirements through 2004 are included in our
estimate of construction expenditures (see Capital Requirements of MD&A). The
agreement is still subject to public comment and judicial approval as to which
no assurances can be given.
As noted below, future environmental initiatives are expected to require
reduced emissions of NOx, SO2, mercury, and possibly CO2 from electric
generating facilities. The emission reductions to be achieved at the Hudson and
Mercer coal units are expected to assist in complying with such future
requirements.
In 2001, the EPA indicated that it was considering enforcement action under
its PSD rules relating to the construction of Bergen 2, scheduled for operation
in 2002. The EPA maintained that PSD requirements were applicable to Bergen 2,
thereby requiring Fossil to obtain a permit before beginning actual on-site
construction. The agreement resolving the NSR allegations concerning the Hudson
and Mercer coal-fired units also resolved the dispute over Bergen 2, and allowed
construction of the unit to be completed and operation to commence.
Sulfur Dioxide/Nitrogen Oxide
To reduce emissions of SO2, 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 needing to cover
emissions above their allocations can buy allowances from sources that have
excess allowances. Similarly, to reduce emissions of NOx, which contribute to
the formation of smog, Northeastern states and the District of Columbia have set
a cap on total emissions of NOx from affected units, and allocated NOx
allowances (with each allowance authorizing the emission of one ton of NOx) to
those units. The cap applies from May through September, a period commonly
referred to as the "ozone season." The NOx allowances can be bought and sold
through a regional trading program similar to the trading of SO2 allowances. In
2003, the cap will be reduced to limit NOx emissions further.
In 1998, the EPA issued regulations (commonly known as the SIP Call)
requiring the 22 states in the eastern half of the United States to make
significant NOx emission reductions by 2003 and to subsequently cap these
emissions. In January 2000, the EPA adopted a revised rule granting petitions
filed by certain northeastern states under Section 126 of the CAA. The petitions
sought significant reductions in nitrogen oxide emissions from utility and
industrial sources. The rule imposes emission reduction requirements comparable
to the NOx SIP Call Rule. The EPA has delayed the implementation of the SIP Call
and the Section 126 Rule until May 31, 2004. The NOx reduction requirements of
the SIP Call and the Section 126 rule are consistent with requirements already
in place in New Jersey, New York and Pennsylvania, and therefore are not likely
to have an additional impact on or change the
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capacity available from our existing facilities. New facilities that Power is
developing in Ohio and Indiana will be subject to rules that those states are
expected to promulgate to comply with the SIP Call.
To comply with the SO2 and NOx requirements, affected units may choose one
or more strategies, including installing air pollution control technologies,
changing or limiting operations, changing fuels or obtaining additional
allowances. At this time, Power does not expect to incur material expenditures
to continue complying with the SO2 program. Power also does not expect that the
potential costs for purchasing additional NOx allowances will be material
through December 31, 2002. In 2003, when the NOx cap is reduced in New Jersey,
New York, Pennsylvania, and other Northeastern states, the cost of complying
with the NOx program in those states may increase significantly. Whether the
cost will increase or decrease will depend upon whether Power will be a net
purchaser or seller of NOx allowances. The extent of any increase or decrease
will depend upon a number of factors that may increase or decrease total NOx
emissions from affected units, thus increasing or decreasing demand for a fixed
supply of allowances. Power has been implementing measures to reduce NOx
emissions at several of its units, which will reduce the cost of purchasing
allowances.
In December 1999, the EPA proposed to approve plans by several states
(including New Jersey and certain other Northern states) to attain the ozone
National Ambient Air Quality Standards. That approval is contingent on these
states implementing new programs to further reduce emissions of smog-forming
chemicals (including NOx). The affected Northeastern states have committed to
make these reductions, and were required to have selected measures by October 1,
2001 to achieve the reductions. Measures selected by the states are currently
under EPA review. Measures under consideration may increase demand for NOx
allowances and, consequently, increase their prices.
In 1997, the EPA adopted a new air quality standard for fine particulate
matter, and a revised air quality standard for ozone. To attain the fine
particulate matter standard, states may require further reductions in NOx and
SO2. However, under the time schedule announced by the EPA when the new standard
was adopted, non-attainment areas will not be designated until 2002 and control
measures to meet this standard will not be identified until 2005. Additionally,
similar NOx and SO2 reductions may be required to satisfy requirements of an EPA
rule protecting visibility in many of the nation's scenic areas, including some
areas near our facilities. States or the federal government may require
additional reductions in NOx emissions from electric generating facilities as
part of an effort to achieve the revised ozone standard.
Other Air Pollutants
The CAA directed the EPA to study potential public health impacts of
hazardous air pollutants (HAPs) emitted from electric utility steam generating
units. In December 2000, the EPA announced its intent to regulate HAP emissions
from coal-fired and oil-fired steam units, concluding that these emissions pose
significant hazards to public health. EPA plans to develop "Maximum Achievable
Control Technology" (MACT) standards for these units. The EPA plans to propose
the MACT standards by December 2003 and promulgate a final rule by December
2004, with compliance to be required by December 2007.
In December 1997, delegates from the U.S. and 166 other nations agreed to a
treaty known as the Kyoto Protocol. If the U.S. were to ratify the treaty, it
would be bound to reduce emissions of CO2 and certain other "greenhouse gases"
by 7% below 1990 levels. However, in March 2001, President Bush announced that
the United States would not ratify the treaty. On January 11, 2002, Power
announced a voluntary agreement that calls for a goal of reducing by December
31, 2005 the annual average carbon dioxide emission rate of its fossil fuel
fired electric generating units by 15% below the 1990 average annual carbon
dioxide emission rate of its New Jersey fossil fuel fired electric generating
units. Fossil also has agreed to make a $1.5 million grant to the NJDEP to
assist in the development of landfill gas projects, and to make an additional
grant equal to $1 per ton of CO2 emitted greater than the 15% goal, up to $1.5
million, if that reduction is not achieved.
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Water Pollution Control
The Federal Water Pollution Control Act (FWPCA) prohibits the discharge of
pollutants to waters of the United States from point sources, except pursuant to
a National Pollutant Discharge Elimination System (NPDES) permit issued by 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. 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. We also have
ownership interests in domestic and international facilities in jurisdictions
that have their own laws and implementing regulations to regulate discharges to
their surface waters and ground waters that directly regulate our facilities in
these jurisdictions.
The EPA is conducting a rulemaking 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 became effective on January 17, 2002. None of the projects that Power
currently has under construction are subject to the Phase I rule.
The EPA is scheduled to propose draft Phase II rules covering large
existing power plants on February 28, 2002, and issue final rules on August 28,
2003. The content of the final Phase II rules cannot be predicted at this time,
although it is reasonable to expect that the rule will apply to all of Power's
steam electric and combined cycle units that use surface waters for cooling
purposes. If the Phase II rules require retrofitting of cooling water intake
structures at our existing facilities, the cost of complying with the rules
would be material and could require certain of the facilities to be closed.
On June 29, 2001, the NJDEP issued a renewal permit (the 2001 Permit) for
Salem, with an effective date of August 1, 2001, allowing for the continued
operation of Salem with its existing cooling water system. This 2001 Permit
renews Salem's variance from applicable thermal water quality standards under
Section 316(a) of the FWPCA, determines that the existing intake structure
represents best technology available under Section 316(b) of the FWPCA, requires
that Power continue to implement the wetlands restoration and fish ladder
programs established under the 1994 NJPDES Permit issued for Salem, and imposes
requirements for additional analyses of data and studies to determine if other
intake technologies are available for application at Salem that are biologically
effective. The 2001 Permit also requires us to install up to two additional fish
ladders in New Jersey and fund a $500,000 escrow account for the construction of
artificial reefs by NJDEP. The 2001 Permit expires on July 31, 2006.
Power has also reached a settlement with the Delaware Department of Natural
Resources and Environmental Control (DNREC) providing that Nuclear will fund
additional habitat restoration and enhancement activities as well as fisheries
monitoring and that Power and DNREC will work cooperatively on the finalization
of other regulatory approvals required for implementation of the 2001 Permit. As
part of this agreement, Power deposited approximately $5.8 million into an
escrow account to be used for future costs related to this settlement.
In 1970, the Delaware River Basin Commission (the DRBC) had issued a Docket
for Salem (1970 Docket) that approved the construction and operation of the
station's cooling water system. In 1995, the DRBC had issued a Revised Docket
for Salem (1995 Revised Docket) that amended the Heat Dissipation Area (HDA)
established in the 1970 Docket, and approved the continued operation of the
station's cooling water system. At its meeting on September 13, 2001, the DRBC
unanimously approved our request for revisions to the 1995 Revised Docket. The
Docket, as revised, provides for an HDA consistent with the hydrothermal
modeling studies conducted in connection with the renewal application for
Salem's NJPDES permit, incorporates by reference the terms and conditions of the
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2001 Permit, rescinds the 1995 Revised Docket, and establishes a twenty-five
year term for the Docket. The newly revised Docket again includes a re-opener
clause that allows the DRBC to re-consider the terms and conditions of the
Docket, based upon changed circumstances.
Capital costs of complying with water pollution control requirements
through 2004 are included in our estimate of construction expenditures in MD&A.
Hudson and Mercer Generation Stations
The NJDEP is in the process of reviewing the NJPDES permit renewal
application for our Hudson Station. As part of that renewal, the NJDEP has
requested updated information, in part to address issues identified by a
consultant hired by NJDEP. The consultant recommended that Hudson Station be
retrofitted to operate with closed cycle cooling to address alleged adverse
impacts associated with the thermal discharge and intake structure. Power
proposed certain modifications to the intake structure and submitted these
demonstrations to NJDEP in the fourth quarter of 1998. Power believes that these
demonstrations address the issues identified by the NJDEP's consultant and
provide an adequate basis for favorable determinations under the FWPCA without
the imposition of closed cycle cooling, although no assurances can be given.
The NJDEP has advised us that it is reviewing a NJPDES permit renewal
application for Mercer Station, and in connection with that renewal, will be
reexamining the effects of Mercer Station's cooling water system pursuant to
FWPCA. Power has submitted updated demonstrations to the NJDEP.
It is impossible to predict the timing and/or outcome of the review of
these applications in respect of the Hudson and Mercer Generation Stations. An
unfavorable outcome could have a material adverse effect on our financial
position, results of operations and net cash flows. Power believes that the
current operations of its stations are in compliance with FWPCA and will
vigorously prosecute our applications to continue operations of its generating
stations with present cooling water intake structures.
Control of Hazardous Substances
PSE&G Manufactured Gas Plant Remediation Program
For information regarding PSE&G's Manufactured Gas Plant Remediation
Program, see Note 9. Commitments and Contingent Liabilities of Notes.
Hazardous Substances
Generators of hazardous substances potentially face joint and several
liability, without regard to fault, when they fail to manage these materials
properly and when they are required to clean up property affected by the
production and discharge of such substances. Certain Federal and state laws
authorize the EPA and the NJDEP, among other agencies, to issue orders and bring
enforcement actions to compel responsible parties to investigate and take
remedial actions at any site that is determined to present an actual or
potential threat to human health or the environment because of an actual or
threatened release of one or more hazardous substances. Because of the nature of
PSE&G's and Power's businesses, including the production 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 9. Commitments and
Contingent Liabilities. For a discussion of remediation/clean-up actions
involving PSE&G and Power, see Item 3. Legal Proceedings.
Other liabilities associated with environmental remediation include natural
resource damages. The Federal Comprehensive Environmental Response, Compensation
and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and
Control Act (Spill Act) authorize Federal and state trustees for natural
resources to assess
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"damages" against persons who have discharged a hazardous substance, which
discharge resulted in an "injury" to natural resources. Until recently, the
State trustee, NJDEP, has not aggressively pursued natural resource damages. In
1997, the NJDEP adopted changes to the Technical Requirements for Site
Remediation pursuant to the Spill Act. Among these changes was a new provision
requiring all persons conducting remediation to characterize "injuries" to
natural resources. Further, these changes required persons to address those
injuries through restoration or damages. Power cannot assess the magnitude of
the potential impact of this regulatory change. Although not currently
estimable, these costs could be material.
A preliminary review of possible mercury contamination at the Kearny
Station, concluded that an additional study and investigations are required. A
Remedial Investigation (RI) was conducted and a report was submitted to the
NJDEP in 1997. This report is currently under technical review. As currently
issued, the RI Report found that the mercury at the site is stable and immobile
and should be addressed at the time the Kearny Station is retired.
The EPA has determined that a six mile stretch of the Passaic River in the
area of Newark, New Jersey is a facility within the meaning of that term under
the CERCLA and that, to date, at least thirteen corporations, including PSE&G
and Power, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the Passaic River facility. Power
has one plant and PSE&G has one former electric plant and four former
manufactured gas plants within the Passaic River "facility". We cannot predict
what action, if any, the EPA or any third party may take against them with
respect to these matters, or in such event, what costs Power or PSE&G may incur
to address any such claims. However, such costs may be material.
The EPA conducted an inspection of Spill Prevention Control and
Countermeasure (SPCC) Plan compliance at three of PSE&G's substation facilities
in 1997. The EPA identified certain procedural and substantive deficiencies in
the SPCC Plans for these sites. PSE&G has submitted revised SPCC Plans to the
EPA for these sites and is currently working with the EPA to finalize these SPCC
Plans. In 1998, PSE&G evaluated SPCC Plan compliance at all of SPCC substations
and identified deficiencies. The necessary upgrades are now in the process of
being made. It is anticipated that these upgrades will take several years to
complete.
Nuclear Fuel Disposal
After spent fuel is removed from a nuclear reactor, it is placed in
temporary storage for cooling in a spent fuel pool at the nuclear station site.
Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal
government has entered into contracts with the operators of nuclear power plants
for transportation and ultimate disposal of the spent fuel To pay for this
service, the nuclear plant operators were required to contribute to a Nuclear
Waste Fund at a rate of one mil per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal
government. These costs are being recovered through the BGS contract through
July 2002. In addition, a one-time payment was made to the DOE for permanently
discharged spent fuels irradiated prior to 1983. Payments made to the United
States Department of Energy (DOE) for disposal costs are based on nuclear
generation and are included in Energy Costs in the Consolidated Statements of
Income.
Under the NWPA, the DOE was required to begin taking possession of all
spent nuclear fuel generated by the Power's nuclear units for disposal by no
later than 1998. DOE construction of a permanent disposal facility has not begun
and DOE has announced that it does not expect a facility to be available earlier
than 2010. In February 2002, President Bush announced that Yucca Mountain in
Nevada was designated as the permanent disposal facility for nuclear wastes. The
states have thirty days to object, and, if objections are raised, the issue will
be determined by the U.S. Congress. No assurances can be given as to the final
outcome of this matter.
Exelon has advised Power that it had signed an agreement with the DOE
applicable to Peach Bottom under which Exelon would be reimbursed for costs
resulting from the DOE's delay in accepting spent nuclear fuel. The agreement
allows Exelon to reduce the charges paid to the Nuclear Waste Fund to reflect
costs reasonably incurred due to the DOE's delay. Past and future expenditures
associated with Peach Bottom's recently completed on-site dry storage facility
would be eligible for this reduction in future DOE fees. In 2000, a group of
eight utilities filed a petition against DOE in the Eleventh Circuit U.S. Court
of Appeals seeking to set aside the receipt of credits out of the Nuclear Waste
Fund, as stipulated in the Peach Bottom agreement. On September 26, 2001 Nuclear
filed a complaint in the U. S. Court of Federal Claims seeking damages caused by
the DOE not taking possession of spent nuclear fuel in 1998. No assurances can
be given as to any damage recovery or the ultimate availability of a disposal
facility.
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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 reactor 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). The availability of adequate spent fuel
storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and
2007 for Hope Creek. Power presently expects to construct an on-site storage
facility that would satisfy the spent fuel storage needs of both Salem and Hope
Creek through the end of the license life. This construction will require
certain regulatory approvals, the timely receipt of which cannot be assured.
Exelon has advised Power that it has constructed an on-site dry storage facility
at Peach Bottom that is now licensed and operational and can provide storage
capacity through the end of the current licenses for the two Peach Bottom units.
On July 3, 2001 an application was submitted to the NRC to renew the operating
licenses for Peach Bottom Units 2 and 3. If approved, the current licenses would
be extended by 20 years, to 2033 and 2034 for Units 2 and 3 respectively. NRC
review of the application is expected to take approximately two years.
In October 2001, Nuclear filed a complaint in the United States Court of
Federal Claims, along with a number of other plaintiffs, seeking $28.2 million
in relief from past overcharges by the DOE for enrichment services. No
assurances can be given as to any claimed damage recovery.
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. In 2000, New Jersey,
Connecticut and South Carolina formed the Atlantic Compact. This arrangement
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 Peach
Bottom, Salem and Hope Creek which have the capacity for at least five years of
temporary storage for each facility.
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with the Energy Policy Act (EPAct), 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 is $79 million
(adjusted for inflation). As of December 31, 2001, $48 million has been paid,
resulting in a balance due of $31 million. PSE&G and Power believe that they
should not be subject to collection of any such fund payments under the EPAct.
Along with a number of other nuclear generator owners, Power and PSE&G have
filed suit in the U.S. Court of Claims and in the U.S. District Court, Southern
District of NY to recover these costs.
ITEM 2. PROPERTIES
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.
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The electric lines and gas mains of PSE&G 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 rights are deemed by PSE&G to be adequate for the purposes for
which they are being used.
PSE&G believes that it maintains 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, 2001, PSE&G's transmission and distribution system
included approximately 21,760 circuit miles, of which approximately 6,363 miles
were underground, and approximately 836,068 poles, of which approximately
536,780 poles were jointly owned. Approximately 99% of this property is located
in New Jersey.
In addition, as of December 31, 2001, PSE&G owned five electric
distribution headquarters and four subheadquarters in four operating divisions,
all located in New Jersey.
Gas Distribution Properties
As of December 31, 2001, 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:
Daily Capacity
Plant Location (Therms)
------------------------------- ------------------ --------------
Burlington LNG................. Burlington, NJ 773,000
Camden LPG..................... Camden, NJ 280,000
Central LPG.................... Edison Twp., NJ 960,000
Harrison LPG................... Harrison, NJ 960,000
--------------
Total.................... 2,973,000
As of December 31, 2001, PSE&G owned and operated approximately 16,888
miles of gas mains, owned 11 gas distribution headquarters and two
subheadquarters all in two operating regions located in New Jersey and owned one
meter shop in New Jersey serving all such areas. In addition, PSE&G operated 61
natural gas metering or regulating stations, all located in New Jersey, of which
28 were located on land owned by customers or natural gas pipeline companies
supplying PSE&G with natural gas and were operated under lease, easement or
other similar arrangement. In some instances, the pipeline companies owned
portions of the metering and regulating facilities.
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Office Buildings and Facilities
PSE&G leases substantially all of a 26-story office tower for its corporate
headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining
three-story building. PSE&G also leases other 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, 2001,
PSE&G owned 39 switching stations in New Jersey with an aggregate installed
capacity of 30,417,670 kilovolt-amperes and 249 substations with an aggregate
installed capacity of 7,446,000 kilovolt-amperes. In addition, six substations
in New Jersey having an aggregate installed capacity of 108,000 kilovolt-amperes
were operated on leased property.
Power
Power subleases approximately 148,000 square feet of office space from
PSE&G in Newark, New Jersey. Other leased properties include an emergency media
center (9,300 square feet) near Salem which is designed as an information
clearinghouse in the event of a nuclear emergency. It also leases approximately
19,600 square feet of space in the Hadley Road Training Center in South
Plainfield, New Jersey from PSE&G. This space is used for fossil fuel
procurement and materials management staff.
Power owns a 57.41% interest in about 12,000 acres of restored wetlands and
conservation facilities in the Delaware Estuary. This subsidiary was formed to
acquire and own lands and other conservation facilities required to satisfy the
condition of the NJPDES permit issued for the Salem Generating Station. Power
also owns several other facilities including the on-site Nuclear Administration
and Processing Center buildings.
Power has an ownership interest in the 650-acre Merrill Creek Reservoir in
Warren County, New Jersey. 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 entities that have generation facilities along the
Delaware River and use the river water in their operations. Power also owns the
Maplewood Test Center in Maplewood, New Jersey and the Central Maintenance Shop
at Sewaren, New Jersey.
Power believes that it maintains insurance coverage against loss or damage
to its principal 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 Risk Factors and
Note 9. Commitments and Contingent Liabilities of Notes.
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As of December 31, 2001, Power's share of installed generating capacity was
11,487 MW, as shown in the following table:
Total Owned Principal
Capacity Capacity Fuels
Name and Location (MW) (MW) Used Mission
- ------------------------------------------------------------ -------- -------- --------- --------------
Steam:
Hudson, Jersey City, NJ............................... 991 991 Coal/Gas Load Following
Mercer, Hamilton, NJ.................................. 648 648 Coal/Gas Load Following
Sewaren, Woodbridge Twp., NJ.......................... 453 453 Gas/Oil Load Following
Linden, Linden, NJ (F)................................ 430 430 Oil Load Following
Keystone, Shelocta, PA--22.84%(A)(B)................... 1,700 388 Coal Base Load
Conemaugh, New Florence, PA--22.50%(A)(B).............. 1,700 382 Coal Base Load
Kearny, Kearny, NJ.................................... 300 300 Oil Load Following
Albany, Albany, NY (F)................................ 380 380 Oil Load Following
----------- -----------
Total Steam........................... 6,602 3,972
----------- -----------
Nuclear: (Capacity calculated in accordance with industry
maximum dependable capability standards)
Hope Creek, Lower Alloways Creek, NJ ................. 1,049 1,049 Nuclear Base Load
Salem 1 & 2, Lower Alloways Creek, NJ 57.41%(A)....... 2,188 1,275 Nuclear Base Load
Peach Bottom 2 & 3, Peach Bottom, PA 50%(A)(C)........ 2,186 1,094 Nuclear Base Load
----------- -----------
Total Nuclear...................................... 5,423 3,418
----------- -----------
Combined Cycle:
Bergen, Ridgefield, NJ................................ 675 675 Gas Load Following
Burlington, Burlington, NJ............................ 245 245 Gas Load Following
----------- -----------
Total Combined Cycle............................... 920 920
----------- -----------
Combustion Turbine:
Essex, Newark, NJ..................................... 617 617 Gas/Oil Peaking
Edison, Edison Township, NJ........................... 504 504 Gas/Oil Peaking
Kearny, Kearny, NJ (F)................................ 443 443 Gas/Oil Peaking
Burlington, Burlington, NJ............................ 561 557 Oil Peaking
Linden, Linden, NJ.................................... 316 316 Gas/Oil Peaking
Hudson, Jersey City, NJ............................... 129 129 Oil Peaking
Mercer, Hamilton, NJ.................................. 129 129 Oil Peaking
Sewaren, Woodbridge Township, NJ...................... 129 129 Oil Peaking
Bayonne, Bayonne, NJ.................................. 42 42 Oil Peaking
Bergen, Ridgefield, NJ................................ 21 21 Gas Peaking
National Park, National Park, NJ...................... 21 21 Oil Peaking
Kearny, Kearny, NJ.................................... 21 21 Gas Peaking
Linden, Linden, NJ.................................... 21 21 Gas/Oil Peaking
Salem, Lower Alloways Creek, NJ 50%(A)................ 38 22 Oil Peaking
----------- -----------
Total Combustion Turbine........................... 2,992 2,972
----------- -----------
Internal Combustion:
Conemaugh, New Florence, PA--22.50%(A)(B).............. 11 2 Oil Peaking
Keystone, Shelocta, PA--22.84%(A)(B)................... 11 3 Oil Peaking
----------- -----------
Total Internal Combustion.......................... 22 5
----------- -----------
Pumped Storage:
Yards Creek, Blairstown, NJ--50%(A)(D)(E)...... 400 200 Peaking
----------- -----------
Total Operating Generation Plants.................. 16,359 11,487
=========== ===========
(A) Power's share of jointly owned facility.
(B) Operated by Reliant Energy
(C) Operated by Exelon
(D) Operated by Jersey Central Power & Light
(E) Excludes energy for pumping and
synchronous condensers.
(F) These assets are scheduled for retirement within the next five years,
partially dependent upon new generation going into service discussed below.
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As of December 31, 2001, Power had 3,830 MW of generating capacity in
construction, as shown in the following table:
POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT
As of December 31, 2001
Total Principal
Capacity Fuels Expected in
Name and Location (MW) Used Missions Service Date
- ---------------------------------------------------------- ----------- ------------- ----------------- ------------
Single Cycle:
Waterford (Phase I), Ohio (June 2002)............. 500 Gas Load Following June 2002
Combined Cycle:
Bergen, Ridgefield, NJ (June 2002).............. 546 Gas Load Following June 2002
Lawrenceburg, Indiana (May 2003)................ 1,150 Gas Load Following May 2003
Waterford (Phase II), Ohio (May 2003)........... 350 Gas Load Following May 2003
Linden, Linden, NJ (June 2003).................. 1,218 Gas Load Following June 2003
-----------
Total Construction............................. 3,764
===========
As of December 31, 2001, Power had 900 MW of generating capacity in advanced
development, as shown in the following table:
Total Principal
Capacity Fuels Expected in
Name and Location (MW) Used Missions Service Date
- --------------------------------------------------------- -------- --------- ---------------- ------------
Combined Cycle:
Bethlehem, NY (June 2004)....................... 750 Gas/Oil Load Following June 2004
Nuclear Uprates...................................... 150 Nuclear Base Load Various
-----------
Total Advanced Development................... 900
-----------
Total Capacity
Projected Capacity (mw)
- ----------------------------------------------------------------------------
Total Owned Operating Generating Plants 11,487
Under Construction 3,764
Advanced Development 900
Less: Planned Retirements (1,253)
----------------
Projected Capacity 14,898
================
Energy Holdings
Energy Holdings does not own any real property. Energy Holdings subleases
office space for its corporate headquarters at 80 Park Plaza, Newark, New Jersey
from PSE&G. Energy Holdings' subsidiaries also lease office space at various
locations throughout the world to support business activities. 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.
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Electric Generation Facilities
Global has invested in the following generation facilities which are in
operation or under construction or advanced development:
- --------------------------------------------------------------------------------
OPERATING POWER PLANTS
- --------------------------------------------------------------------------------
As of December 31, 2001
- --------------------------------------------------------------------------------
Global's
Net Equity
Global's Interest in
Total Ownership Total
Location Primary Fuel MW Interest MW
---------------------------------------------------------------
United States
- -------------
Texas Independent Energy
Guadalupe......................... TX Natural gas 1,000 50% 500
Odessa............................ TX Natural gas 1,000 50% 500
Kalaeloa............................. HI Oil 180 50% 90
GWF
Bay Area I........................ CA Petroleum coke 21 50% 10
Bay Area II....................... CA Petroleum coke 21 50% 10
Bay Area III...................... CA Petroleum coke 21 50% 10
Bay Area IV....................... CA Petroleum coke 21 50% 10
Bay Area V........................ CA Petroleum coke 21 50% 10
Hanford.............................. CA Petroleum coke 27 50% 14
Hanford - Peaking Plant.............. CA Natural gas 90 50% 45
SEGS III............................. CA Solar 30 9% 3
Tracy................................ CA Biomass 21 35% 7
Bridgewater.......................... NH Biomass 16 40% 6
Kennebec............................. ME Hydro 15 16% 2
Conemaugh............................ PA Hydro 15 50% 8
------------ ----------
Total United States 2,499 1,225
------------ ----------
---------------------------------------------------------------
International
- -------------
CTSN................................. Argentina Coal/Natural 650 19% 124
gas/Oil
MPC
Jingyuan - Units 5 and 6.......... China Coal 600 15% 90
Tongzhou.......................... China Coal 30 40% 12
Nantong........................... China Coal 24 46% 11
Jinqiao (Thermal Energy).......... China Coal/Oil N/A 30% N/A
Zuojiang - Units 1, 2 and 3....... China Hydro 72 30% 22
Fushi - Units 1, 2 and 3.......... China Hydro 54 35% 19
Shanghai BFG...................... China Blast furnace 50 16% 8
gas
PPN.................................. India Naphtha/Natural 330 20% 66
gas
Tanir Bavi........................... India Naphtha 220 74% 163
Crotone.............................. Italy Biomass 20 26% 5
Electroandes......................... Peru Hydro 183 100% 183
Chorzow (existing facility).......... Poland Coal 100 55% 55
Turboven
Maracay.............................. Venezuela Natural gas 60 50% 30
Cagua................................ Venezuela Natural gas 60 50% 30
TGM.................................. Venezuela Natural gas 40 9% 4
----------- ------------
Total International (A) 2,493 822
----------- ------------
Total Operating Power Plants 4,992 2,047
----------- ------------
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- --------------------------------------------------------------------------------
POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT
- --------------------------------------------------------------------------------
As of December 31, 2001
- --------------------------------------------------------------------------------
Global's
Net Equity
Global's Interest in In
Total Ownership Total Service
International Location Primary Fuel MW Interest MW Date
- ------------- -------------------------------------------------------------------------------
United States
GWF Energy
Henrietta) (A) California Natural gas 90 50% 45 2002
Tracy) (A) California Natural gas 160 50% 80 2002
Parana......................... Argentina Natural gas 830 33% 274 2002
Halan (Thermal Energy)...... China Coal N/A 50% N/A 2002
Prisma
Strongoli................... Italy Biomass 40 26% 10 2002
Porto Empedocle (A)......... Italy Biomass 24 26% 6 2002
Bando....................... Italy Biomass 20 51% 10 2002
Salalah........................ Oman Natural gas 200 81% 162 2003
Skawina CHP (A)................ Poland Coal 590 35% 207 2003
Chorzow........................ Poland Coal 220 90% 198 2003
Kuo Kuang...................... Taiwan Natural gas 480 18% 84 2003
Rades.......................... Tunisia Natural gas 471 60% 283 2002
Turboven
Valencia (A)................ Venezuela Natural gas 80 50% 40 2002
---------- ----------
Total Construction or Advanced Development 3,205 1,399
---------- ----------
TOTAL Generation Facilities 8,197 3,446
========== ==========
(A) In advanced development.
Electric Distribution Facilities
Global also has invested in the following distribution facilities:
Global's
Number of Ownership
Location Customers Interest
------------------------------------------
EDEN (B)......................... Argentina 270,000 30%
EDES (B)......................... Argentina 150,000 30%
EDELAP (B)....................... Argentina 280,000 30%
EDEERSA.......................... Argentina 235,000 90%
Rio Grande Energia............... Brazil 990,000 32%
Chilquinta Energia............... Chile 400,000 50%
SAESA............................ Chile 630,000 100%
Luz del Sur...................... Peru 690,000 44%
---------
3,645,000
==========
(B) Assets Held for Sale to AES. See Note 18. Subsequent Events.
ITEM 3. LEGAL PROCEEDINGS
As previously disclosed, by complaints filed in 1995 and 1996, shareholder
derivative actions on behalf of PSEG shareholders were commenced by purported
shareholders against certain directors and officers. The four complaints
generally sought recovery of damages for alleged losses purportedly arising out
of PSE&G's operation of the Salem and Hope Creek generating stations, together
with certain other relief, including removal of certain executive officers of
PSE&G and PSEG and certain changes in the composition of PSEG's Board of
Directors. By decision dated July 28, 1999, the Court granted the defendants'
motions for summary judgment dismissing all four derivative actions. The
plaintiffs have appealed in all three of these actions. In April 2001, the
Appellate Division of the New Jersey Superior Court unanimously affirmed the
lower court's order granting summary judgment in the shareholder derivative
litigation. The plaintiffs have filed petitions for certification with the New
Jersey Supreme
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Court seeking permission to appeal this order, which PSEG has opposed. The New
Jersey Supreme Court granted the Petition for Certification and the matter was
argued in February 2002. PSEG cannot predict the outcome of these appeals.
Public Service Enterprise Group Inc. by G. E. Stricklin, derivatively v. E.
James Ferland, et. al., Superior Court of New Jersey, Chancery Division, Essex
County, Docket No. C-160-96. Dr. Steven Fink and Dr. David Friedman, P.C. Profit
Sharing Plan, derivatively, Lawrence R. Codey, et. al., Superior Court of New
Jersey, Chancery Division, Essex County, Docket No. C-65-96. A. Harold Datz
Pension and Profit Sharing Plan derivatively, et. al., v. Lawrence R. Codey, et.
al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No.
C-68-96.
The Brazilian Consumer Association of Water and Energy has filed a lawsuit
against Rio Grande Energia S.A. (RGE), a Brazilian distribution company of which
Global is a 32% owner, and two other utilities, claiming that certain value
added taxes and the residential tariffs that are being charged by such utilities
to their respective customers are illegal. RGE believes that its collection of
the tariffs and value added taxes are in compliance with applicable tax and
utility laws and regulations. While it is the contention of RGE that the claims
are without merit, and that it has valid defenses and potential third party
claims, an adverse determination could have a material adverse effect on PSEG's
financial condition, results of operations and net cash flows.
Assobraee-Associacao Brasileira de Consumidores de Agua e Energia Eletrica v.
Rio Grande Energia S/A -RGE, CEEE and AES Sul, First Public Treasury Court/City
of Porto Alegre. Proceeding No. 101214451.
See information on the following proceedings at the pages indicated:
(1) Pages 15 and 78. Proceedings before the BPU in the matter of the
Energy Master Plan Phase II Proceeding to investigate the future
structure of the Electric Power Industry, Docket Nos. EX94120585Y,
EO97070461, EO97070462, EO97070463, and EX01050303.
(2) Page 16. PSE&G's Gas Base Rate Filings, Docket Nos. GR01050328 and
GR01050297.
(3) Page 24. Administrative proceedings before the NJDEP under the FWPCA
for certain electric generating stations.
(4) Pages 26 and 27. Department of Energy (DOE) Overcharges, Docket No.
01-592C.
(5) Pages 26 and 27. DOE not taking possession of spent nuclear fuel,
Docket No. 01-551C.
(6) Pages 102. PSE&G's MGP Remediation Program.
(7) Page 102. Investigation and additional investigation by the EPA
regarding the Passaic River site. Docket No. EX93060255.
(8) Page 104. Complaint filed with the Federal Energy Regulatory
Commission addressing contract terms of certain Sellers of Energy
and Capacity under Long-Term Contracts with the California Department
of Water Resources. Public Utilities Commission of the State of
California v. Sellers of Long Term Contracts to the California
Department of Water Resources FERC Docket No. EL02-60-000. California
Electricity Oversight Board v. Sellers of Energy and Capacity Under
Long-Term Contracts with the California Department of Water Resources
FERC Docket No. EL02-62-000.
In addition, see the following environmental related matters involving
governmental authorities. Based on current information, PSEG does not expect
expenditures for any such site, individually or all such current sites in the
aggregate, to have a material effect on their financial condition, results of
operations and net cash flows.
(1) Claim made in 1985 by U.S. Department of the Interior under CERCLA
with respect to the Pennsylvania Avenue and Fountain Avenue municipal
landfills in Brooklyn, New York, for damages to natural resources. The
U.S. Government alleges damages of approximately $200 million. To
PSE&G's knowledge there has been no action on this matter since 1988.
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(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 us 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 operating and
maintenance expenses, 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 60% Complete Remedial Design document was
submitted to the EPA in March of 2001. This document presents the
design details that will implement the EPA 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.
Additionally, with respect to this site, the United States of America
application in the matter entitled United States of America, et. al.,
v. Union Corporation, et. al., Civil Action No. 80-1589, United States
District Court for the Eastern District of Pennsylvania, seeking leave
of court to file an amended complaint adding claims under the CERCLA
was granted. One other utility and us were named as third party
defendants in the foregoing captioned matter. An application to
intervene in the captioned matter as third party defendants, filed by
seven other utilities alleged to be liable for contamination at the
Site, has also been granted by the Court.
(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 has entered into a memorandum of
agreement (MOA) with the NJDEP for the Klockner Road site pursuant to
which PSE&G will conduct an RI/FS and remedial action, if warranted,
of the site. Preliminary investigations indicated the potential
presence of soil and groundwater contamination at the site.
(6) In 1991, the NJDEP issued Directive and Notice to Insurers Number Two
(Directive Two) to 24 Insurers and 52 Respondents, including PSE&G, in
connection with an investigation and remediation of the Global
Landfill Site in Old Bridge Township, Middlesex County, New Jersey
seeking recovery of past and anticipated future NJDEP response costs
($37 million). PSE&G and other participating PRPs have agreed with
NJDEP to a partial settlement of such costs and to perform the
remedial design and remedial action. In 1996, 13 of the Directive Two
Respondents, including PSE&G, filed a contribution action pursuant to
CERCLA and the Spill Act against approximately 190 parties seeking
contribution for an equitable share of all liability for response
costs incurred and to be incurred in connection with the site. In
September 1997, the NJDEP issued a Superfund record of decision (ROD)
with estimated cost of $3.7 million. The Directive Two Respondents'
foregoing contribution claims have been resolved by settlement in
2001.
(7) In 1991, the NJDEP issued Directive and Notice To Insurers Number One
(Directive No. One) to 50 insurers and 20 respondents, including
PSE&G, seeking from the respondents payment of $5.5 million of NJDEP's
anticipated costs of remedial action and of administrative oversight
at the Combe Fill South Sanitary Landfill in Washington and Chester
Townships, Morris County, New Jersey (Combe Site). The $5.5 million
represents NJDEP's 10% share of total estimated site remediation costs
and administrative oversight costs pursuant to a cooperative agreement
with the United States concerning the selected
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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remedial action for the site. In 1996, the NJDEP issued Directive
Number Two (Directive No. Two) to 37 respondents, including PSE&G,
directing the respondents to arrange for the operation, maintenance
and monitoring of the implemented remedial action described therein or
pay the NJDEP's future costs of these activities, estimated to be $39
million. In addition, Directive No. Two directs the respondents to
prepare a work plan for the development and implementation of a
Natural Resource Damage Restoration Plan. In October 1998, the NJDEP
and The United States of America filed separate cost recovery actions
pursuant to CERCLA and/or the Spill Act against approximately 30
parties seeking recovery of their respective shares of past and future
site investigation and remediation response and administrative
oversight costs incurred and to be incurred at the site. Third party
contribution actions were also filed in each of the foregoing cost
recovery actions seeking contribution for an equitable share of all
liability for these same costs from approximately 170 third party
defendants. PSE&G is a named defendant in the NJDEP cost recovery
action and a named third party defendant in the contribution action
filed in the United States' lawsuit.
(8) Spill Act Multi-Site Directive (Directive) issued by the NJDEP to
PRPs, including PSE&G, listing four separate sites, including the
former solid waste bulking and transfer facility called the Marvin
Jonas Transfer Station (Sewell Site) in Deptford Township, Gloucester
County, New Jersey. With regard to the Sewell Site, this Directive
ordered approximately 350 PRPs, including PSE&G, to enter into an
Administrative Consent Order (ACO) with NJDEP, requiring them to
remediate the Sewell Site. PSE&G and certain other de minimis parties
have accepted a settlement offer in 2001 from other PRPs to resolve
their liability for response and removal costs at the site.
(9) 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.
(10) The New York State Department of Environmental Conservation (NYSDEC)
has named PSE&G as one of many potentially responsible parties for
contamination existing at the former Quanta Resources Site in Long
Island City, New York. Waste oil storage, processing, management and
disposal activities were conducted at the site from approximately 1960
to 1981. It is believed that waste oil from our facilities was taken
to the Quanta Resources Site. NYSDEC has requested that the
potentially responsible parties reimburse the state for the costs
NYSDEC has expended at the site and to conduct an investigation and
remediation of the site. Power, PSE&G and the other PRPs are
negotiating with NYSDEC the terms of an agreement that will set forth
these requirements, and are negotiating among themselves an agreement
for the sharing of the associated costs.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
-------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our Common Stock is listed on the New York Stock Exchange, Inc. As of
December 31, 2001, there were 119,944 holders of record.
The following table indicates the high and low sale prices for our Common
Stock and dividends paid for the periods indicated:
Dividend
Common Stock High Low Per Share
- ------------ ---- --- ---------
2001:
First Quarter.......................... $48.50 $36.88 $0.54
Second Quarter......................... 51.55 41.80 0.54
Third Quarter.......................... 50.00 40.21 0.54
Fourth Quarter......................... 44.20 38.70 0.54
2000:
First Quarter.......................... $36.00 $25.69 $0.54
Second Quarter......................... 38.19 29.25 0.54
Third Quarter.......................... 45.69 32.88 0.54
Fourth Quarter......................... 50.00 38.88 0.54
For additional information concerning dividend history, policy and
potential preferred voting rights, restrictions on payment and common stock
repurchase programs, see Liquidity and Capital Resources and External Financings
of MD&A and Note 6. Schedule of Consolidated Capital Stock and Other Securities
of Notes.
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ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
Years Ended December 31,
----------------------------------------------------------------------------
2001 2000 1999 1998 1997
------------- ------------- ------------- ------------- -------------
(Millions of Dollars, where applicable)
Total Operating Revenues.................... $9,815 $9,495 $8,327 $7,864 $6,447
============= ============= ============= ============= =============
Income Before Extraordinary Item............ $763 $764 $723 $644 $560
Extraordinary Item (A)...................... (2) -- (804) -- --
Cumulative Effect Adjustment (B)............ 9 -- -- -- --
------------- ------------- ------------- ------------- -------------
Net Income (Loss)........................... $770 $764 $(81) $644 $560
============= ============= ============= ============= =============
Earnings per Average Share (Basic and Diluted):
Before Extraordinary Item................ $3.67 $3.55 $3.29 $2.79 $2.41
Extraordinary Item (A)................... (0.01) -- (3.66) -- --
Cumulative Effect Adjustment (B) ........ 0.04 -- -- -- --
------------- ------------- ------------- ------------- -------------
Total Earnings per Average Share....... 3.70 $3.55 $(0.37) $2.79 $2.41
============= ============= ============= ============= =============
Dividends Paid per Share.................... $2.16 $2.16 $2.16 $2.16 $2.16
As of December 31:
Total Assets............................. $25,397 $21,526 $19,015 $17,991 $17,943
Long-Term Liabilities:
Long-Term Debt (C) .................... $10,301 $5,297 $4,575 $4,763 $4,885
Other Noncurrent Liabilities (E)....... $1,981 $1,762 $1,562 $764 $609
Preferred Stock With Mandatory Redemption... -- $75 $75 $75 $75
Monthly Guaranteed Preferred Beneficial
Interest
in PSE&G's Subordinated Debentures....... $60 $210 $210 $210 $210
Quarterly Guaranteed Preferred Beneficial
Interest
in PSE&G's Subordinated Debentures....... $95 $303 $303 $303 $303
Quarterly Guaranteed Preferred Beneficial
Interest
in PSEG's Subordinated Debentures........ $525 $525 $525 $525 --
Ratio of Earnings to Fixed Charges (D)... 2.30 2.73 3.09 2.86 2.55
(A) 2001 charge relates to loss on early debt retirement. For the
extraordinary charge recorded in 1999, see Note 3 - Regulatory Issues and
Accounting Impacts of Deregulation.
(B) Impact of SFAS 133 Adoption, See Note 8. Financial Instruments, Energy
Trading and Risk Management.
(C) Increase in debt partially related to securitization transaction in 2001
and consolidation of non-recourse debt.
(D) Excludes income and expenses from Extraordinary Item.
(E) Excludes Deferred Taxes and ITC and the Excess Depreciation Reserve
portion of Regulatory Liabilities.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This discussion makes reference to the Consolidated Financial Statements
and related Notes to Consolidated Financial Statements (Notes) of Public Service
Enterprise Group Incorporated and should be read in conjunction with such
statements and notes.
CORPORATE STRUCTURE
We are a holding company and, as such, have no operations of our own. We
have four principal direct wholly-owned subsidiaries: Public Service Electric
and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc.
(Energy Holdings) and PSEG Services Corporation (Services).
PSE&G is an operating public utility company engaged principally in the
transmission, distribution and sale of electric energy and gas service in New
Jersey. On August 21, 2000, pursuant to the terms of the Final Order issued by
the New Jersey Board of Public Utilities (BPU), PSE&G transferred its
generation-related assets and liabilities and its wholesale power contracts to
Power and its subsidiaries in exchange for a promissory note in an amount equal
to the total purchase price of $2.786 billion. Power paid the promissory note on
January 31, 2001 at which time the transferred assets were released from the
lien of PSE&G's First and Refunding Mortgage. PSE&G continues to own and operate
its regulated electric and gas transmission and distribution business. A
bankruptcy-remote subsidiary of PSE&G, PSE&G Transition Funding LLC, issued
$2.525 billion of securitization bonds in January of 2001 in partial recovery of
PSE&G's stranded cost resulting from New Jersey deregulation and restructuring.
An additional $540 million of PSE&G's stranded costs is being recovered from its
customers over a four-year transition period ending July 31, 2003 through a
Market Transition Charge (MTC).
Power was formed in June 1999 to acquire, own and operate the electric
generation-related assets of PSE&G pursuant to the Final Order issued by the BPU
under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the
New Jersey Electric Discount and Energy Competition Act (Energy Competition
Act). Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear
LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC
(ER&T) and currently operates in two reportable segments, generation and
trading. The generation segment of Power's business earns revenues by selling
energy on a wholesale basis under contract to power marketers and to load
serving entities, and by bidding energy, capacity and ancillary services into
the market. The energy trading segment of Power's business earns revenues by
trading energy, capacity, fixed transmission rights, fuel and emission
allowances in the spot, forward and futures markets. The trading segment also
earns revenues through financial transactions, including swaps, options and
futures in the electricity and gas markets. Power also has a finance company
subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides
certain financing for its other subsidiaries.
Energy Holdings participates in three energy-related reportable segments
through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global),
which develops, acquires, owns and operates electric generation and distribution
facilities; PSEG Resources Inc. (Resources), which provides energy
infrastructure financing and invests in energy-related financial transactions
and manages a diversified portfolio of investments including leveraged leases,
operating leases, leveraged buyout (LBO) funds, limited partnerships and
marketable securities; and PSEG Energy Technologies Inc. (Energy Technologies),
an energy management company that constructs, operates and maintains heating,
ventilating and air conditioning (HVAC) systems for, and provides energy-related
engineering, consulting and mechanical contracting services to, industrial and
commercial customers in the Northeastern and Middle Atlantic United States.
Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG
Capital), which serves as a financing vehicle for Energy Holdings' subsidiaries
and borrows on the basis of a minimum net worth maintenance agreement with PSEG.
See Liquidity and Capital Resources for further detail. Energy Holdings is also
the parent of Enterprise Group Development Corporation (EGDC), a property
management business and is conducting a controlled exit from this business.
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Services was formed in 1999 and provides management and administrative
services to us and our subsidiaries.
OVERVIEW OF 2001 AND FUTURE OUTLOOK
The Energy Competition Act and the related BPU proceedings, including the
Final Order and the Energy Master Plan Proceedings, have dramatically reshaped
the utility industry in New Jersey and have directly affected how we will
conduct business, and therefore, our financial prospects in the future.
Deregulation, restructuring, privatization and consolidation are creating
opportunities and risks for us and our subsidiaries. We have realigned our
organizational structure to address the competitive environment brought about by
the deregulation of the electric generation industry in New Jersey and the
Eastern U.S and have transitioned from primarily being a regulated New Jersey
utility to a operating as a competitive global energy company. We have been
engaged in the competitive energy business for a number of years through certain
of our unregulated subsidiaries; however, competitive businesses now constitute
a much larger portion of our activities. As of December 31, 2001, Power, PSE&G,
and Energy Holdings comprised approximately 20%, 51% and 29% of PSEG's
consolidated assets and contributed approximately 50%, 30% and 20% of our net
income for the year ended December 31, 2001. Our projected earnings
contributions for 2002 and 2003 are 50% to 55% from Power, 25% to 30% from
Energy Holdings and 20% to 25% from PSE&G. Additionally, we will be more
dependent on cash flows generated from our unregulated operations for our
capital needs. As the unregulated portion of the business continues to grow,
financial risks and rewards will be greater, financial requirements will change
and the volatility of earnings and cash flows will increase.
Our subsidiaries consist of a portfolio of energy-related businesses that
together are designed to produce a coherent energy market strategy. Because the
nature and risks of these businesses are different, and because they operate in
different geographic locations, the combined entity is designed to produce
consistent earnings growth in a manner that will mitigate the adverse financial
effects of business losses or an economic downturn is any one sector or
geographic region.
For 2001, we earned $3.70 per share. Our improved earnings for 2001 as
compared to 2000 were due primarily to new acquisitions, asset sales and
improved operations at Global, new leveraged lease investments at Resources,
continued strong performance of our nuclear generating facilities and improved
performance of our energy trading operations, which saw an increase in margins
from $72 million in 2000 to $140 million in 2001. These improvements more than
offset the effects of comparatively unfavorable weather conditions, two BPU
mandated 2% rate reductions, effective in February 2001 and August 2001, and the
effects of the securitization transaction that occurred on January 31, 2001.
We estimate a 7% compound annual growth rate in earnings per share over the
next five years. Our earnings for 2002 will depend on several factors, including
our ability to effectively manage our commitments under contracts to deliver
energy, capacity and ancillary services to the various suppliers of BGS to New
Jersey's utilities and our ability to minimize the effects, including potential
asset impairments, brought about by the economic, political and social crisis in
Argentina, where we face considerable fiscal and cash uncertainties. For further
discussion of our $632 million investment exposure in Argentina, see Note 9.
Commitments and Contingent Liabilities.
Looking beyond 2002, our earnings will depend on the outcome of future BGS
auctions in New Jersey, energy prices, which are currently depressed, in the
United States markets in which Power and Global participate, the successful
operation of our generation stations, PSE&G's ability to obtain timely and
adequate rate relief, regulatory decisions affecting our interests in
distribution companies in South America, and the effect of economic conditions
in foreign countries in which we invest.
PSE&G
PSE&G operates under cost-based regulation by the BPU for its distribution
operations and by the Federal Energy Regulatory Commission (FERC) for its
electric transmission operations. As such, the earnings of PSE&G are largely
determined by the regulation of its rates. PSE&G is expected to continue to make
a steady contribution to earnings in the future as it continues its transmission
and distribution and sale of electric energy and gas service in
40
New Jersey. PSE&G's success will be determined by its ability to maintain system
reliability and safety, effectively manage costs and obtain timely and adequate
rate relief. The risks from this business are relatively modest and generally
relate to the regulatory treatment of the various rate and other issues by the
BPU and the FERC.
On January 9, 2002 the BPU approved an additional $90 million of gas base
rate revenues for PSE&G, simultaneously with other PSE&G rate filings related to
underrecovered gas costs which were deferred on its balance sheet. All three
rate changes were effective January 9, 2002.
Also on January 9, 2002, the BPU approved the transfer of the utility's gas
supply business, including its transportation and storage contracts, to Power.
As a result, after April 1, 2002, Power will provide gas supply to PSE&G to
serve its Basic Gas Supply Service (BGSS) customers under a Requirements
Contract at market prices. Industrial and commercial BGSS customers will be
priced under PSE&G's Market Priced Gas Service (MPGS) and residential BGSS
customers will remain under current pricing until April 1, 2004 after which,
subject to further BPU approval, those residential gas customers would also move
to MPGS service.
On February 15, 2002, the BPU announced the successful outcome of the BGS
auction. Through the auction, PSE&G contracted for sufficient electricity to
serve all of its BGS customers and any difference between the existing tariff
rates and the rates set through the auction for the one-year contract period
beginning August 1, 2002 will be deferred and recovered over future periods as a
regulatory asset.
POWER
Power is focused on a generation market extending from Maine to the
Carolinas and the Atlantic Coast to Indiana (Super Region). The risks of Power's
business are that the competitive wholesale power prices that it is able to
obtain are sufficient to provide a profit and sustain the value of its assets.
It is also subject to credit risk of the counterparties to whom it sells energy
products, the successful operation of its generating facilities, fluctuations in
market prices of energy and imbalances between obligations and available supply.
These risks are higher than those for a regulated business. Therefore, they
provide the opportunity for greater returns, but they also present the greater
possibility of business losses and counterparty credit risk. Power is currently
constructing projects which will increase capacity by over 3,500 MW, net of
planned retirements.
Power currently sells approximately 95% of the output from its generation
facilities under bilateral contracts, primarily the BGS contract with PSE&G, and
the remaining 5% to customers in the competitive wholesale (spot) market. Within
the spot market, Power sells into the energy, capacity and ancillary services
markets. Ancillary services include operating reserves and area regulation.
Power has entered into one-year contracts commencing August 1, 2002 with
various direct bidders in the New Jersey BGS Auction, which was approved by the
BPU on February 15, 2002. Power believes that its obligations under these
contracts are reasonably balanced by its available supply.
In addition, we anticipate that Power will continue its strong growth in
its energy trading segment. In 2001, the energy trading business realized a
gross margin of $140 million and forecasts an improvement for 2002, primarily
driven by the transfer of PSE&G's gas supply business to Power, discussed
below. We marked to market energy trading contracts with gains and losses
included in earnings. The vast majority of these contracts have terms of less
than one year and are valued using market exchange prices and broker quotes.
The energy trading business provides the opportunity for greater returns, but
it also is more risky than the regulated business, and can be adversely
impacted by fluctuating energy market prices and by the credit quality of the
counterparties with which it does business. Our trading business utilizes a
conservative risk management strategy to minimize exposure to credit risk. For
further information, see Accounting Issues, Note 1. Organizationa and Summary
of Significant Accounting Policies and Note 8. Financial Instruments, Energy
Trading and Risk Management.
ENERGY HOLDINGS
Energy Holdings is a major part of our growth strategy. In order to achieve
this strategy, Global will focus on generation and distribution investments
within targeted high-growth regions. Resources will utilize its market access,
industry knowledge and transaction structuring capabilities to expand its
energy-related financial investment
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portfolio. We are evaluating the future prospects of Energy Technologies'
business model and its fit in our portfolio given the slower pace of retail
deregulation in the markets in which we operate. Resources' assets generate cash
flow and earnings in the near term, while investments at Global generally have a
longer time horizon before achieving expected cash flow and earnings. Also,
Resources' passive lower-risk assets serve to balance the higher risk associated
with operating assets at Global and Energy Technologies.
Global's more recent activities have been concentrated on developing
generation internationally and in acquiring distribution businesses, principally
in South America, that have been privatized by the local governments. As Global
has grown, its objective has evolved from being a minority or equal partner to
seeking to be the majority or sole owner of many of its investments. Global's
business depends on the ability to negotiate or obtain favorable prices and
terms for the output of its generating facilities nationally and
internationally, and to obtain favorable governmental and regulatory treatment
for its distribution assets in foreign countries. Global undertakes investments
where the expected return is commensurate with the market, regulatory,
international and currency risks that are inherent with its investments. Since
these risks are priced in the original investment decision, to the extent that
market, regulatory international or currency conditions evolve differently than
originally forecast, the investment performance of Global's assets will differ
form the expected performance. Thus, the expected investment returns from
Global's projects are priced to produce relatively high returns to compensate
for the high level of risk associated with this business.
Global has investment exposure of $632 million in four distribution
companies and two generation plants in Argentina. For further discussion of our
$632 million investment exposure in Argentina, see Note 9. Commitments and
Contingent Liabilities.
Resources invests principally in energy-related financing transactions,
principally leveraged leases. As such, it is designed to produce predictable
earnings at reasonable levels with relatively low risk. The modest risks faced
by Resources are the credit risk of its counterparties and the tax treatment of
its investment structures. Resources' earnings and cash flow streams are
dependent upon the availability of and its ability to continue to enter into
these transactions.
Energy Technologies is a business that principally constructs and installs
heating, ventilating and air conditioning equipment and related services. It has
not produced profitable operations due to the extremely competitive nature of
the business and the failure of the retail energy market to develop. The
principal risks of this business are to be able to reduce internal costs to
become profitable in this market and to obtain revenues to cover the carrying
value of its assets.
RESULTS OF OPERATIONS
Our business consists of six reportable segments which are Generation,
Energy Trading, PSE&G, Global, Resources and Energy Technologies. The following
is a discussion of the major year-to-year financial statement variances and
follows the financial statement presentation as it relates to each of our
segments. The presentation of Electric Revenues and Electric Energy Costs
includes Power's generation business, the electric transmission and distribution
business of PSE&G and the consolidated portions of Global's operations; Gas
Revenues and Gas Costs includes the gas distribution business of PSE&G; Trading
Revenues and Costs includes Power's energy trading business; and Other Revenues
includes Global's unconsolidated operations, Resources and Energy Technologies.
Prior to 2001, Energy Technologies had certain electric and gas costs which were
included in Electric Energy Costs and Gas Costs, respectively. For a discussion
of management's determination of our reportable segments and related
disclosures, see Note 14. Financial Reporting by Business Segments.
Prior to April 1999, the discussion that follows reports on business
conducted under full monopoly regulation of the utility businesses. It must be
understood that such businesses have changed due to the deregulation of the
electric generation and natural gas commodity sales businesses, the subsequent
transfer of the generation business, and the anticipated transfer of the gas
supply business from PSE&G to Power. Past results are not an indication of
future business prospects or financial results.
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Earnings (Losses)
------------------------------------------------
Year Ended December 31,
------------------------------------------------
2001 2000 1999 (A)
------------ ------------ ------------
(Millions of Dollars)
Generation...................... $311 $270 $490
Energy Trading.................. 83 43 23
PSE&G........................... 230 369 131
Resources....................... 64 65 66
Global.......................... 116 40 28
Energy Technologies............. (18) (10) (6)
Other (B)....................... (16) (13) (9)
------------ ------------ ------------
Total PSEG................. $770 $764 $723
============ ============ ============
Contribution to Earnings Per Share
(Basic and Diluted)
------------------------------------------------
Year Ended December 31,
------------------------------------------------
2001 2000 1999 (A)
------------ ------------ ------------
Generation...................... $1.49 $1.26 $2.23
Energy Trading.................. 0.40 0.20 0.10
PSE&G........................... 1.11 1.71 0.60
Resources....................... 0.31 0.30 0.30
Global.......................... 0.55 0.19 0.13
Energy Technologies............. (0.08) (0.05) (0.03)
Other (B)....................... (0.08) (0.06) (0.04)
------------ ------------ ------------
Total PSEG................. $3.70 $3.55 $3.29
============ ============ ============
(A) Excludes $804 million, net of tax, extraordinary item recorded in
1999.
(B) Other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation) and EGDC. Losses
primarily result from after-tax effect of interest on certain
financing transactions and certain other administrative and general
expenses at parent companies.
For the Year Ended December 31, 2001 compared to the Year Ended December 31,
2000
Basic and diluted earnings per share of our common stock (Common Stock)
were $3.70 for the year ended December 31, 2001, an increase of $0.15 per share,
or 4.2% from the comparable 2000 period, including $0.12 of accretion as a
result of our stock repurchase program, discussed in Liquidity and Capital
Resources. In addition, our improved earnings for 2001 as compared to 2000
resulted from improved performance from our Energy Trading segment, Global's
withdrawal and sale of its interest in the Eagle Point Cogeneration Partnership
(Eagle Point), acquisitions and expanded operations at Global, new leveraged
lease investments at Resources and continued strong performance of our nuclear
facilities. These improvements more than offset the effects of unfavorable
weather conditions at PSE&G, two BPU mandated 2% rate reductions effective in
February 2001 and August 2001 which reduced generation revenues, and the effects
of the securitization transaction that occurred on January 31, 2001.
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Operating Revenues
Electric
Electric revenues increased $319 million or 8% in 2001 as compared to 2000
primarily due to the inclusion of $172 million of revenues related to various
majority owned acquisitions and plants going into operation at our Global
segment in 2001.
In addition, revenues from our generation segment increased $108 million in
2001 as compared to 2000 primarily due to an increase of $180 million in BGS
revenue for the year ended December 31, 2001 as compared to 2000 which resulted
from customers returning to PSE&G in 2001 from third party suppliers (TPS) as
wholesale market prices exceeded fixed BGS rates. At December 31, 2001, TPS were
serving less than 1% of the customer load traditionally served by PSE&G as
compared to the December 31, 2000 level of 10.5%. Partially offsetting this
increase was a net $40 million decrease in MTC revenues, relating to two 2% rate
reductions offset by a pre-tax charge to income related to MTC recovery in 2000.
As of December 31, 2001, as required by the Final Order, PSE&G has had rate
reductions totaling 9% since August 1, 1999 and will have an additional 4.9%
rate reduction effective August 1, 2002, which will be in effect until July 31,
2003.
The remaining $39 million of the increase related to the PSE&G segment and
was primarily related to increases in electric distribution and appliance
service revenue.
Gas Distribution
In our PSE&G segment, Gas Distribution revenues increased $153 million or
7% in 2001 as compared to 2000 primarily due to higher gas costs experienced in
2001. Customer rates in all classes of business have increased in 2001 to
recover a portion of the higher natural gas costs. The commercial and industrial
classes fuel recovery rates vary monthly according to the market price of gas.
The BPU also approved increases in the fuel component of the residential class
rates of 16% in November 2000 and 2% for each month from December 2000 through
July 2001. These increased revenues were partially offset by lower sales volumes
in the fourth quarter of 2001 than the comparable period in 2000, primarily
resulting from warmer weather.
Pursuant to a settlement, the BPU issued an order approving a $90 million
gas base rate increase effective January 9, 2002. The BPU approved the
settlement simultaneously with the implementation of PSE&G's previously approved
Gas Cost Underrecovery Adjustment (GCUA) surcharge to recover its October 31,
2001 gas cost under-recovery balance of approximately $130 million over a three
year period with interest and also approved PSE&G's proposal to reduce its
2001/2003 Commodity Charges (formerly Levelized Gas Adjustment Clause (LGAC)) by
approximately $140 million. The net impact of simultaneously implementing the
above three proceedings for the typical gas residential heating customers is an
approximate rate reduction of 2%.
Trading
Revenues from our energy trading segment decreased by $321 million or 12%
for the year ended December 31, 2001 from the comparable periods in 2000,
respectively, due to lower energy trading volumes and lower prices as compared
to 2000. For information regarding valuation, term, credit and other issues
related to Power's energy trading segment, see Accounting Issues, Note 1.
Organization and Summary of Significant Accounting Policies and Note 8.
Financial Instruments, Energy Trading and Risk Management of Notes.
Other
Other revenues increased $169 million or 21% in 2001 as compared to 2000.
This increase was due to an increase in revenues at the Global, Resources and
Energy Technologies segments of $111 million, $9 million and $50 million,
respectively. The increase at Global was primarily realized from the gain of $75
million on the withdrawal and sale of Global's interest in Eagle Point and was
partially offset by a loss in equity earnings of $26 million, which was recorded
in 2000 and not recorded in 2001, as a result of the withdrawal. In addition,
revenues benefited from an increase of $45 million in
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interest income related to certain loans, notes and approximately $29 million of
increased revenues relating primarily to improved earnings of certain
non-consolidated projects. These increases were partially offset by lower
revenues due to a reduction in earnings related to the adverse effect of foreign
currency exchange rate movements between the United States dollar and Brazilian
Real. The increase at Resources was primarily due to improved revenues of $45
million from higher leveraged lease income from new leveraged lease transactions
that was partially offset by lower Net Investment Gains of $37 million. The
increase at Energy Technologies was primarily due to increased sales in its
mechanical contracting business partially offset by a decrease of energy supply
revenues.
Operating Expenses
Electric Energy Costs
Electric Energy Costs increased $159 million or 17% in 2001 as compared to
2000. The increase was primarily due to $85 million of Electric Energy Costs
relating to the various majority-owned acquisitions and projects going into
operation at Global in 2001; higher costs in our generation segment associated
with increased load served under the BGS contract due to retail customers
returning to PSE&G in 2001 as discussed previously; and higher fuel costs of $73
million for fossil generation from higher natural gas prices in the early part
of 2001 and higher gas expense due to increased MMBTU usage. These increases
were partially offset by low cost generation from the continued strong
performance of our nuclear generation facilities.
Gas Costs
Gas Costs increased $125 million or 8% in 2001 as compared to 2000 due to
higher natural gas prices at our PSE&G segment in the early part of 2001. Under
the LGAC in PSE&G, underrecoveries or overrecoveries, together with interest (in
the case of net overrecoveries), are deferred and included in operations in the
period in which they are reflected in rates. These increases were partially
offset by lower costs incurred at Energy Technologies due to the outsourcing of
certain supply contracts since June 2000 under its retail gas service
agreements.
Trading Costs
Energy Trading costs decreased $391 million or 15% in 2001 compared to
2000, primarily due to lower energy trading volumes and lower prices.
Operation and Maintenance
Operation and Maintenance expense increased $280 million or 14% in 2001 as
compared to 2000. Contributing to the increase were higher operating expenses
relating to various majority-owned acquisitions and new plants going into
operation at Global in 2001. Additionally, operation and maintenance expenses
increased due to planned generation outage work in the first quarter of 2001 and
higher expenses relating to projects going into operation during the second
quarter of 2000 for our generation segment and the deferral of costs incurred
during 2000 in connection with deregulation that PSE&G expects to recover in
future rates.
Depreciation and Amortization
Depreciation and Amortization expense increased $160 million or 44% in 2001
as compared to 2000. The 2001 increase was due primarily due to $180 million of
amortization of the regulatory asset recorded for PSE&G's stranded costs, which
commenced with the issuance of the transition bonds, previously discussed. These
increases were partially offset by a reduction in the accrual for the estimated
cost of removal in our Generation segment.
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Taxes Other Than Income Taxes
Taxes Other Than Income Taxes decreased $16 million or 9% in 2001 as
compared to 2000. This decrease was primarily due to a reduction in the net
taxable Transitional Energy Facility Assessment (TEFA) sales and the scheduled
phase out of the TEFA. The TEFA was enacted as part of the energy tax reform
bill and was scheduled to be phased out by 2003. Recent legislation delayed the
phase out until 2007.
Interest Expense
Interest expense increased $131 million or 23% in 2001 as compared to 2000.
The increase was primarily due to increased debt associated with the issuance of
$2.525 billion securitization bonds by Transition Funding and the issuance of
$1.8 billion of senior notes by Power to finance the generation asset transfer.
These increases were offset by a general reduction in the amount of short-term
and long-term debt at PSEG and PSE&G using proceeds from securitization bonds.
Interest expense at Energy Holdings increased $53 million primarily from
additional borrowings used for equity investments in Global and Resources.
Preferred Securities Dividend Requirements of Subsidiaries
Preferred Securities Dividend Requirements decreased $22 million or 23% in
2001 as compared to 2000 due to redemption of trust preferred securities.
Income Taxes
Income Taxes decreased $117 million or 24% in 2001 as compared to 2000. The
decrease was primarily due to lower pre-tax income and normal adjustments as a
result of closing the audit for the 1994-1996 tax years and upon filing our
actual tax return for 2000.
For the Year Ended December 31, 2000 compared to the Year Ended December 31,
1999
Excluding the $804 million, net of tax, extraordinary charge recorded in
1999, resulting from the deregulation of our generation segment, basic and
diluted earnings per share increased $0.26 for the year ended December 31, 2000
as compared to 1999, including $0.08 of accretion as a result of our stock
repurchase program. For further discussion, see Note 3. Regulatory Issues and
Accounting Impacts of Deregulation of Notes. This increase was primarily due to
lower depreciation and amortization resulting from the amortization of the
excess depreciation reserve at our PSE&G segment beginning in January 2000 and
the lower depreciation resulting from the lower recorded amounts of the
generation-related assets in our generation segment resulting from the 1999
impairment recorded pursuant to Statement of Financial Accounting Standards
(SFAS) No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" (SFAS 121). Also contributing to the
increase were increased sales due to favorable weather conditions in the fourth
quarter of 2000 and higher profits realized from our energy trading segment. In
addition, better overall performance of our Global segment, which benefited from
favorable performance by its domestic generation assets and by its investments
made in South America distribution assets in 1999, contributed to the increase.
The increase in earnings was partially offset by the 5% electric rate reduction,
beginning August 1, 1999 coupled with a charge to income in the third quarter of
2000 related to MTC recovery at our generation segment.
Operating Revenues
Electric
Electric revenues decreased $244 million or 6% in 2000 as compared to 1999
due to a decrease in revenues from our generation segment primarily relating to
the 5% rate reduction, which decreased our revenues by approximately $120
million combined with a $115 million deferral of MTC revenues; and reduced
retail demand as PSE&G lost retail customers to TPS which amounted to
approximately $182 million. See Accounting Issues-Accounting for the Effects of
Regulation for a discussion of the deferral of MTC revenues. These decreases
were partially offset by increased revenues from our PSE&G segment relating to
higher transmission and distribution sales.
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To the extent fuel expense flowed through the Electric Levelized Energy
Adjustment Clause (LEAC) through July 31, 1999, the Levelized Gas Adjustment
Clause (LGAC), the Societal Benefits Clause (SBC) or the non-utility generation
market transition charge (NTC) mechanisms, as established by the BPU with
respect to PSE&G's rates, variances in certain revenues and expenses offset and
thus had no effect on earnings. On August 1, 1999, the LEAC mechanism was
eliminated as a result of the Final Order. This has increased earnings
volatility since Power now bears the full risks and rewards of changes in
nuclear and fossil generating fuel costs and purchased power costs. See Note 3.
Regulatory Issues and Accounting Impacts of Deregulation for a discussion of
LEAC, LGAC, SBC, NTC, Remediation Adjustment Clause (RAC) and Demand Side
Management (DSM) and their status under the Energy Master Plan Proceedings.
Gas Distribution
Revenues from our PSE&G segment for gas distribution increased $423 million
or 25% in 2000 as compared to 1999 primarily due to increases in natural gas
prices being passed along to customers under certain transportation only
contracts. Under these contracts, PSE&G is responsible only for delivery of gas
to its customers. Such customers are responsible for payment to PSE&G for the
cost of the commodity and as PSE&G's costs for these customers increase, the
customer's rates will increase. Also contributing to this increase were higher
sales resulting from colder weather in the fourth quarter of 2000 as compared to
the same period in 1999 and higher rates approved by the BPU to allow PSE&G to
recover for increasing natural gas costs.
Trading
Energy Trading revenues increased $882 million or 48% for the year ended
December 31, 2000 from the comparable period in 1999 primarily due to increased
energy trading volumes.
Other
Other revenues increased $107 million or 16% in 2000 as compared to 1999.
The increase was due to an increase of $26 million at Resources due to higher
leveraged lease income from new leveraged lease investments, and increases in
revenue at Energy Technologies due to the addition of revenues from acquisitions
of various HVAC companies in 2000 and 1999. These increases were partially
offset by a reduction in revenues of $42 million at Global primarily due to
a gain on sale of Newark Bay recorded in 1999 as compared to no significant gain
on sale of assets in 2000.
Operating Expenses
Electric Energy Costs
Electric Energy Costs increased $38 million or 4% in 2000 as compared to
1999. The increase was primarily due to higher fuel costs in our generation
segment and additional costs related to projects at our Global and Energy
Technologies segments.
Due to the elimination of the LEAC on August 1, 1999, the historical trends
can no longer be considered an indication of future Electric Energy Costs. Given
the elimination of the LEAC, the lifting of the requirements that electric
energy offered for sale in the Pennsylvania-New Jersey-Maryland Power Pool (PJM)
regional pool not exceed the variable cost of producing such energy (capped at
$1,000 per megawatt-hour), the absence of a PJM price cap in situations
involving emergency purchases and the potential for plant outages, price
movements could have a material impact on our financial condition, results of
operations or net cash flows.
Gas Costs
Gas Costs increased $364 million or 33% in 2000 as compared to 1999
primarily due to the higher prices for natural gas and increased demand for
natural gas at our PSE&G segment due to colder weather in the fourth quarter
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of 2000 as compared to the same period in 1999. This increase was partially
offset by the outsourcing of certain supply contracts at Energy Technologies in
June 2001, as discussed previously.
Due to the operation of the Levelized Gas Adjustment Clause (LGAC)
mechanism, variances in gas revenues and costs at PSE&G offset and had no direct
effect on earnings.
Trading Costs
Energy Trading Costs increased $847 million or 47% for the year ended
December 31, 2000 from the comparable 1999 period primarily due to increased
energy trading volumes.
Operation and Maintenance
Operation and Maintenance expense increased $81 million or 4% in 2000 as
compared to 1999. The increase was primarily due to the addition of $123 million
in operating expenses from the HVAC and mechanical service contracting companies
acquired by Energy Technologies in 2000 and 1999. The increase was partially
offset by the effects of a $55 million pre-tax charge to earnings to reduce the
carrying value of certain assets at Global and EGDC in 1999.
Depreciation and Amortization
Depreciation and Amortization expense decreased $174 million or 32% in 2000
as compared to 1999. The decrease was primarily due to the amortization of the
regulatory liability for the excess electric distribution depreciation reserve
at PSE&G, which amounted to approximately $125 million as of December 31, 2000.
Also contributing to the decrease was lower depreciation resulting from the
lower net book value balances of the generation-related assets in our generation
segment. The generation-related asset balances were reduced as of April 1, 1999
as a result of the impairment recorded pursuant to SFAS 121.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes, which include TEFA, decreased $14 million or
7% in 2000 as compared to 1999 due to New Jersey Energy tax reform and the
five-year commencing in January 1999. Effective January 1, 2000, revised rates
became effective which reflected two years phase out of the TEFA discussed
previously.
Interest Expense
Interest expense increased $84 million or 17% in 2000 as compared to 1999.
The increase was primarily due to interest expense associated with recourse
financing activities at Energy Holdings which increased $51 million from
additional borrowings incurred as a result of equity investments in distribution
and generation facilities and the repayment of non-recourse debt. Also
contributing to the increase was the interest related to higher levels of
short-term debt.
Income Taxes
Income Taxes decreased $73 million or 13% in 2000 as compared to 1999. The
decrease is primarily due to a decrease in the foreign tax liability from
foreign investments at Global recorded under the equity method. Under such
accounting method, Global reflects in revenues its pro rata share of
investments net income. Under this accounting method, the foreign income taxes
are a component of equity in earnings, thereby distorting the effective tax
rate downward. During 1999, there was an increase in state income taxes at
Resources totaling $11 million due to the early termination of a leveraged
lease. The decrease was also due to lower effective tax rates relating to the
amortization of the excess depreciation reserve for electric distribution.
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LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a
consolidated basis, noting the uses and contributions of our three direct
operating subsidiaries in 2001, PSE&G, Power and Energy Holdings.
Our capital requirements and those of our subsidiaries are met and
liquidity provided by internally generated cash flow and external financings.
PSEG, Power and Energy Holdings from time to time make equity contributions to
their respective direct and indirect subsidiaries to provide for part of their
capital and cash requirements, generally relating to long-term investments. At
times, we utilize inter-company dividends and inter-company loans to satisfy
various subsidiary needs and efficiently manage our and our subsidiaries'
short-term cash needs. Any excess funds are invested in accordance with
guidelines adopted by our Board of Directors.
External funding to meet our needs and the needs of PSE&G, the majority of
the requirements of Power and a substantial portion of the requirements of
Energy Holdings, is comprised of corporate finance transactions. The debt
incurred is the direct obligation of those respective entities. Some of the
proceeds of these debt transactions are used by the respective obligor to make
equity investments in its subsidiaries.
All of our publicly traded debt as well as that of PSE&G, Power and Energy
Holdings have received investment grade ratings from each of the three major
credit rating agencies. The changes in the energy industry and the recent
bankruptcy of Enron Corp. are attracting increased attention from the rating
agencies which regularly assess business and financial matters. Given the
changes in the industry, attention to and scrutiny of our, PSE&G's, Power's and
Energy Holdings' performance, capital structure and competitive strategies by
rating agencies will likely continue. These changes could affect the bond
ratings, cost of capital and market prices of our respective securities. We will
continue to evaluate our capital structure, financing requirements, competitive
strategies and future capital expenditures to maintain our current credit
ratings.
The current ratings of securities of PSEG and its subsidiaries are shown
below and reflect the respective views of the rating agencies, from whom an
explanation of the significance of their ratings may be obtained. There is no
assurance that these ratings will continue for any given period of time or
that they will not be revised or withdrawn entirely by the rating agencies,
if, in their respective judgments, circumstances so warrant. Any downward
revision or withdrawal may adversely effect the market price of PSEG's, Energy
Holdings' Powers and PSE&G's securities and serve to increase those companies'
cost of capital.
Moody's Standard & Poor's Fitch
------------------------------------------------------------------
PSEG
-----------------------------
Extendible Notes Baa2 BBB BBB+
Preferred Securities Baa3 BB+ BBB
Commercial Paper P2 A2 Not Rated
PSE&G
-----------------------------
Mortgage Bonds A3 A- A
Preferred Securities Baa1 BBB A-
Commercial Paper P2 A2 F1
Power
-----------------------------
Senior Notes Baa1 BBB BBB+
Energy Holdings
-----------------------------
Senior Notes Baa3 BBB- BBB-
PSEG Capital
-----------------------------
Medium Term Notes Baa2 BBB Not Rated
Depending on the particular company, external financing may consist of
public and private capital market debt and equity transactions, bank revolving
credit and term loan facilities, commercial paper and/or project financings.
Some of these transactions involve special purpose entities. These are
corporations, limited liability companies or partnerships formed in accordance
with applicable tax, accounting and legal requirements in order to achieve
specified beneficial financial advantages, such as favorable tax, legal
liability or accounting treatment.
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The availability and cost of external capital could be affected by each
subsidiary's performance as well as by the performance of their respective
subsidiaries and affiliates. This could include the degree of structural or
regulatory separation between us and our subsidiaries and between PSE&G and its
non-utility affiliates 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 and
levels of earnings and net cash flows, as to which no assurances can be given.
Financing for Global's projects and investments is generally provided by
non-recourse project financing transactions. These consist of loans from banks
and other lenders that are typically secured by project and special purpose
subsidiary assets and/or cash flows. Two of Power's projects currently under
construction have similar financing. Non-recourse transactions generally impose
no obligation on the parent-level investor to repay any debt incurred by the
project borrower. However, in some cases, certain obligations relating to the
investment being financed, including additional equity commitments, are
guaranteed by Global, Energy Holdings, and/or Power. Further, the consequences
of permitting a project-level default include loss of any invested equity by the
parent.
Our debt indentures and credit agreements and those of our subsidiaries
contain cross-default provisions under which a default by us or by specified
subsidiaries involving specified levels of indebtedness in other agreements
would result in a default and the potential acceleration of payment under such
indentures and credit agreements. For example, a default for a specified amount
with respect to any indebtedness of Global and Power, as set forth in various
credit agreements, including obligations in non-recourse transactions, could
cause a cross-default in one of our or our subsidiaries' credit agreements.
Such lenders, or the debt holders under any of our or our subsidiaries'
indentures, could determine that debt payment obligations may be accelerated as
a result of a cross-default. These occurrences could severely limit our
liquidity and restrict our ability to meet our debt, capital and, in extreme
cases, operational cash requirements. Any inability to satisfy required
covenants and/or borrowing conditions would have a similar impact. This would
have a material adverse effect on our financial condition, results of operations
and net cash flows, and those of our subsidiaries.
In addition, our credit agreements and those of our subsidiaries generally
contain provisions under which the lenders could refuse to advance loans in the
event of a material adverse change in the borrower's, and as may be relevant,
our, Energy Holdings', Power's or PSE&G's business or financial condition. In
the event that we or the lenders in any of our or our subsidiaries' credit
agreements determine that a material adverse change has occurred, loan funds may
not be advanced.
Some of these credit agreements also 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 our
future financial position and the level of earnings and cash flow, as to which
no assurances can be given. As part of our financial planning forecast, we
perform stress tests on our financial covenants. These tests include a
consideration of the impacts of potential asset impairments, foreign currency
fluctuations, and other items. Our current analyses and projections indicate
that, even in a worst-case scenario with respect to our investments in Argentina
and considering other potential events, we will still be able to meet our
financial covenants.
Our debt indentures and credit agreements and those of our subsidiaries do
not contain any "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 we and/or our subsidiaries may be subject
to increased interest costs on certain bank debt. Also, in connection with its
energy trading business, Power must meet certain credit quality standards as are
required by counterparties. If Power loses its investment grade credit rating,
ER&T would have to provide credit support (letters of credit or cash), which
would significantly impact the energy trading business. These same contracts
provide reciprocal benefits to Power. Global and Energy Holdings may have to
provide collateral for certain of their equity commitments if Energy Holdings'
ratings should fall below investment grade. This would increase our costs of
doing business and limit our ability to successfully conduct our energy trading
operations. In addition, our counterparties may require us to meet margin or
other security requirements which may include cash payments.
Capital resources and investment requirements could be affected by the
outcome of proceedings by the BPU pursuant to its Energy Master Plan and Energy
Competition Act and the requirements of the 1992 Focused Audit
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conducted by the BPU, of the impact of our non-utility businesses, owned by
Energy Holdings, on PSE&G. As a result of the Focused Audit, the BPU ordered
that, among other things:
(1) We will not permit Energy Holdings' investments to exceed 20% of our
consolidated assets without prior notice to the BPU;
(2) PSE&G's Board of Directors would provide an annual certification that
the business and financing plans of Energy Holdings will not adversely
affect PSE&G
(3) We will (a) limit debt supported by the minimum net worth maintenance
agreement between us and PSEG Capital to $650 million and (b) make a
good-faith effort to eliminate such support over a six to ten year
period from May 1993; and
(4) Energy Holdings will pay PSE&G an affiliation fee of up to $2 million
a year which is to be used to reduce customer rates.
In the Final Order the BPU noted that, due to significant changes in the
industry and, in particular, our corporate structure as a result of the Final
Order, modifications to or relief from the Focused Audit order might be
warranted. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt
by the end of 2003 and that it believes that the Final Order otherwise
supercedes the requirements of the Focused Audit. While we believe that this
issue will be satisfactorily resolved, no assurances can be given.
In addition, if we were no longer to be exempt under the Public Utility
Holding Company Act of 1935 (PUHCA), we and our subsidiaries would be subject to
additional regulation by the SEC with respect to financing and investing
activities, including the amount and type of non-utility investments. We believe
that this would not have a material adverse effect on our financial condition,
results of operations and net cash flows.
Over the next several years, we and our subsidiaries will be required to
refinance maturing debt, incur additional debt and provide equity to fund
investment activity. 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 affect our financial condition,
results of operations and net cash flows.
We and our subsidiaries have the following credit facilities for various
funding purposes and to provide liquidity for our $850 million commercial
program and PSE&G's $900 million commercial paper program. These agreements are
with a group of banks and provide for borrowings with maturities of up to one
year. The following table summarizes our various facilities as of December 31,
2001.
Commercial
Maturity Total Primary Amount Paper (Cp)
Company Date Facility Purpose Outstanding Outstanding
- ------------------------------------------- -------- -------- ------- ----------- -----------
(MILLIONS OF DOLLARS)
PSEG
- -------------------------------------------
364-day Credit Facility March 2002 $570 CP Support $ -- $475
5-year Credit Facility March 2002 280 CP Support -- N/A
5-year Credit Facility December 2002 150 Funding 125 N/A
Bilateral Credit Agreement N/A No Limit Funding 153 N/A
PSE&G
- -------------------------------------------
364-day Credit Facility June 2002 390 CP Support -- --
5-year Credit Facility June 2002 450 CP Support -- --
Bilateral Credit Agreement June 2002 60 CP Support -- --
Bilateral Credit Agreement N/A No Limit Funding -- N/A
Energy Holdings
- -------------------------------------------
364-day Credit Facility May 2002 200 Funding -- N/A
5-year Credit Facility May 2004 495 Funding 250 N/A
Bilateral Credit Agreement N/A 100 Funding 50 N/A
---- ----
Total N/A $578 $475
==== ====
PSEG
As of December 31, 2001, we had repurchased approximately 26.5 million
shares of Common Stock, at a cost of approximately $997 million since 1998. The
repurchased shares have primarily been
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held as treasury stock with the balance used for general corporate purposes.
Dividend payments on Common Stock were $2.16 per share and totaled
approximately $449 million and $464 million for the years ended December 31,
2001 and 2000, respectively. Our dividend rate has remained constant since 1992
in order to retain additional capital for reinvestment and to reduce the payout
ratio as earnings grow. Although we presently believe we will have adequate
earnings and cash flow in the future from our subsidiaries to maintain common
stock dividends at the current level, earnings and cash flows required to
support the dividend will become more volatile as our business continues to
change from one that is principally regulated to one that is principally
competitive. Future dividends declared will necessarily be dependent upon our
future earnings, cash flows, financial requirements, alternate investment
opportunities and other factors.
We have issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on these
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, PSEG may not pay any dividends on its common stock until such
default is cured. Currently, there has been no deferral or default.
Financial covenants contained in our facilities include the ratio of debt
(excluding non-recourse project financings and securitization debt and including
commercial paper and loans) to total capitalization. At the end of any quarterly
financial period such ratio shall not be more than .70 to 1. As of December 31,
2001, the ratio of debt to capitalization was .64 to 1.
In June 2001, $300 million of Extendible Notes, Series C matured.
In 2001, we invested $400 million in Energy Holdings and expect to make
approximately the same contribution in 2002.
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements and/or retired Mortgage Bonds
provided that its ratio of earnings to fixed charges calculated in accordance
with its Mortgage is at least 2:1. At December 31, 2001, PSE&G's Mortgage
coverage ratio was 3:1. As of December 31, 2001, the Mortgage would permit up to
approximately $1 billion aggregate principal amount of new Mortgage Bonds to be
issued against previous additions and improvements. PSE&G will need to obtain
BPU authorization to issue any incremental debt financing necessary for its
capital program, including refunding of maturing debt and opportunistic
refinancing. In January 2002, PSE&G filed a petition with the BPU for
authorization to issue $1 billion of long-term debt through December 31, 2003.
On December 27, 2001, PSE&G filed a shelf registration statement on Form
S-3 for the issuance of $1 billion of debt and tax deferred preferred
securities, which was declared effective by the SEC in February 2002.
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On January 31, 2001, $2.525 billion of transition bonds were issued by
PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of
PSE&G, in eight classes with maturities ranging from 1 year to 15 years. PSE&G
also received payment from Power on its $2.786 billion promissory note used to
finance the transfer of its generation business to Power. The proceeds from
these transactions were used to pay for certain debt issuance and related costs
for securitization, retire a portion of PSE&G's outstanding short-term debt,
reduce PSE&G's common equity, loan funds to us and make various short-term
investments.
In March 2001, PSE&G redeemed all of its $150 million of 9.375% Series A
cumulative monthly income preferred securities, all of its $75 million of 5.97%
preferred stock, $15 million of its 6.75% preferred stock and $52 million of its
floating rate notes due December 7, 2002. In June 2001, PSE&G redeemed the
remaining $248 million outstanding of floating rate notes due December 7, 2002.
In June 2001, PSE&G redeemed all of its $208 million of 8.625% Series A
cumulative quarterly income preferred securities.
In November 2001, $100 million of PSE&G Mortgage Bonds, Series FF matured.
Also in November 2001, PSE&G redeemed $105 million of its variable rate
Pollution Control Notes. In December 2001, PSE&G redeemed an additional $19
million of its variable rate Pollution Control Notes.
Since 1986, PSE&G has made regular cash payments to us in the form of
dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock
dividends of $112 million and $638 million to us for the years ended December
31, 2001 and 2000, respectively.
PSE&G has issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on those
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, PSE&G may not pay any dividends on its common or preferred stock
until such default is cured. Currently, there has been no deferral or default.
Power
Power's short-term financing needs will be met using our commercial paper
program or lines of credit discussed above. As of December 31, 2001, letters of
credit were issued in the amount of approximately $100 million.
In April 2001, Power issued $500 million of 6.875% Senior Notes due 2006,
$800 million of 7.75% Senior Notes due 2011 and $500 million 8.625% Senior Notes
due 2031. The net proceeds from the sale of the senior notes were used primarily
for the repayment of loans from us.
In August 2001, subsidiaries of Power closed on $800 million of
non-recourse project bank financing for projects in Waterford, Ohio and
Lawrenceburg, Indiana. The total combined project cost for Waterford and
Lawrenceburg is estimated at $1.2 billion. Power's required estimated equity
investment in these projects is approximately $400 million. In connection with
these projects, ER&T has entered into a five-year tolling agreement pursuant to
which it is obligated to purchase the output of these facilities at stated
prices. As a result, ER&T will bear the price risk related to the output of
these generation facilities which are scheduled to be completed in 2003.
In the fourth quarter of 2001, Power issued $124 million in Pollution
Control Notes.
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Energy Holdings
As of December 31, 2001, Energy Holdings had two separate senior revolving
credit facilities with a syndicate of banks as discussed in the table above. The
five-year facility permits up to $250 million of letters of credit to be issued
of which $57 million are outstanding as of December 31, 2001.
Financial covenants contained in these facilities include the ratio of cash
flow available for debt service (CFADS) to fixed charges. At the end of any
quarterly financial period such ratio shall not be less than 1.50x for the
12-month period then ending. As a condition of borrowing, the pro-forma CFADS to
fixed charges ratio shall not be less than 1.75x as of the quarterly financial
period ending immediately following the first anniversary of each borrowing or
letter of credit issuance. CFADS includes, but is not limited to, operating cash
before interest and taxes, pre-tax cash distributions from all asset
liquidations and equity capital contributions from us to the extent not used to
fund investing activity. In addition, the ratio of consolidated recourse
indebtedness to recourse capitalization, as at the end of any quarterly
financial period, shall not be greater than 0.60 to 1.00. This ratio is
calculated by dividing the total recourse indebtedness of Energy Holdings by the
total recourse capitalization. This ratio excludes the debt of PSEG Capital,
which is supported by us. As of December 31, 2001, the latest 12 months CFADS
coverage ratio was 4.4 and the ratio of recourse indebtedness to recourse
capitalization was .45 to 1.
PSEG Capital has a $750 million MTN program which provides for the private
placement of MTNs. This MTN program is supported by a minimum net worth
maintenance agreement between PSEG Capital and us which provides, among other
things, that we (1) maintain its ownership, directly or indirectly, of all
outstanding common stock of PSEG Capital, (2) cause PSEG Capital to have at all
times a positive tangible net worth of at least $100,000 and (3) make sufficient
contributions of liquid assets to PSEG Capital in order to permit it to pay its
debt obligations. We believe that we are capable of eliminating our support of
PSEG Capital debt within the time period set forth in the Focused Audit. In
October 2001, $135 million of 6.74% MTNS matured and were refinanced with funds
from the issuance of short-term debt at Energy Holdings. At December 31, 2001
and December 31, 2000, total debt outstanding under the MTN program was $480
million and $650 million, respectively maturing from 2002 to 2003.
In February 2001, Energy Holdings sold $400 million of 8.625% Senior Notes
due 2008 and in July 2001, sold $550 million of 8.50% Senior Notes due 2011. The
net proceeds were used to repay short-term debt outstanding from intercompany
loans and borrowings under Energy Holdings' revolving credit facilities and for
general corporate purposes.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million
due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million
(after-tax) was recorded in connection with the refinancing of the $160 million
non-recourse bank debt.
In October 2001, PSEG Chile Holdings, a wholly-owned subsidiary of Global
and a United States functional currency entity closed on $150 million of project
financing related to its investment in SAESA, a Chilean Peso functional currency
entity. The debt is variable and is based on LIBOR. In connection with this
project financing, PSEG Chile Holdings entered into two foreign currency forward
exchange contracts with a total notional amount of $150 million. The two
contracts were entered into to hedge the Peso/United States Dollar exposure on
the net investment.
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CAPITAL REQUIREMENTS
For the year ended December 31, 2001, we made net plant additions of $2.053
billion, excluding Allowance for Funds Used During Construction (AFDC) and
capitalized interest. The majority of these additions, $1.5 billion, primarily
related to Power for developing the Lawrenceburg, Indiana and the Waterford,
Ohio sites and adding capacity to the Bergen, Linden, Burlington and Kearny
stations in New Jersey. In addition, PSE&G had net plant additions of $398
million related to improvements in its transmission and distribution system, gas
system and common facilities.
Also in 2001, Energy Holdings' subsidiaries made investments totaling
approximately $1.7 billion. These investments included leveraged lease
investments totaling $460 million by Resources and new acquisitions by Global
and additional investments in existing domestic and international facilities.
Forecasted Expenditures
Our subsidiaries have substantial commitments as part of their growth
strategies and ongoing construction programs. We expect that the majority of
each subsidiaries' capital requirements over the next five years will come from
internally generated funds, with the balance to be provided by the issuance of
debt at the subsidiary or project level and equity contributions from us.
Projected construction and investment expenditures for our subsidiaries for
the next five years are as follows:
2002 2003 2004 2005 2006
(Millions of Dollars)
Power........................ $ 960 $ 700 $ 340 $ 250 $ 230
Energy Holdings.............. 450 600 600 600 600
PSE&G........................ 485 440 440 450 465
----------------------------------------------------------------------------------
Total................... $ 1,895 $ 1,740 $ 1,380 $ 1,300 $ 1,295
==================================================================================
For a discussion of new generation and development and other commitments to
purchase equipment and services, all of which are included in our forecasts
above, see Note 9. Commitments and Contingent Liabilities
Power's capital needs will be dictated by its strategy to continue to
develop as a profitable, growth-oriented supplier in the wholesale power market.
Power will size its fleet of generation assets to take advantage of market
opportunities, while seeking to increase its value and manage commodity price
risk through its wholesale energy trading activity. A significant portion of
Power's projected investment expenditures in the latter part of this forecast
are not yet committed to specific projects.
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Energy Holdings plans to continue the growth of Global and Resources. The
majority of Energy Holdings' projected investment expenditures are not yet
committed to specific projects. Investment activity is subject to periodic
review and revision and may vary significantly depending upon the opportunities
presented.
PSE&G's construction expenditures are primarily to maintain the safety and
reliability of its electric and gas transmission and distribution facilities.
Factors affecting our subsidiaries' actual expenditures and investments,
including ongoing construction programs, include: availability of capital,
suitable investment opportunities, prices of energy and supply in markets in
which we participate, economic and political trends, revised load forecasts,
business strategies, site changes, cost escalations under construction
contracts, requirements of regulatory authorities and laws, and the timing of
and amount of electric and gas transmission and/or distribution rate changes.
Disclosures about Contractual Obligations and Commercial Obligations and
Certain Investments
The following tables, reflect our and our subsidiaries' contractual cash
obligations and other commercial commitments in the respective periods in which
they are due.
Less
Total Amounts Than
Contractual Cash Obligations Committed 1 year 2 - 3 years 4 - 5 years Over 5 years
(Millions of Dollars)
------------------------------------------------------------------------------
Long - Term Debt $10,301 $1,093 $1,364 $1,622 $6,222
Capital Lease Obligations 102 8 16 16 62
Operating Leases 64 14 20 11 19
------------------------------------------------------------------------------
Total Contractual Cash Obligations $10,467 $1,115 $1,400 $1,649 $6,303
==============================================================================
We, Power, and Energy Holdings have guaranteed certain obligations of
affiliates, including the successful completion, performance or other
obligations and have contract equity contribution obligations related to certain
projects in an aggregate amount of approximately $730 million, as of December
31, 2001. A substantial portion of such guarantees is eliminated upon successful
completion, performance and/or refinancing of construction debt with
non-recourse project term debt.
In the normal course of business, Energy Technologies secures construction
obligations with performance bonds issued by insurance companies. In the event
that Energy Technologies' tangible equity falls below $100 million, Energy
Holdings would be required to provide additional support for the performance
bonds. As of December 31, 2001, Energy Technologies had tangible equity of $114
million and performance bonds outstanding of $124 million. The performance bonds
are not included in the table below.
Total Less
Amounts Than
Other Commercial Commitments Committed 1 year 2 - 3 years 4 - 5 years Over 5 years
--------- ------ ----------- ----------- ------------
(Millions of Dollars)
------------------------------------------------------------------------------
Standby Letters of Credit $159 $144 $5 $4 $ 6
Guarantees and Equity Commitments 571 428 101 - 42
------------------------------------------------------------------------------
Total Commercial Commitments $730 $572 $106 $4 $ 48
==============================================================================
Off Balance Sheet Arrangements
Global has certain investments that are accounted for under the equity
method in accordance with generally accepted accounting principles (GAAP).
Accordingly, an amount is recorded on our balance sheet which is primarily
Energy Holdings' equity investment and is increased for Energy Holdings'
pro-rata share of earnings less any dividend distribution from such investments.
The companies in which we invest that are accounted for under the equity method
have an aggregate $1.88 billion of debt on their combined, consolidated
financial statements. Our pro-rata share of such debt is $737 million and is
non-recourse to us, Energy Holdings and Global. We are generally not required to
support the debt service obligations of these companies. However, default with
respect to this non-recourse debt could result in a loss of invested equity.
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Resources has investments in leveraged leases that are accounted for in
accordance with SFAS 13 "Accounting for Leases." Leveraged lease investments
generally involve three parties: an owner/lessor, a creditor, and a lessee. In a
typical leveraged lease financing, the lessor purchases an asset to be leased.
The purchase price is typically financed 80% with debt provided by the creditor
and the balance comes from equity funds provided by Resources. The creditor
provides long term financing to the transaction, and is secured by the property
subject to lease. Such long term financing is non-recourse to Resources. As
such, in the event of default the creditor may only look to the leased asset as
security for his loan. As a lessor, Resources has ownership rights to the
property and rents the property to the lessee for use in its business operation.
As of December 31, 2001 Resources' equity investment in leased assets was
approximately $1.6 billion, net of deferred taxes of approximately $1.2 billion.
In the event that collectibility of the minimum lease payments to be
received by the lessor is no longer reasonably predictable, the accounting
treatment for some of the leases may change. In such cases, Resources may deem
that a lessee has a high probability of defaulting on the lease obligation. In
many instances, Resources has protected its equity investment in such
transactions by providing for the direct right to assume the debt obligation.
Debt assumption would be at Resources' sole discretion, and normally only would
occur if an appraisal of the leased property yielded a value that exceeds the
present value of the debt outstanding. Should Resources ever directly assume a
debt obligation, the fair value of the underlying asset and the associated debt
would be recorded on the balance sheet instead of the net equity investment in
the lease. In the events described above, the lease essentially changes from
being classified as a capital lease to a conventional operating lease.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss arising from adverse changes in foreign currency
exchange rates, commodity prices, equity security prices, and interest rates as
discussed in the notes to the financial statements. Our policy is to use
derivatives to manage risk consistent with our business plans and prudent
practices. We have a Risk Management Committee comprised of executive officers
which utilizes an independent risk oversight function to ensure compliance with
corporate policies and prudent risk management practices.
Counterparties expose us to credit losses in the event of non-performance
or non-payment. We have a credit management process which is used to assess,
monitor and mitigate counterparty exposure for us and our subsidiaries. In the
event of non-performance or non-payment by a major counterparty, there may be a
material adverse impact on our and our subsidiaries' financial condition,
results of operations or net cash flows.
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Foreign Currencies
The objective of our foreign currency risk management policy is to preserve
the economic value of cash flows in non-functional currencies. Toward this
end, Energy Holdings' policy is to hedge all significant firmly committed cash
flows identified as creating foreign currency exposure. In addition, we
typically hedge a portion of exposure resulting from identified anticipated
cash flows, providing the flexibility to deal with the variability of
longer-term forecasts as well as changing market conditions, in which the cost
of hedging may be excessive relative to the level of risk involved.
As of December 31, 2001, Global and Resources had assets located or held in
international locations of approximately $3.4 billion and $1.3 billion,
respectively.
Resources' international investments are primarily leveraged leases of
assets located in Australia, Austria, Belgium, China, Germany, the Netherlands,
the United Kingdom, and New Zealand with associated revenues denominated in
United States Dollars ($US) and therefore, not subject to foreign currency risk.
Global's international investments are primarily in companies that generate
or distribute electricity in Argentina, Brazil, Chile, China, India, Italy,
Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign
countries involves certain additional risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries are likely to result
in declining values in such countries' currencies. As currencies fluctuate
against the $US, there is a corresponding change in Global's investment value in
terms of the $US. Such change is reflected as an increase or decrease in the
investment value and Other Comprehensive Income (Loss), a separate component of
Stockholder's Equity. As of December 31, 2001, net foreign currency devaluations
have reduced the reported amount of Energy Holdings' total Stockholder's Equity
by $258 million (after-tax), of which $79 million (after-tax) was caused by
the devaluation of the Chilean Peso and $169 million (after-tax) was caused by
the devaluation of the Brazilian Real.
Global holds a 60% ownership interest in a Tunisian generation facility
under construction. The Power Purchase Agreement, signed in 1999, contains an
embedded derivative that indexes the fixed Tunisian dinar payments to United
States Dollar exchange rates. The embedded derivative is being marked to market
through the income statement. As of January 1, 2001, a $9 million gain was
recorded in the cumulative effect of accounting change for SFAS No. 133. During
2001, an additional gain of $1.4 million was recorded to the income statement as
a result of favorable movements in the United States Dollar to Tunisian dinar
exchange rate.
Global holds approximately a 32% ownership interest in RGE whose debt is
denominated in United States Dollars. In December 2001, the distribution
company entered into a series of three forward exchange contracts to purchase
United States Dollars for Brazilian Reals in order to hedge the risk of
fluctuations in the exchange rate between the two currencies associated with
the upcoming principal payments on the debt. These contracts expire in May,
June and July 2002. As of December 31, 2001, Global's share of the fair value
and aggregate notional value of the contracts was approximately $13 million.
These contracts were established as hedges for accounting purposes resulting
in an after tax charge to Other Comprehensive Income (OCI) of approximately
$1.2 million. In addition, in order to hedge the foreign currency exposure
associated with the outstanding portion of the debt, Global entered into a
forward exchange contract in December 2001 to purchase United States Dollars
for Brazilian Reals in approximately their share of the total debt outstanding
($61 million). The contract expired prior to December 31, 2001 and was not
designated as a hedge for accounting purposes. As a result of unfavorable
movements in the United States Dollars to Brazilian Real exchange rates, a
loss of $4 million, after-tax was recorded related to this derivative upon
maturity of the contract. This amount was recorded in Other Income.
Through its 50% joint venture, Meiya Power Company, Global holds a 17.5%
ownership interest in a Taiwanese generation project under construction where
the construction contractor's fees, payable in installments through July 2003,
are payable in Euros. To manage the risk of foreign exchange rate fluctuations
associated with these payments, the project entered into a series of forward
exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of
December 31, 2001, Global's share of the fair value and aggregate notional value
of these forward exchange contracts was approximately $1 million and $16
million, respectively. These forward exchange contracts were not designated as
hedges for accounting purposes, resulting in an after-tax gain of approximately
$0.5 million. In addition, after-tax gains of $1 million were recorded during
2001 on similar forward exchange contracts expiring during the year.
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During 2001, Global purchased approximately 100% of a Chilean distribution
company. In order to hedge final Chilean peso denominated payments required to
be made on the acquisition, Global entered into a forward exchange contract to
purchase Chilean Pesos for United States Dollars. This transaction did not
qualify for hedge accounting, and, as such, upon settlement of the transaction,
Global recognized an after-tax loss of $0.5 million. Furthermore, as a
requirement to obtain certain debt financing necessary to fund the acquisition,
and in order to hedge against fluctuations in the United States Dollars to
Chilean Peso foreign exchange rates, Global entered into a forward contract with
a notional value of $150 million to exchange Chilean Pesos for United States
Dollars. This transaction expires in October 2002 and is considered a hedge for
accounting purposes. As of December 31, 2001, the derivative asset value of $4
million has been recorded to OCI, net of taxes ($1.4 million). In addition,
Global holds a 50% interest in another Chilean distribution company, which was
anticipating paying its U.S. investors a return of capital. In order to hedge
the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the
distribution company entered into a forward exchange contract to purchase United
States Dollars for Chilean Pesos. Global's after-tax share of the loss on
settlement of this transaction (recorded by the distribution company) was $0.3
million.
In January 2002, RGE entered into a series of nine cross currency interest
rate swaps for the purpose of hedging its exposure to fluctuations in the
Brazilian Real to United States Dollars exchange rates with respect to its
United States Dollars denominated debt principal payments due in 2003 through
2006. The instruments convert the variable LIBOR based interest payments on
the loan balance to variable CDI based interest payments. CDI is the Brazilian
interbank interest rate. As a result, the distribution company has hedged its
foreign currency exposure but is still at risk for variability in the
Brazilian CDI interest rate during the terms of the instruments. Global's
share of the notional value of the instruments is approximately $15 million
for the instruments maturing in May, June and July of 2003 through 2005 and
approximately $19 million for the instruments maturing in May, June and July
2006. Also in January 2002, the distribution company entered into two similar
cross currency interest rate swaps to hedge the United States Dollar
denominated interest payments due on the debt in February 2002 and May 2002.
Global's share of the notional value of these two instruments is approximately
$3 million each.
Commodity Contracts
During 2001, Power entered into electric physical forward contracts and gas
futures and swaps with a maximum term of approximately one year, to hedge our
forecasted BGS requirements and gas purchases requirements for generation. These
transactions qualified for hedge accounting treatment under SFAS 133 and were
settled prior to the end of 2001. The majority of the marked-to-market
valuations were reclassified from OCI to earnings during the quarter ended
September 30, 2001. As of December 31, 2001, we did not have any outstanding
derivatives accounted for under this methodology. However, there was substantial
activity during the year ended December 31, 2001. In 2001, the values of these
forward contracts, gas futures and swaps as of June 30 and September 30 were
$(34.2) million and $(0.4) million.
Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas
futures, options and swaps to hedge forecasted requirements. As of December 31,
2001, the fair value of those instruments was $(137) million with a maximum term
of approximately one year. PSE&G utilizes derivatives to hedge its gas
purchasing activities which, when realized, are recoverable through its
Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts
are recognized at fair value as derivative assets or liabilities on the balance
sheet and the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.
We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, and the BGS auction, the VAR threshold was increased
to $75 million.
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The measured VAR using a variance/co-variance model with a 95% confidence
level and assuming a one-week time horizon as of December 31, 2001 was
approximately $18 million, compared to the December 31, 2000 level of $19
million. This estimate was driven by our assumption that Power would enter
into contracts for approximately 50% of its generating capacity during the BGS
auction. Since Power obtained contracts in excess of this amount, the VAR at
December 31, 2001 would have been even lower. This estimate, however, is not
necessarily indicative of actual results, which may differ due to the fact
that actual market rate fluctuations may differ from forecasted fluctuations
and due to the fact that the portfolio of hedging instruments may change over
the holding period and due to certain assumptions embedded in the calculation.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of
fluctuating interest rates in the normal course of business. Their policy is to
manage interest rate risk through the use of fixed rate debt, floating rate
debt, interest rate swaps and interest rate lock agreements. As of December 31,
2001, a hypothetical 10% change in market interest rates would result in a $3
million, $4 million, and $2 million, change in annual interest costs related to
short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings,
respectively. The following table shows details of the interest rate swaps at
PSEG, PSE&G, Power and Energy Holdings and their associated values that are
still open at December 31, 2001:
Total Fair Other
Project Notional Pay Receive Market Comprehensive
Underlying Securities Percent Amount Rate Rate Value Income
- -------------------------------------------------------------------------------------------------------------------
PSEG:
Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0)
Securities
PSE&G:
Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ -
Power:
Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3
Energy Holdings:
Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7)
Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6)
Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5)
Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3)
Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7)
Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2)
Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7)
Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9)
----------- ---------- -------------- --------------------------
Total Energy Holdings $590.4 $(73.1) $(29.6)
----------- ---------- -------------- --------------------------
Total PSEG $1,414.9 $(94.4) $(31.3)
=========== ========== ============== ==========================
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
We expect to reclass approximately $14.0 million of open interest rate
swaps from OCI to earnings during the next twelve months. As of December 31,
2001, there was a $31.3 million balance remaining in the Accumulated Other
Comprehensive Loss Account, as indicated in the table above.
We have also entered into several interest rate swaps that were closed out
during 2001 and are being amortized to earnings over the life of the underlying
debt. These items, along with their current and anticipated effect on earnings
discussed below.
In February 2001, we entered into various forward-interest rate swaps, with
an aggregate notional amount of $400 million, to hedge the interest rate risk
related to the anticipated issuance of debt. On April 11, 2001, Power issued
$1.8 billion in fixed-rate Senior Notes and closed out the forward starting
interest rate swaps. The aggregate loss, net of tax, of $3.2 million was
classified as Accumulated Other Comprehensive Loss and is being amortized and
charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects it will amortize approximately $0.8 million from
OCI to earnings during the next twelve months.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million
due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million
(after-tax) was recorded in connection with the refinancing of the $160 million
non-recourse bank debt.
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Equity Securities
Resources has investments in equity securities and limited partnerships.
Resources carries its investments in equity securities at their approximate fair
value as of the reporting date. Consequently, the carrying value of these
investments is affected by changes in the fair value of the underlying
securities. Fair value is determined by adjusting the market value of the
securities for liquidity and market volatility factors, where appropriate. The
aggregate fair values of such investments, which had quoted market prices at
December 31, 2001 and December 31, 2000 were $34 million and $115 million,
respectively. The potential change in fair value resulting from a hypothetical
10% change in quoted market prices of these investments amounted to $3 million
and $9 million at December 31, 2001 and December 31, 2000, respectively.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We have established credit policies that we believe significantly
minimize credit risk. These policies include an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances and the use of standardized agreements,
which may allow for the netting of positive and negative exposures associated
with a single counterparty.
As a result of the BGS auction, Power has contracted to provide generating
capacity to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. These bilateral contracts are subject to
credit risk. This credit risk relates to the ability of counterparties to meet
their payment obligations for the power delivered under each BGS contract. This
risk is substantially higher than the risk associated with potential nonpayment
by PSE&G under the BGS contract expiring July 31, 2002 since PSE&G is a
rate-regulated entity. Any failure to collect these payments under the new BGS
contracts could have a material impact on our results of operations, cash flows,
and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of
energy trading contracts with Enron and its affiliates in the Pennsylvania-New
Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities.
We took proper steps to mitigate our exposures to both Enron and other
counterparties who could have been affected by Enron. As of December 31, 2001,
we owed Enron approximately $23 million, net, and Enron held a letter of credit
from Power for approximately $40 million.
As a result of the California Energy Crisis, Pacific Gas & Electric Company
(PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April
16, 2001. GWF, Hanford and Tracy had combined pre-petition receivables due from
PG&E, for all plants amounting to approximately $62 million. Of this amount,
approximately $25 million had been reserved as an allowance for doubtful
accounts resulting in a net receivable balance of approximately $37 million.
Global's pro-rata share of this gross receivable and net receivable was
approximately $30 million and $18 million, respectively.
In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E
which stipulates that PG&E will make full payment of the $62 million in 12 equal
installments, including interest by the end of 2002. On December 31, 2001, PG&E
paid GWF $8 million, representing the initial installment payment and all
accrued interest due, pursuant to the agreement.
As of December 31, 2001, GWF, Hanford and Tracy still had combined
pre-petition receivables due from PG&E for all plants amounting to approximately
$57 million. Global's pro-rata share of this receivable was $27 million. As a
result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25
million which increased operating income by $25 million (of which Global's share
was $11 million).
FOREIGN OPERATIONS
As of December 31, 2001, Global and Resources had approximately $3.4
billion and $1.3 billion, respectively, of international assets. As of December
31, 2001, foreign assets represented 19% of our consolidated assets and the
revenues related to those foreign assets contributed 4% to consolidated revenues
for the year ended December 31, 2001. For discussion of foreign currency risk
and potential asset impairments related to our investments in Argentina, see the
above discussion in Qualitative and Quantitive Disclosures About Market Risk and
Note 9. Commitments and Contingent Liabilities and Note 17. Subsequent Events of
Notes.
ACCOUNTING ISSUES
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of: SFAS
No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) for
PSE&G, our regulated
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transmission and distribution business; Emerging Issues Task Force (EITF) 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) and EITF 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent" (EITF 99-19), for our Energy Trading business; and SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities", as
amended (SFAS 133), to account for the various hedging transactions, and SFAS
52, "Foreign Currency Translation" and its impacts on Global's foreign
investments.
Accounting for the Effects of Regulation
PSE&G prepares its financial statements in accordance with the provisions
of SFAS No. 71, which differs in certain respects from the application of GAAP
by non-regulated businesses. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated utility is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if
it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, PSE&G has
deferred certain costs, which will be amortized over various future periods. To
the extent that collection of such costs or payment of liabilities is no longer
probable as a result of changes in regulation and/or PSE&G's competitive
position, the associated regulatory asset or liability is charged or credited to
income.
As a result of New Jersey deregulation legislation and regulatory orders
issued by the BPU, certain regulatory assets and liabilities were recorded. The
amortization of two of these regulatory liabilities will have a significant
effect on our annual earnings. They include the estimated amount of MTC revenues
to be collected in excess of the authorized amount of $540 million and the
amount of excess electric distribution depreciation reserves. The amount of
these regulatory liabilities will be amortized to earnings over the four-year
transition period from August 1, 1999 through July 31, 2003.
The MTC was authorized by the BPU as an opportunity to recover up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on a
net present value basis. As a result of the appellate reviews of the Final
Order, PSE&G's securitization transaction was delayed until the first quarter of
2001, causing a delay in the implementation of the Securitization Transition
Charge (STC) which would have reduced the MTC. As a result, MTC was being
recovered at a faster rate than intended under the Final Order and a significant
overrecovery was probable. In order to properly recognize the recovery of the
allowed unsecuritized stranded costs over the transition period, PSE&G recorded
a regulatory liability and Power recorded a charge to net income of $88 million,
pre-tax, or $52 million, after tax, in the third quarter of 2000 for the
cumulative amount of estimated collections in excess of the allowed
unsecuritized stranded costs from August 1, 1999 through September 30, 2000.
PSE&G then began deferring a portion of these revenues each month to recognize
the estimated collections in excess of the allowed unsecuritized stranded costs.
As of December 31, 2001, this deferred amount was $168 million and is aggregated
with the Societal Benefits Clause. After deferrals, pre-tax MTC revenues
recognized were $220 million in 1999, $239 million in 2000, and $196 million
in 2001. In 2002 and 2003, we expect to record approximately $90 million and
$121 million, respectively.
The amortization of the Excess Depreciation Reserve is another significant
regulatory liability affecting our earnings. As required by the BPU, PSE&G
reduced its depreciation reserve for its electric distribution assets by $569
million and recorded such amount as a regulatory liability to be amortized over
the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million
was amortized and recorded as a reduction of depreciation expense pursuant to
the Final Order. The remaining $319 million will be amortized through July 31,
2003.
See Note 4. Regulatory Assets and Liabilities of Notes for further
discussion of these and other regulatory issues.
Accounting, Valuation and Presentation of Our Energy Trading Business
Accounting - We account for our energy trading business in accordance with
the provisions of EITF Issue No. 98-10 which requires that energy trading
contracts be marked to market with gains and losses included in current
earnings.
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Valuation - Since the vast majority of our energy trading contracts have
terms of less than one year, valuations for these contracts are readily
obtainable from the market exchanges, such as PJM, and over the counter
quotations. The valuations also include a credit reserve and a liquidity
reserve, which is determined using financial quotation systems, monthly bid-ask
prices and spread percentages. We have consistently applied this valuation
methodology for each reporting period presented. The fair values of these
contracts and a more detailed discussion of credit risk are reflected in Note 8.
Financial Instruments, Energy Trading and Risk Management.
Presentation - EITF 99-19 provided guidance on the issue of whether a
company should report revenue based on the gross amount billed to the customer
or the net amount retained. The guidance states that whether a company should
recognize revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We report swaps,
futures, option premiums, firm transmission rights, transmission congestion
credits, and purchases and sales of emission allowances on a net basis. The
prior year financial statements have been reclassified accordingly. One of the
primary drivers of our determination that these contracts should be presented on
a gross basis was that we retain counterparty risk.
SFAS 133 - Accounting for Derivative Instruments and Hedging Activities
SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in OCI, net of tax, or as a Regulatory Asset (Liability). Amounts in
accumulated OCI are ultimately recognized in earnings when the related hedged
forecasted transaction occurs. The change in the fair value of the ineffective
portion of the derivative instrument designated as a cash flow hedge is recorded
in earnings. Derivative instruments that have not been designated as hedges are
adjusted to fair value through earnings. We have entered into several derivative
instruments, including hedges of anticipated electric and gas purchases,
interest rate swaps and foreign currency hedges which have been designated as
cash flow hedges.
The fair value of the derivative instruments is determined by reference to
quoted market prices, listed contracts, published quotations or quotations from
counterparties. In the absence thereof, we utilize mathematical models based on
current and historical data. The fair value of most of our derivatives is
determined based upon quoted market prices. Therefore, the effect on earnings of
valuations from our models is minimal.
For additional information regarding Derivative Financial Instruments, See
Note 8 - Financial Instruments, Energy Trading and Risk Management - Derivative
Instruments and Hedging Activities of Notes.
SFAS 52 - Foreign Currency Translation
Our financial statements are prepared using the United States Dollar as the
reporting currency. In accordance with SFAS 52 "Foreign Currency Translation",
foreign operations whose functional currency is deemed to be the local (foreign)
currency, asset and liability accounts are translated into United States Dollars
at current exchange rates and revenues and expenses are translated at average
exchange rates prevailing during the period. Translation gains and losses (net
of applicable deferred taxes) are not included in determining net income but are
reported in other comprehensive income. Gains and losses on transactions
denominated in a currency other than the functional currency are included in the
results of operations as incurred.
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The determination of an entity's functional currency requires management's
judgment. It is based on an assessment of the primary currency in which
transactions in the local environment are conducted, and whether the local
currency can be relied upon as a stable currency in which to conduct business.
As economic and business conditions change, we are required to reassess the
economic environment and determine the appropriate functional currency. The
impact of foreign currency accounting could have a material adverse impact on
our financial condition, results of operation and net cash flows.
Other Accounting Issues
For additional information on our accounting policies and the
implementation of recently issued accounting standards, see Note 1. Organization
and Summary of Significant Accounting Policies and Note 2. Accounting Matters of
Notes, respectively.
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, 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
"will", "anticipate", "intend", "estimate", "believe", "expect", "plan",
"hypothetical", "potential", variations of such words and similar expressions
are intended to identify forward-looking statements. We 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 of factors
should not be construed as exhaustive or as any admission regarding the adequacy
of our disclosures prior to the effective date of the Private Securities
Litigation Reform Act of 1995.
In addition to any assumptions and other factors referred to specifically
in connection with such forward-looking statements, factors that could cause
actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o because a portion of our business is conducted outside the United
States, adverse international developments could negatively impact our
business;
o credit, commodity, and financial market risks may have an adverse
impact;
o energy obligations, available supply and trading risks may have an
adverse impact;
o the electric industry is undergoing substantial change;
o generation operating performance may fall below projected levels;
o ability to obtain adequate and timely rate relief;
o we and our subsidiaries are subject to substantial competition from
well capitalized participants in the worldwide energy markets;
o our ability to service debt could be limited;
o if our operating performance or cash flow from minority interests
falls below projected levels, we may not be able to service our debt;
o power transmission facilities may impact our ability to deliver our
output to customers;
o government regulation affects many of our operations;
o environmental regulation significantly impacts our operations;
o we are subject to more stringent environmental regulation than many of
our competitors;
o insurance coverage may not be sufficient;
o acquisition, construction and development may not be successful; and
o recession, acts of war or terrorism could have an adverse impact.
64
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ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to quantitative and qualitative disclosures about
market risk is set forth under the caption "Qualitative and Quantitative
Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations. Such information is
incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
65
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, except for Per Share Data)
For The Years Ended December 31,
-------------------------------------------------
2001 2000 1999
-------------- ------------- ------------
OPERATING REVENUES
Electric $ 4,156 $ 3,837 $ 4,081
Gas 2,293 2,140 1,717
Trading 2,403 2,724 1,842
Other 963 794 687
------- ------- -------
Total Operating Revenues 9,815 9,495 8,327
OPERATING EXPENSES
Electric Energy Costs 1,119 960 922
Gas Costs 1,596 1,471 1,107
Trading Costs 2,256 2,647 1,800
Operation and Maintenance 2,264 1,984 1,903
Depreciation and Amortization 522 362 536
Taxes Other Than Income Taxes 166 182 196
------- ------- -------
Total Operating Expenses 7,923 7,606 6,464
------- ------- -------
OPERATING INCOME 1,892 1,889 1,863
Other Income and Deductions 21 33 7
Interest Expense-net (705) (574) (490)
Preferred Securities Dividend Requirements
and Premium on Redemption (72) (94) (94)
------- ------- -------
INCOME BEFORE INCOME TAXES,
EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 1,136 1,254 1,286
Income Taxes (373) (490) (563)
------- ------- -------
INCOME BEFORE EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 763 764 723
Extraordinary Item (net of tax - 2001, $1; 1999, $345) (2) - (804)
Cumulative Effect of a Change in Accounting Principle
(net of tax) 9 - -
------- ------- -------
NET INCOME (LOSS) $ 770 $ 764 $ (81)
======= ======= =======
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING (000's) 208,226 215,121 219,814
======= ======= =======
EARNINGS PER SHARE (BASIC AND DILUTED):
INCOME BEFORE EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE $ 3.67 $ 3.55 $ 3.29
Extraordinary Item (net of tax) (0.01) - (3.66)
Cumulative Effect of a Change in Accounting Principle
(net of tax) 0.04 - -
------- ------- -------
NET INCOME (LOSS) $ 3.70 $ 3.55 $ (0.37)
======= ======= =======
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 2.16 $ 2.16 $ 2.16
======= ======= =======
See Notes to Consolidated Financial Statements.
66
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
December 31,
-----------------------------------
2001 2000
--------------- -------------
CURRENT ASSETS
Cash and Cash Equivalents $ 169 $ 102
Accounts Receivable:
Customer Accounts Receivable 824 778
Other Accounts Receivable 348 431
Allowance for Doubtful Accounts (43) (44)
Unbilled Electric and Gas Revenues 291 357
Fuel 509 431
Materials and Supplies 174 155
Prepayments 74 31
Energy Trading Contracts 454 799
Restricted Cash 13 1
Assets held for Sale 422 48
Other 24 50
--------------- -------------
Total Current Assets 3,259 3,139
--------------- -------------
PROPERTY, PLANT AND EQUIPMENT
Generation 4,884 2,860
Transmission and Distribution 9,500 8,479
Other 502 608
--------------- -------------
Total 14,886 11,947
Accumulated depreciation and amortization (4,822) (4,266)
--------------- -------------
Net Property, Plant and Equipment 10,064 7,681
--------------- -------------
NONCURRENT ASSETS
Regulatory Assets 5,220 4,995
Long-Term Investments, net of accumulated amortization
and net of valuation allowances - 2001, $30; 2000, $72 4,818 4,545
Nuclear Decommissioning Fund 817 716
Other Special Funds 222 122
Goodwill, net of accumulated amortization 649 78
Other, net of accumulated amortization 348 250
--------------- -------------
Total Noncurrent Assets 12,074 10,706
--------------- -------------
TOTAL ASSETS $ 25,397 $ 21,526
=============== =============
See Notes to Consolidated Financial Statements.
67
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
December 31,
------------------------------------
2001 2000
--------------- ---------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,213 $ 667
Commercial Paper and Loans 1,338 2,885
Accounts Payable 790 1,001
Energy Trading Contracts 602 730
Other 751 429
--------------- ---------------
Total Current Liabilities 4,694 5,712
--------------- ---------------
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 3,205 3,107
Regulatory Liabilities 373 470
Nuclear Decommissioning 817 716
OPEB Costs 476 448
Cost of Removal 146 157
Other 488 415
--------------- ---------------
Total Noncurrent Liabilities 5,505 5,313
--------------- ---------------
COMMITMENTS AND CONTINGENT LIABILITIES - -
--------------- ---------------
CAPITALIZATION:
LONG-TERM DEBT 10,301 5,297
--------------- ---------------
SUBSIDIARIES' PREFERRED SECURITIES:
Preferred Stock Without Mandatory Redemption 80 95
Preferred Stock With Mandatory Redemption - 75
Guaranteed Preferred Beneficial Interest in Subordinated Debentures 680 1,038
--------------- ---------------
Total Subsidiaries' Preferred Securities 760 1,208
--------------- ---------------
COMMON STOCKHOLDERS' EQUITY:
Common Stock, issued; 2001 and 2000, 231,957,608 shares 3,599 3,604
Treasury Stock, at cost; 2001 - 26,118,590 shares,
2000 - 23,986,290 shares (981) (895)
Retained Earnings 1,809 1,493
Accumulated Other Comprehensive Loss (290) (206)
--------------- ---------------
Total Common Stockholders' Equity 4,137 3,996
--------------- ---------------
Total Capitalization 15,198 10,501
--------------- ---------------
TOTAL LIABILITIES AND CAPITALIZATION $ 25,397 $ 21,526
=============== ==============
See Notes to Consolidated Financial Statements.
68
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
For the Years Ended December 31,
-------------------------------------------------
2001 2000 1999
------------ ------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 770 $ 764 $ (81)
Adjustments to reconcile net income (loss) to net cash flows from
operating activities:
Extraordinary Loss - net of tax 2 - 804
Depreciation and Amortization 522 362 536
Amortization of Nuclear Fuel 99 96 92
Recovery (Deferral) of Electric Energy and Gas Costs - net (86) 16 61
Excess Unsecuritized Stranded Costs 54 115 -
Provision for Deferred Income Taxes and ITC - net (179) (11) (215)
Investment Distributions 73 56 134
Equity Income from Partnerships (107) (28) (53)
Unrealized Gains on Investments (67) (39) (63)
Leasing Activities (7) 74 6
Proceeds from Sale of Capital Leases 104 89 125
Proceeds from Withdrawal/Sale of Partnerships 75 - 71
Net Changes in certain current assets and liabilities:
Inventory - Fuel and Materials and Supplies (84) (145) 9
Accounts Receivable and Unbilled Revenues 272 (299) (236)
Prepayments (40) 8 8
Accounts Payable (406) 260 57
Other Current Assets and Liabilities 511 (47) 59
Other (164) (42) 114
------------ ------------- -------------
Net Cash Provided By Operating Activities 1,342 1,229 1,428
------------ ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, excluding IDC and AFDC (2,053) (959) (582)
Net Change in Long-Term Investments (709) (678) (1,127)
Acquisitions, Net of Cash Provided (756) (14) (49)
Other (260) (53) (70)
------------ ------------- -------------
Net Cash Used In Investing Activities (3,778) (1,704) (1,828)
------------ ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt (1,512) 913 916
Issuance of Long-Term Debt 6,317 1,200 1,143
Redemption/Purchase of Long-Term Debt (1,292) (1,033) (676)
Redemption of Preferred Securities (448) - -
Purchase of Treasury Stock (91) (298) (400)
Cash Dividends Paid on Common Stock (449) (464) (474)
Other (22) - 11
------------ ------------- -------------
Net Cash Provided By (Used In) Financing Activities 2,503 318 520
------------ ------------- -------------
Net Change In Cash And Cash Equivalents 67 (157) 120
Cash And Cash Equivalents At Beginning Of Period 102 259 139
------------ ------------- -------------
Cash And Cash Equivalents At End Of Period $ 169 $ 102 $ 259
============ ============= =============
Income Taxes Paid $ 87 $ 485 $ 534
Interest Paid $ 700 $ 550 $ 494
See Notes to Consolidated Financial Statements.
69
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(Millions)
Common Treasury
Stock Stock
------------------- ----------------------
Shs. Amount Shs. Amount
------- ---------- ------- -----------
BALANCE AS OF JANUARY 1, 1999 232 3,603 (5) (207)
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(17) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (11) (400)
Other - 1 - 10
------------------- ----------------------
BALANCE AS OF DECEMBER 31, 1999 232 3,604 (16) (597)
------------------- ----------------------
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (8) (298)
------------------- ----------------------
BALANCE AS OF DECEMBER 31, 2000 232 $ 3,604 (24) $ (895)
------------------- ----------------------
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) - - - -
Change in Fair Value of Derivative Instruments, net of tax $(31)
and minority interest $(6) - - - -
Cumulative Effect of Change in Accounting Principle net of tax $(14) - - - -
Reclassification Adjustments for Net Amounts included in Net Income,
net of tax of $19 and minority interest of $3 - - - -
Pension Adjustments, net of tax $(1) - - - -
Change in Fair Value of Equity Investments, net of tax $(1) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (2) (92)
Other - (5) - 6
=================== ======================
BALANCE AS OF DECEMBER 31, 2001 232 $ 3,599 (26) $ (981)
=================== ======================
Accumulated
Other
Retained Comprehensive
Earnings Income (Loss) Total
------------ ----------------- ------------
Balance as of January 1, 1999 1,748 (46) 5,098
Net Income (Loss) (81) - (81)
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(17) - (158) (158)
------------
Other Comprehensive Income (Loss) - - (158)
------------
Comprehensive Income (Loss) - - (239)
Cash Dividends on Common Stock (474) - (474)
Purchase of Treasury Stock - - (400)
Other - - 11
------------ ----------------- ------------
Balance as of December 31, 1999 1,193 (204) 3,996
------------ ----------------- ------------
Net Income (Loss) 764 - 764
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) - (2) (2)
------------
Other Comprehensive Income (Loss) - - (2)
------------
Comprehensive Income (Loss) - - 762
Cash Dividends on Common Stock (464) - (464)
Purchase of Treasury Stock - - (298)
------------ ----------------- ------------
Balance as of December 31, 2000 $1,493 $ (206) $3,996
------------ ----------------- ------------
Net Income (Loss) 770 - 770
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) - (34) (34)
Change in Fair Value of Derivative Instruments, net of tax $(31)
and minority interesf $(6) - (57) (57)
Cumulative Effect of Change in Accounting Principle net of tax $(14) - (15) (15)
Reclassification Adjustments for Net Amounts included in Net Income,
net of tax of $19 and minority interest of $3 - 26 26
Pension Adjustments, net of tax $(1) - (2) (2)
Change in Fair Value of Equity Investments, net of tax $(1) - (2) (2)
------------
Other Comprehensive Income (Loss) - - (84)
------------
Comprehensive Income (Loss) - - 686
Cash Dividends on Common Stock (449) - (449)
Purchase of Treasury Stock - - (92)
Other (5) - (4)
------------ ----------------- ------------
Balance as of December 31, 2001 $1,809 $ (290) $4,137
============ ================= ============
See Notes to Consolidated Financial Statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
Organization
We have four principal direct wholly-owned subsidiaries: Public Service
Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings
Inc. (Energy Holdings) and PSEG Services Corporation (Services).
PSE&G is an operating public utility providing electric and gas service in
certain areas within the State of New Jersey. Following the transfer of its
generation-related assets to Power in August 2000, PSE&G continues to own and
operate its transmission and distribution business.
Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear
LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC
(ER&T) and currently operates in two reportable segments, generation and energy
trading. Power and its subsidiaries were established to acquire, own and operate
the electric generation-related business of PSE&G pursuant to the Final Decision
and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU)
under the New Jersey Electric Discount and Energy Competition Act (Energy
Competition Act) discussed below. Power also has a finance company subsidiary,
PSEG Power Capital Investment Co. (Power Capital), which provides certain
financing for Power's subsidiaries.
Energy Holdings participates in three energy-related reportable segments
through its wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources
Inc. (Resources) and PSEG Energy Technologies Inc. (Energy Technologies). Energy
Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital)
and is also the parent of Enterprise Group Development Corporation (EGDC), a
commercial real estate property management business, and is conducting a
controlled exit from this business.
Services provides management and administrative services at cost to us and
our subsidiaries.
Summary of Significant Accounting Policies
Consolidation
Our consolidated financial statements include our accounts and those of our
subsidiaries. We and our subsidiaries consolidate those entities in which we
have a controlling interest. Those entities in which we and our subsidiaries do
not have a controlling interest are being accounted for under the equity method
of accounting. For investments in which significant influence does not exist,
the cost method of accounting is applied. All significant intercompany accounts
and transactions are eliminated in consolidation.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Regulation
PSE&G prepares its financial statements in accordance with the provisions
of Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for
Effects of Certain Types of Regulation" (SFAS 71). In general, SFAS 71
recognizes that accounting for rate-regulated enterprises should reflect the
economic effects of regulation. As a result, a regulated utility is required to
defer the recognition of costs (a regulatory asset) or the recognition of
obligations (a regulatory liability) if it is probable that, through the
rate-making process, there will be a corresponding increase or decrease in
future rates. Accordingly, PSE&G has deferred certain costs and recoveries,
which will be amortized over various future periods. To the extent that
collection of such costs or payment of liabilities is no longer probable as a
result of changes in regulation and/or PSE&G's competitive position, the
associated regulatory asset or liability is charged or credited to income.
PSE&G's transmission and distribution business continues to meet the
requirements for application of SFAS 71.
Derivative Financial Instruments
We use derivative financial instruments to manage our risk from changes in
interest rates, commodity prices and foreign currency exchange rates, pursuant
to its business plans and prudent practices.
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended (SFAS 133). SFAS 133 established
accounting and reporting standards for derivative instruments, including certain
derivative instruments included in other contracts, and for hedging activities.
It requires an entity to recognize the fair value of derivative instruments held
as assets or liabilities on the balance sheet. For cash flow hedging purposes,
changes in the fair value of the effective portion of the gain or loss on the
derivative are reported in Other Comprehensive Income (OCI) or as a Regulatory
Asset (Liability), net of tax. Amounts in accumulated OCI are ultimately
recognized in earnings when the related hedged forecasted transaction occurs.
The change in the fair value of the ineffective portion of the gain or loss on a
derivative instrument designated as a cash flow hedge is recorded in earnings.
Derivative instruments that have not been designated as hedges are adjusted to
fair value through earnings. We recorded a cumulative effect in a change in
accounting principle of $9 million, net of tax and a decrease to OCI of ($15)
million, respectively, in connection with the adoption of SFAS 133.
The fair value of the derivative instruments is determined by reference to
quoted market prices, listed contracts, published quotations or quotations from
counterparties. In the absence thereof, we utilize mathematical models based on
current and historical data.
Prior to the adoption of SFAS 133, we accounted for the results of our
derivative activities for hedging purposes utilizing the settlement method. The
settlement method provided for recognizing gains or losses from derivatives when
the related physical transaction was completed. Derivatives that were not
entered into for hedging purposes were valued at fair value and changes in fair
value were recorded in earnings.
For additional information regarding Derivative Financial Instruments, See
Note 8. Financial Instruments, Energy Trading and Risk Management.
Commodity Contracts
PSE&G enters into natural gas commodity forwards, futures, swaps and
options with counterparties to reduce exposure to price fluctuations from
factors such as weather, changes in demand and changes in supply. These
instruments, in conjunction with physical gas supply contracts, are designed to
cover estimated gas customer commitments. In accordance with SFAS 133, such
energy contracts are recognized at fair value as
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
derivative assets or liabilities on the balance sheet. These derivatives, when
realized, are recoverable through the Levelized Gas Adjustment Clause (LGAC).
Accordingly, the offset to the change in fair value of these derivatives is
specified as a regulatory asset or liability.
Power enters into electricity forward purchases and natural gas commodity
futures and swaps with counterparties to manage exposure to electricity and
natural gas price risk. These contracts, in conjunction with owned electric
generating capacity, are designed to manage price risk exposure for electric
customer commitments. In accordance with SFAS 133, such energy contracts are
recognized at fair value as derivative assets or liabilities on the balance
sheet and the effective portion of the gain of loss on the contracts is reported
in OCI, net of tax. Amounts in accumulated OCI are ultimately recognized in
earnings when the related hedged forecasted transaction occurs.
Power also enters into forwards, futures, swaps and options as part of its
energy trading operations. Effective January 1, 1999, Power adopted Emerging
Issues Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires
that energy trading contracts be marked to market with gains and losses included
in current earnings.
The vast majority of these commodity-related contracts have terms of less
than one year. Valuations for these contracts are readily obtainable from the
market exchanges, such as PJM, and over the counter quotations. The fair value
of the financial instruments that are marked to market are based on management's
best estimates. The valuations also take into account a liquidity reserve, which
is determined by using financial quotation systems, monthly bid-ask prices and
spread percentages. The valuations also take into account credit reserves,
discussed in Note 8. Financial Instruments, Energy Trading and Risk Management -
Credit Risk. We have consistently applied this valuation methodology for each
reporting period presented.
In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), provided guidance on the issue of whether a
company should report revenue based on the gross amount billed to the customer
or the net amount retained. The guidance states that whether a company should
recognize revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We continue to
report swaps, futures, option premiums, firm transmission rights, transmission
congestion credits, and purchases and sales of emission allowances on a net
basis. The prior year financial statements have been reclassified accordingly.
For additional information regarding commodity-related contracts, See Note
8 - Financial Instruments, Energy Trading and Risk Management.
Revenues and Fuel Costs
Electric and Gas Revenues are recorded based on services rendered to
customers during each accounting period. PSE&G records unbilled revenues for the
estimated amount customers will be billed for services rendered from the time
meters were last read to the end of the respective accounting period.
Prior to August 1, 1999, fuel revenue and expense flowed through the
Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel
revenues and expenses were subject to deferral accounting and had no direct
effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause
(LGAC), any LEAC and
73
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
LGAC underrecoveries or overrecoveries, together with interest (in the case of
net overrecoveries), are deferred and included in operations in the period in
which they are reflected in rates. Following the transfer of generation-related
assets and liabilities in August 2000, Power bears the full risks and rewards of
changes in nuclear and fossil generating fuel costs and replacement power costs.
Cash and Cash Equivalents
Cash and cash equivalents consists primarily of working funds and highly
liquid marketable securities (commercial paper and money market funds) with an
original maturity of three months or less.
Restricted Cash
Transition Funding has deposited funds with a Trustee which are required to
be used for payment of principal, interest and other expenses related to its
transition bonds (see Note 3. Regulatory Issues and Accounting Impacts of
Deregulation). Accordingly, these funds are classified as "Restricted Cash" on
our Consolidated Balance Sheets
Materials and Supplies and Nuclear Fuel
PSE&G's materials and supplies are carried on the books at average cost in
accordance with rate based regulation. The carrying value of the materials and
supplies and nuclear fuel for our non-utility subsidiaries is valued at lower of
cost or market.
Depreciation and Amortization
PSE&G calculates depreciation under the straight-line method based on
estimated average remaining lives of the several classes of depreciable
property. These estimates are reviewed on a periodic basis and necessary
adjustments are made as approved by the BPU. The depreciation rate stated as a
percentage of original cost of depreciable property was 3.32% for 2001 and 3.52%
for 2000 and 1999. PSE&G has certain regulatory assets and liabilities resulting
from the use of a level of depreciation expense in the ratemaking process that
differs from the amount that is recorded under generally accepted accounting
principles (GAAP) for non-regulated companies.
Power calculates depreciation on generation-related assets based on the
assets' estimated useful lives determined based on planned operations, rather
than using depreciation rates prescribed by the BPU in rate proceedings. The
estimated useful lives are from 3 years to 20 years for general plant. The
estimated useful lives for buildings and generating stations are as follows:
Class of Property Estimated Useful Life
----------------- ---------------------
Fossil Production 25-55 years
Nuclear Generation 30 years
Pumped Storage 45 years
Nuclear fuel burnup costs are charged to fuel expense on a
units-of-production basis over the estimated life of the fuel. Rates for the
recovery of fuel used at all nuclear units include a provision of one mill per
kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs.
Energy Holdings calculates depreciation on property, plant and equipment
under the straight line method with estimated useful lives from 3 years to 40
years.
74
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Unamortized Loss on Reacquired Debt and Debt Expense
Bond issuance costs and associated premiums and discounts are generally
amortized over the life of the debt issuance. In accordance with Federal Energy
Regulatory Commission (FERC) regulations, PSE&G's costs to reacquire debt are
deferred and amortized over the remaining original life of the retired debt.
When refinancing debt, the unamortized portion of the original debt issuance
costs of the debt being retired must be amortized over the life of the
replacement debt. Gains and losses on reacquired debt associated with PSE&G's
regulated operations will continue to be deferred and amortized to interest
expense over the period approved for ratemaking purposes. For our non-utility
subsidiaries, all gains and losses on reacquired debt are reflected in earnings
as an extraordinary item.
Allowance for Funds Used During Construction (AFDC) and Interest
Capitalized During Construction (IDC)
AFDC represents the cost of debt and equity funds used to finance the
construction of new utility assets under the guidance of SFAS 71. The amount of
AFDC capitalized was reported in the Consolidated Statements of Income as a
reduction of interest charges. The rates used for calculating AFDC in 2001, 2000
and 1999 were 6.71%, 6.45% and 5.29%, respectively. Effective April 1, 1999,
AFDC was no longer used for any capital projects related to our generation
assets. Interest related to these capital projects is now capitalized in
accordance with SFAS No. 34, "Capitalization of Interest Cost." In 2001, 2000
and 1999, AFDC amounted to $2 million, $1 million and $3 million, respectively.
IDC represents the cost of debt used to finance the construction of
non-utility facilities. The amount of IDC capitalized is reported in the
Consolidated Statements of Income as a reduction of interest charges. The
weighted average rates used for calculating IDC in 2001 and 2000 were 7.98% and
9.98%, respectively. In 2001, 2000 and 1999, IDC amounted to $80 million, $35
million and $13 million, respectively.
Income Taxes
We and our subsidiaries file a consolidated Federal income tax return and
income taxes are allocated to our subsidiaries based on the taxable income or
loss of each subsidiary. Investment tax credits were deferred in prior years and
are being amortized over the useful lives of the related property.
Property, Plant and Equipment
PSE&G's additions to plant, property and equipment and replacements that
are either retirement units or property record units are capitalized at original
cost. The cost of maintenance, repair and replacement of minor items of property
is charged to appropriate expense accounts. At the time units of depreciable
property are retired or otherwise disposed, the original cost adjusted for net
salvage value is charged to accumulated depreciation.
Our non-regulated subsidiaries only capitalize costs which increase the
capacity or extend the life of an existing asset, represent a newly acquired or
constructed asset or represent the replacement of a retired asset. The cost of
maintenance, repair and replacement of minor items of property is charged to
appropriate expense accounts.
Environmental costs are capitalized if the costs mitigate or prevent future
environmental contamination or if the costs improve existing assets'
environmental safety or efficiency. All other environmental expenditures are
expensed.
75
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Assets Held For Sale
For a discussion of the pending sale of certain investments in Argentina,
see Note 9. Commitments and Contingent Liabilities.
EGDC is conducting a controlled exit from the real estate business. In
1999, a pre-tax charge of $11 million was recorded for a property held for sale.
This amount is recorded in operations and maintenance expense. Since EGDC has
been conducting a controlled exit from the real estate business, gains and
losses from property sales are considered to be in the normal course of business
of EGDC. As of December 31, 2001 and December 31, 2000, EGDC has three
properties and four properties, respectively, reported as Assets Held for Sale
amounting to $23 and $13 million, respectively.
Foreign Currency Translation/Transactions
The assets and liabilities of foreign operations are translated into United
States dollars at current exchange rates and revenues and expenses are
translated at average exchange rates for the year. Resulting translation
adjustments are reflected as a separate component of stockholders' equity.
Transaction gains and losses that arise from exchange rate fluctuations on
normal operating transactions denominated in a currency other than the
functional currency are included in earnings as incurred.
Capital Leases as Lessee
The Consolidated Balance Sheets include assets and related obligations
applicable to capital leases under which the entity is a lessee. The total
amortization of the leased assets and interest on the lease obligations equals
the net minimum lease payments included in rent expense for capital leases.
Capital leases of PSE&G relate primarily to its corporate headquarters. See Note
9 - Commitments and Contingent Liabilities.
Impairment of Long-Lived Assets
We and our unregulated subsidiaries review long-lived assets for possible
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. In the event that facts and
circumstances indicate that the carrying amount of long-lived assets may be
impaired, an evaluation of recoverability would be performed. If an evaluation
is required, the estimated future undiscounted cash flows associated with the
asset would be compared to the asset's carrying amount to determine if a
writedown is required. If this review indicates that the assets will not be
recoverable, the carrying value of our assets would be reduced to their
estimated market value. Upon deregulation, PSE&G evaluated the recoverability of
its generation related assets and recorded an extraordinary, non-cash charge to
earnings. For the impact of the application of SFAS 121, see Note 3. Regulatory
Issues and Accounting Impacts of Deregulation.
Goodwill
We classified the cost in excess of fair value of the net assets as
goodwill (including tax attributes) of companies acquired in purchase business
transactions.
Goodwill recorded in connection with acquisitions that occurred prior to
July 1, 2001 are amortized on a straight line basis over its estimated useful
life, principally over a forty year period, except for certain amounts with
lives determined to be shorter than forty years. For a discussion of recent
accounting standards with respect to recent business combinations and goodwill,
see Note 2. "Accounting Matters".
We evaluate the recoverability of goodwill by estimating the future
discounted cash flows of the businesses to which goodwill relates. The rate used
in determining discounted cash flows is a rate corresponding to our cost of
76
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
capital. Estimated cash flows are then determined by disaggregating our business
segments to an operational and organizational level for which meaningful
identifiable cash flows can be determined. When estimated future discounted cash
flows are less than the carrying value of the net assets (tangible or
identifiable intangibles) and related goodwill, impairment losses of goodwill
are charged to operations. Impairment losses, limited to the carrying value of
goodwill, represent the excess sum of the carrying value of the net assets
(tangible or identifiable intangibles) and goodwill over the discounted cash
flows of the business being evaluated. In determining the estimated future cash
flows, we consider current and projected future levels of income as well as
business trends, prospects and economic conditions.
For a discussion of recent accounting standards with respect to recent
business combinations and goodwill, see Note 2. Accounting Matters and Note 9.
Commitments and Contingent Liabilities.
Use of Estimates
The process of preparing financial statements in conformity with GAAP
requires the use of estimates and assumptions regarding certain types of assets,
liabilities, revenues and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial statements. Accordingly,
upon settlement, actual results may differ from estimated amounts.
Nuclear Decommissioning Trust Funds
Funds in our Nuclear Decommissioning Trust are stated at fair value.
Changes in the fair value of trust funds are also reflected in the accrued
liability for nuclear decommissioning.
Reclassifications
Certain reclassifications of amounts reported in prior periods have been
made to conform with the current presentation.
Current Assets and Current Liabilities
The fair value of the current assets and liabilities approximate their
carrying amounts.
Note 2. Accounting Matters
In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS
141). SFAS 141 was effective July 1, 2001 and requires that all business
combinations on or after that date be accounted for under the purchase method.
Upon implementation of this standard, there was no impact on our financial
position or results of operations and we do not believe it will have a
substantial effect on our strategy.
Also in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a
nonamortizable asset and will be subject to an annual review for impairment and
an interim review when events or circumstances occur. SFAS 142 is effective for
all fiscal years beginning after December 15, 2001. The impact of adopting SFAS
142 is likely to be material to our financial position and results of
operations. For additional information relating to potential asset impairments,
see Note 9. Commitments and Contingent Liabilities.
Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). Under SFAS 143, the fair value of a
liability for an asset retirement obligation should be recorded in the period in
which it is created with an offsetting amount to an asset. Upon settlement of
the liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002. We are currently evaluating this guidance and
cannot predict the impact on our financial position or results of operations;
however, such impact could be material.
77
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In August 2001, FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144 long-lived assets to
be disposed of will be measured at the lower of carrying amount or fair value
less cost to sell, whether reported in continued operations or in discontinued
operations. Discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. We are currently
evaluating this guidance and which may have a material impact on our financial
position or results of operations.
Note 3. Regulatory Issues and Accounting Impacts of Deregulation
New Jersey Energy Master Plan Proceedings and Related Orders
Following the enactment of the Energy Competition Act, the BPU rendered a
Final Order relating to PSE&G's rate unbundling, stranded costs and
restructuring proceedings (Final Order). PSE&G, pursuant to the Final Order,
transferred its electric generating facilities and wholesale power contracts to
Power and its subsidiaries on August 21, 2000 in exchange for a promissory note
in an amount equal to the purchase price.
The generating assets were transferred at the price specified in the BPU
order - $2.443 billion plus $343 million for other generation related assets and
liabilities. Because the transfer was between affiliates, PSE&G and Power
recorded the sale at the net book value of the assets and liabilities rather
than the transfer price. The difference between the total transfer price and the
net book value of the generation-related assets and liabilities was recorded as
an equity adjustment on PSE&G's and Power's Consolidated Balance Sheets. These
amounts are eliminated on our consolidated financial statements. Power paid the
promissory note on January 31, 2001, with funds provided from us via equity
contributions and loans.
Also in the Final Order, the BPU concluded that PSE&G should recover up to
$2.94 billion (net of tax) of its generation-related stranded costs through
securitization of $2.4 billion, plus an estimated $125 million of transaction
costs, and an opportunity to recover up to $540 million (net of tax) of its
unsecuritized generation-related stranded costs on a net present value basis.
The $540 million is subject to recovery through a market transition charge
(MTC). PSE&G remits the MTC revenues to Power as part of the BGS contract as
provided for by the Final Order.
In September 1999, the BPU issued its order approving PSE&G's petition
relating to the proposed securitization transaction (Finance Order) which
authorized, among other things, the imposition of a non-bypassable transition
bond charge (TBC) on PSE&G's customers; the sale of PSE&G's property right in
such charge to a bankruptcy-remote financing entity; the issuance and sale of
$2.525 billion of securitization bonds by such entity as consideration for such
property right, including an estimated $125 million of transaction costs; and
the application by PSE&G of the transition bond proceeds to retire outstanding
debt and/or equity. PSE&G Transition Funding LLC (Transition Funding) issued the
transition bonds on January 31, 2001; and the TBC and a 2% rate reduction became
effective on February 7, 2001 in accordance with the Final Order. An additional
2% rate reduction became effective on August 1, 2001 bringing the total rate
reduction to 9% since August 1, 1999. These rate reductions and the TBC were
funded through the MTC rate.
On January 31, 2001, $2.525 billion of securitization bonds (non-recourse
asset backed securities) were issued by Transition Funding, in eight classes
with maturities ranging from 1 year to 15 years. Also on January 31, 2001, PSE&G
received payment from Power on its $2.786 billion promissory note used to
finance the transfer of PSE&G's generation business. The proceeds from these
transactions were used to pay for certain debt issuance and related costs for
securitization, retire a portion of PSE&G's outstanding short-term debt, reduce
PSE&G common equity, loan funds to us and make various short-term investments.
78
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In order to properly recognize the recovery of the allowed unsecuritized
stranded costs over the transition period, we recorded a charge to net income of
$88 million, pre-tax, or $52 million, after tax, in the third quarter of 2000
for the cumulative amount of estimated collections in excess of the allowed
unsecuritized stranded costs from August 1, 1999 through September 30, 2000. As
of December 31, 2001, the amount of estimated collections in excess of the
allowed unsecuritized stranded costs was $168 million.
Extraordinary Charge and Other Accounting Impacts of Deregulation
In April 1999, PSE&G determined that SFAS 71 was no longer applicable to
the electric generation portion of its business in accordance with the
requirements of Emerging Issues Task Force Issue 97-4, "Deregulation of the
Pricing of Electricity - Issues Related to the Application of FASB Statements
No. 71 and No. 101" (EITF 97-4). Accordingly, in 1999, we recorded an
extraordinary charge to earnings of $804 million (after tax), consisting
primarily of the write-down of PSE&G's nuclear and fossil generating stations in
accordance with SFAS 121. As a result of this impairment analysis, the net book
value of the generating stations was reduced by approximately $5.0 billion
(pre-tax) or $3.1 billion (net of tax). This amount was offset by the creation
of a $4.057 billion (pre-tax), or $2.4 billion (net of tax) regulatory asset, as
provided for in the Final Order and Finance Order.
In addition to the impairment of PSE&G's electric generating stations, the
extraordinary charge consisted of various accounting adjustments to reflect the
absence of cost of service regulation in the electric generation portion of its
business. The adjustments primarily related to materials and supplies, general
plant items and liabilities for certain contractual and environmental
obligations.
In accordance with the Final Order, PSE&G also reclassified a $569 million
excess depreciation reserve related to PSE&G's electric distribution assets from
Accumulated Depreciation to a Regulatory Liability. Such amount is being
amortized in accordance with the terms of the Final Order over the period from
January 1, 2000 to July 31, 2003.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 4. Regulatory Assets and Liabilities
At December 31, 2001 and December 31, 2000, respectively, we had deferred
the following regulatory assets and liabilities on the Consolidated Balance
Sheets:
December
----------------------------
2001 2000
------------ -----------
(Millions of Dollars)
Regulatory Assets
-----------------
Stranded Costs to be Recovered................................ $4,105 $4,057
SFAS 109 Income Taxes......................................... 302 285
OPEB Costs.................................................... 212 232
Societal Benefits Charges (SBC)............................... 4 135
Environmental Costs........................................... 87 13
Unamortized Loss on Reacquired Debt and Debt Expense.......... 92 104
Underrecovered Gas Costs...................................... 120 --
Unrealized Losses on Gas Contracts............................ 137 --
Non-Utility Generation Transition Charge (NTC)................ -- 7
Other......................................................... 161 162
------------ -----------
Total Regulatory Assets................................. $5,220 $4,995
============ ===========
Regulatory Liabilities
----------------------
Excess Depreciation Reserve................................... $319 $444
Non-Utility Generation Transition Charge (NTC)................ 48 --
Overrecovered Gas Costs....................................... -- 26
Other......................................................... 6 --
------------ -----------
Total Regulatory Liabilities............................ $373 $470
============ ===========
Stranded Costs To Be Recovered: This reflects deferred costs to be
recovered through securitization transition charge which was authorized by the
Final Order and Finance Order.
SFAS 109 Income Taxes: This amount represents the portion of deferred
income taxes that will be recovered through future rates, based upon established
regulatory practices, which permit the recovery of current taxes.
OPEB Costs: Includes costs associated with the adoption of SFAS No. 106.
"Employers' Accounting for Benefits Other Than Pensions" which were deferred in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated
Enterprises". Prior to the adoption of SFAS 106, post-retirement benefits costs
were recognized on a cash basis. SFAS 106 required that these costs be accrued
as the benefits were earned. Accordingly a liability and a regulatory asset were
recorded for the total benefits earned at the implementation date. Beginning
January 1, 1998, we commenced the amortization of this regulatory asset over 15
years. See Note 12. Pension, Other Postretirement Benefit and Savings Plans for
additional information.
Societal Benefit Charges (SBC): The SBC includes costs related to PSE&G's
electric transmission and distribution business as follows: 1) social programs
which include the universal service fund; 2) nuclear plant decommissioning; 3)
demand side management (DSM) programs; 4) manufactured gas plant remediation; 5)
consumer education; 6) Under and overrecovered electric bad debt expenses; and
7) MTC overrecovery.
Environmental Costs: Represents environmental investigation and remediation
costs which are probable of recovery in future rates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond
issuance costs, premiums, discounts and losses on reacquired long-term debt.
Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess of
or below the amount included in rates and probable of recovery in the future.
Unrealized Losses on Gas Contracts: This represents the recoverable portion
of unrealized losses associated with contracts used in the company's gas
distribution business
Non-utility Generation Transition Charge (NTC): This clause was established
to account for above market costs related to non-utility generation contracts.
The charge for the stranded NTC recovery was initially set at $183 million
annually. Any NUG contract costs and/or buyouts are charged to the NTC. Proceeds
from the sale of the energy and capacity purchased under these NUG contracts are
also credited to this account.
Other Regulatory Assets: Includes Decontamination and Decommissioning
Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies and
Interest, Property Abandonments and Oil and Gas Property Write-Down and recovery
of costs related to Transition Funding's interest rate swap.
Excess Depreciation Reserve: As required by the BPU, PSE&G reduced its
depreciation reserve for its electric distribution assets by $569 million and
recorded such amount as a regulatory liability to be amortized over the period
from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was
amortized. The remaining $319 million will be amortized through July 31, 2003.
Other Regulatory Liabilities: This includes the following: 1) Interest on
amounts collected from customers that are used to fund incentives for choosing a
third party gas supplier; 2) Interest on amounts collected early from customers
relating to the Transitional Energy Facility Assessment tax; and 3) Amounts
collected from customers in order for Transition Funding to obtain a AAA rating
on its transition bonds.
Note 5. Long-Term Investments
Long-Term Investments are primarily those of Energy Holdings' subsidiaries:
December 31,
---------------------------
2001 2000
----------- -----------
(Millions of Dollars)
Leveraged Leases................................................ $2,784 $2,253
Partnerships:
General Partnerships....................................... 44 46
Limited Partnerships....................................... 615 479
----------- -----------
Total................................................ 659 525
----------- -----------
Corporate Joint Ventures........................................ 1,111 1,584
Securities...................................................... 6 6
Other Investments............................................... 258 177
----------- -----------
Total Long-Term Investments.......................... $4,818 $4,545
=========== ===========
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Leveraged Leases
Resources' net investment in leveraged leases is comprised of the following
elements:
December 31,
--------------------------------
2001 2000
------------ ------------
(Millions of Dollars)
Lease rents receivable............................................ $3,644 $3,175
Estimated residual value of leased assets......................... 1,414 1,040
------------ ------------
5,058 4,215
Unearned and deferred income...................................... (2,274) (1,962)
------------ ------------
Total investments in leveraged leases........................ 2,784 2,253
Deferred taxes arising from leveraged leases...................... (1,175) (1,031)
------------ ------------
Net investment in leverage leases............................ $1,609 $1,222
============ ============
Resources' pre-tax income and income tax effects related to investments in
leveraged leases are as follows:
Years ended December 31,
-------------------------------------------------------------
2001 2000 1999
------------------ ------------------ -----------------
(Millions of Dollars)
Pre-tax income......................................... $ 206 $ 163 $ 112
================== ================== =================
Income tax effect on pre-tax income.................... $ 62 $ 58 $ 41
Amortization of investment tax credits................. $ (1) $ (1) $ (1)
Resources, as lessor, has certain ownership rights to the property through
leveraged leases, with terms ranging from 4 to 45 years. The lease investments
are recorded on a net basis by summing the lease rents receivable over the
lease term and adding the residual value, if any, less unearned income and
deferred taxes to be recognized over the lease term. Leveraged leases are
recorded net of non-recourse debt.
Income on leveraged leases is recognized by a method which produces a
constant rate of return on the outstanding net investment in the lease, net of
the related liability, in the years in which the net investment is positive.
Initial direct costs are deferred and amortized using the interest method over
the lease period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Partnership Investments and Corporate Joint Ventures
Partnership investments of approximately $615 million and corporate joint
ventures of approximately $1.1 billion are those of Resources, Global and EGDC.
Energy Holdings accounts for such investments under the equity method of
accounting. As of December 31, 2001 Energy Holdings had approximately $1.5
billion of investments accounted for under the equity method of accounting.
Summarized results of operations and financial position of all affiliates
in which Global uses the equity method of accounting are presented below:
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 2001
Condensed Income Statement Information
Revenue.................................................. $ 819 $ 473 $ 1,292
Gross Profit............................................. 317 165 482
Minority Interest........................................ (20) -- (20)
Net Income............................................... 141 91 232
Condensed Balance Sheet Information
Assets:
Current Assets.......................................... $ 341 $ 131 $ 472
Property, Plant & Equipment............................. 1,198 1,406 2,604
Goodwill................................................ 863 50 913
Other Non-current Assets............................... 616 23 639
----------------- -------------- ----------------
Total Assets............................................. $ 3,018 $ 1,610 $ 4,628
----------------- -------------- ----------------
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
----------------- -------------- ----------------
Liabilities:
Current Liabilities..................................... $ 415 $ 109 $ 524
Debt.................................................... 761 658 1,419
Other Non Current Liabilities........................... 132 212 344
Minority Interest....................................... 25 -- 25
----------------- -------------- ----------------
Total Liabilities........................................ 1,333 979 2,312
Equity................................................... 1,685 631 2,316
----------------- -------------- ----------------
Total Liabilities & Equity............................... $ 3,018 $ 1,610 $ 4,628
----------------- -------------- ----------------
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 2000
Condensed Income Statement Information
Revenue.................................................. $ 1,059 $ 452 $ 1,511
Gross Profit............................................. 434 256 690
Minority Interest........................................ (25) -- (25)
Net Income............................................... 156 162 318
Condensed Balance Sheet Information
Assets:
Current Assets.......................................... $ 504 $ 130 $ 634
Property, Plant & Equipment............................. 2,355 1,349 3,704
Goodwill................................................ 1,201 -- 1,201
Other Non-current Assets............................... 464 77 541
----------------- -------------- ----------------
Total Assets............................................. $ 4,524 $ 1,556 $ 6,080
----------------- -------------- ----------------
Liabilities:
Current Liabilities..................................... $ 818 $ 99 $ 917
Debt.................................................... 696 732 1,428
Other Non Current Liabilities........................... 174 90 264
Minority Interest....................................... 129 1 130
----------------- -------------- ----------------
Total Liabilities........................................ 1,817 922 2,739
Equity................................................... 2,707 634 3,341
----------------- -------------- ----------------
Total Liabilities & Equity............................... $ 4,524 $ 1,556 $ 6,080
----------------- -------------- ----------------
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 1999
Condensed Income Statement Information
Revenue.................................................. $ 1,184 $ 423 $ 1,607
Gross Profit............................................. 416 265 681
Minority Interest........................................ (23) -- (23)
Net Income............................................... 110 155 265
Purchase Business Combinations/Asset Acquisitions
In December 2001, Global acquired Empresa de Electricidad de los Andes S.A.
(Electroandes) for $227 million, subject to certain purchase price adjustments
pending completion in April 2002. Electroandes is the sixth largest electric
generator in Peru with a 6% market share. Electroandes' main assets include four
hydroelectric facilities with a combined installed capacity of 183 MW and 460
miles of transmission lines located in the Central Andean region (northeast of
Lima). In addition, Electroandes has the exclusive rights to develop a 100 MW
expansion of an existing station and a 150 MW greenfield hydroelectric facility.
In 2000, Electroandes generated 1,150 GWH of electrical energy, of which 97% was
sold through power purchase agreements to mining companies in the region. We
have not finalized the allocation of the purchase price as of December 31, 2001.
An estimation of this allocation was prepared and included as part of our
consolidated financial statements. The purchase price was allocated $15 million
to Current Assets, $78 million to Property, Plant and Equipment, $164 million to
Goodwill, and $30 million to Current Liabilities.
In August 2001, Global purchased a 94% equity stake in SAESA and all of its
subsidiaries from Compania de Petroleos de Chile S.A. (COPEC). The SAESA group
of companies consists of four distribution companies and one transmission
company that provide electric service in the southern part of Chile.
Additionally, Global purchased from COPEC approximately 14% of Empresa Electrica
de la Frontera S.A. (Frontel) not owned by SAESA. SAESA also owns a 50% interest
in the Argentine distribution company Empresa Electrica del Rio Negro S.A. In
2001 Global spent $447 million (net of $16 million in cash acquired) to acquire
a 94% interest in SAESA and a 14% interest in Frontel. In October 2001, Global
completed a tender offer for an additional 6% of publicly trades SAESA shares,
for approximately $25 million. We have not finalized the allocation of the
purchase price as of December 31, 2001. An estimation of this allocation was
prepared and included as part of our consolidated financial statements. The
total purchase price of $488 million was allocated $55 million to Current
Assets, $210 million to Property, Plant and Equipment, $315 million to Goodwill,
$10 million to Other Non-Current Assets, $46 million to Current Liabilities, $39
million to Long-Term Debt, $17 million to Deferred Taxes and Other Non-Current
Liabilities.
In June 2001, Global exercised its option to acquire an additional 49% of
Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an electric
distribution company providing electric service to more than 230,000 customers
in the Province of Entre Rios, Argentina, bringing its total ownership of
EDEERSA to 90%. The additional ownership was purchased for $110 million. An
estimation of this allocation was prepared and included as part of our
consolidated financial statements. The purchase price was allocated
approximately $22 million to Current Assets, $114 million to Property, Plant and
Equipment, $30 million to Goodwill, $15 million to Current Liabilities, and $41
million to Long-Term Debt. We have not finalized the allocation of the purchase
price as of December 31, 2001.
In 2000, Global acquired a 49% interest in Tanir Bavi Power Company Private
Ltd., which was constructing a 220 MW barge mounted, combined-cycle generating
facility located near Mangalore in the state of Karnataka, India. In January
2001, Global acquired an additional 25% interest in the project bringing its
total ownership interest to 74%. In November 2001, the facility achieved full
commercial operation. Power from the facility will be sold to the Karnataka
Electricity Board pursuant to a seven year fixed price power purchase agreement
with a five-year renewal term.
Other Investments
Other investments primarily include amounts related to Life Insurance,
Energy Technologies investments in DSM projects. As of December 31, 2001,
amounts related to such items were $108
84
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
million and $47 million, respectively. As of December 31, 2000, amounts related
to such items were $89 million and $56 million, respectively.
Note 6. Schedule of Consolidated Capital Stock and Other Securities
Outstanding Current
Shares Redemption
At December 31, Price December 31, December 31,
2001 Per Share 2001 2000
---------------------------------- -------------- ----------------
(Millions of Dollars)
PSEG Common Stock (no par) (A)
Authorized 500,000,000 shares; issued and outstanding
at December 31, 2001, 205,839,018 shares and at
December 31, 2000, shares 207,971,318 $2,618 $2,709
PSEG Preferred Securities (B)
PSEG Quarterly Guaranteed Preferred Beneficial
Interest in
PSEG's Subordinated Debentures (D)(E)(G)
7.44%........................................... 9,000,000 -- $225 $225
Floating Rate................................... 150,000 -- 150 150
7.25%........................................... 6,000,000 -- 150 150
-------------- ----------------
Total Quarterly Guaranteed Preferred Beneficial
Interest in
PSEG's Subordinated Debentures.................. $525 $525
============== ================
PSE&G Preferred Securities
PSE&G Cumulative Preferred Stock (C) without Mandatory
Redemption (D)(E) $100 par value series
4.08%........................................... 146,221 103.00 $15 $15
4.18%........................................... 116,958 103.00 12 12
4.30%........................................... 149,478 102.75 15 15
5.05%........................................... 104,002 103.00 10 10
5.28%........................................... 117,864 103.00 12 12
6.92%........................................... 160,711 -- 16 16
$25 par value series
6.75%........................................... -- -- -- 15
-------------- ----------------
Total Preferred Stock without Mandatory Redemption $80 $95
============== ================
With Mandatory Redemption (D)(E) $100
par value series
5.97%........................................... -- -- $-- $75
-------------- ----------------
Total Preferred Stock with Mandatory Redemption... $-- $75
============== ================
PSE&G Monthly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures (D)(E)(F)
9.375%.......................................... -- -- $-- $150
8.00%........................................... 2,400,000 25.00 60 60
-------------- ----------------
Total Monthly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures................. $60 $210
============== ================
PSE&G Quarterly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures (D)(E)(F)
8.625%.......................................... -- -- $-- $208
8.125%.......................................... 3,800,000 -- 95 95
-------------- ----------------
Total Quarterly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures................. $95 $303
============== ================
(A) Our Board of Directors authorized the repurchase of up to 30 million
shares of its common stock in the open market. At December 31, 2001, we
had repurchased approximately 26.5 million shares of common stock at a
cost of approximately $997 million. The repurchased shares have been held
as treasury stock or used for other corporate purposes. Total authorized
and unissued shares include 7,302,488 shares of common stock available
85
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
for issuance through our Dividend Reinvestment and Stock Purchase Plan
and various employee benefit plans. In 2001 and 2000, no shares of common
stock were issued or sold through these plans.
(B) We have authorized a class of 50,000,000 shares of Preferred Stock
without par value, none of which is outstanding.
(C) At December 31, 2001, there were an aggregate of 6,704,766 aggregates of
shares of $100 par value and 10,000,000 shares of $25 par value
Cumulative Preferred Stock which were authorized and unissued and which,
upon issuance, may or may not provide for mandatory sinking fund
redemption. If dividends upon any shares of Preferred Stock are in
arrears in an amount equal to the annual dividend thereon, voting rights
for the election of a majority of PSE&G's Board of Directors become
operative and continue until all accumulated and unpaid dividends thereon
have been paid, whereupon all such voting rights cease, subject to being
revived from time to time.
(D) At December 31, 2001 and 2000, the annual dividend requirement of our
Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in
our Subordinated Debentures) and their embedded costs were $38,433,000
and 4.91%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement and
embedded dividend rate for PSE&G's Preferred Stock without mandatory
redemption was $10,127,383 and 5.03%, $10,886,758 and 5.18%,
respectively, and for our Preferred Stock with mandatory redemption was
$1,119,375 and 6.02%, $4,477,500 and 6.02%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement and
embedded cost of the Monthly Income Preferred Securities (Guaranteed
Preferred Beneficial Interest in PSE&G's Subordinated Debentures) was
$7,768,750 and 4.90%, $18,862,500 and 5.50%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement of the
Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated Debentures) and their embedded costs
were $16,439,584 and 4.97%, $25,658,750 and 5.18%, respectively.
(E) For information concerning fair value of financial instruments, see Note
8. Financial Instruments, Energy Trading and Risk Management.
(F) PSE&G Capital L.P., PSE&G Capital Trust I and PSE&G Capital Trust II were
formed and are controlled by PSE&G for the purpose of issuing Monthly and
Quarterly Income Preferred Securities (Monthly and Quarterly Guaranteed
Preferred Beneficial Interest in PSE&G's Subordinated Debentures). The
proceeds were loaned to PSE&G and are evidenced by PSE&G's Deferrable
Interest Subordinated Debentures. If and for as long as payments on
PSE&G's Deferrable Interest Subordinated Debentures have been deferred,
or PSE&G has defaulted on the indentures related thereto or its
guarantees thereof, PSE&G may not pay any dividends on its common and
preferred stock. The Subordinated Debentures and the indentures
constitute a full and unconditional guarantee by PSE&G of the Preferred
Securities issued by the partnership and the trusts.
(G) Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise
Capital Trust III and Enterprise Capital Trust IV were formed and are
controlled by us for the purpose of issuing Quarterly Trust Preferred
Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG's
Subordinated Debentures). The proceeds were loaned to us and are
evidenced by our Deferrable Interest Subordinated Debentures. If and for
as long as payments on our Deferrable Interest Subordinated Debentures
have been deferred, or we have defaulted on
86
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
the indentures related thereto or its guarantees thereof, PSEG may not
pay any dividends on its common and preferred stock. The Subordinated
Debentures constitute our full and unconditional guarantee of the
Preferred Securities issued by the trusts.
Note 7. Schedule of Consolidated Debt
LONG-TERM
Interest Rates Maturity 2001 2000
- ------------------------------------------------------ --------------------- -------------- ---------------
PSEG (Millions of Dollars)
- ----
Extendible Notes LIBOR plus 0.40% (A) 2001................ $ -- $300
Floating Rate Notes-LIBOR plus 0.875% 2002................ 275 275
-------------- ---------------
Principal Amount Outstanding (C)............................................. 275 575
Amounts Due Within One Year (D).............................................. (275) (300)
-------------- ---------------
Total Long-Term Debt of PSEG ......................................... $ -- $275
============== ===============
PSE&G
- -----
First and Refunding Mortgage Bonds (B):
7.875% 2001................ $ -- $100
6.125% 2002................ 258 258
6.875%-8.875% 2003................ 300 300
6.50% 2004................ 286 286
9.125% 2005................ 125 125
6.75% 2006................ 147 147
6.25% 2007................ 113 113
Variable 2008-2012........... -- 66
6.75%-7.375% 2013-2017........... 330 330
6.45%-9.25% 2018-2022........... 139 139
Variable 2018-2022........... -- 14
5.20%-7.50% 2023-2027........... 434 434
5.45%-6.55% 2028-2032........... 499 499
Variable 2028-2032........... -- 25
5.00%-8.00% 2033-2037........... 160 160
Medium-Term Notes:
7.19% 2002................ 290 290
8.10%-8.16% 2008-2012........... 60 60
7.04% 2018-2022........... 9 9
7.15%-7.18% 2023-2027........... 39 39
-------------- ---------------
Total First and Refunding Mortgage Bonds............................ 3,189 3,394
-------------- ---------------
Unsecured Bonds-7.43% (L) 2002............... -- 300
Unsecured Bonds-Variable 2027............... -- 19
-------------- ---------------
Total Unsecured Bonds............................................... -- 319
-------------- ---------------
Principal Amount Outstanding (C)............................................. 3,189 3,713
Amounts Due Within One Year (D).............................................. (547) (100)
Net Unamortized Discount..................................................... (16) (23)
-------------- ---------------
Total Long-Term Debt of PSE&G (E)................................... $2,626 $3,590
============== ===============
87
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
- ------------------------------------------------------ --------------------- -------------- ---------------
Transition Funding (Millions of Dollars)
- ------------------
Securitization Bonds (I):
5.46%................................................. 2004................ $52 --
5.74%................................................. 2007................ 369 --
5.98%................................................. 2008................ 183 --
LIBOR plus 0.30%...................................... 2011................ 496 --
6.45%................................................. 2013................ 328 --
6.61%................................................. 2015................ 454 --
6.75%................................................. 2016................ 220 --
6.89%................................................. 2017................ 370 --
-------------- ---------------
Principal Amount Outstanding (C)............................................. 2,472 --
Amounts Due Within One Year (I).............................................. (121) --
-------------- ---------------
Total Long-Term Debt of Transition Funding, LLC ...................... $2,351 --
============== ===============
Power
- -----
Senior Notes:
6.88%............................................... 2006................. $500 --
7.75%............................................... 2011................. 800 --
8.63%............................................... 2031................. 500 --
Pollution Control Bonds (J)............................
5.00%............................................... 2012................. 66 --
5.50%............................................... 2020................. 14 --
5.85%............................................... 2027................. 19 --
5.75%............................................... 2031................. 25 --
Non-recourse debt (K):
Variable............................................ 2005................. 770 --
------------ ------------
Principal Amount Outstanding (C).............................................. 2,694 --
Amounts Due Within One Year (D)............................................... -- --
Net Unamortized Discount...................................................... (9) --
-------------- ---------------
Total Long-Term Debt of Power ....................................... $2,685 --
============== ===============
88
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
- ------------------------------------------------------ --------------------- -------------- ---------------
Energy Holdings (Millions of Dollars)
- ---------------
Senior Notes:
9.125% 2004................. $300 $ 300
8.625% 2008................. 400 --
10.00% 2009................. 400 400
8.50% 2011................. 550 --
-------------- ------------
Principal Amount Outstanding (C)............................................. 1,650 700
Net Unamortized Discount..................................................... (6) (5)
-------------- ------------
$1,644 $695
-------------- ------------
PSEG Capital
- ------------
Medium-Term Notes (F):
6.73% - 6.74% 2001................ -- 170
3.12% - 7.72% 2002................ 228 228
6.25% 2003................ 252 252
-------------- ------------
Principal Amount Outstanding (C)............................................. 480 650
-------------- -------------
Amounts Due Within One Year (D).............................................. (228) (170)
Net Unamortized Discount..................................................... -- (1)
-------------- -------------
Total Long-Term Debt of PSEG Capital................................ 252 479
-------------- -------------
Global
- ------
Non-recourse Debt (G):
10.01% -10.385% - Bank Loan 2001................ -- 96
5.47% - 10.385 - Bank Loan 2002................ 41 64
6.64% - 9.46 - Bank Loan 2003-2019........... 711 160
14.00% - Minority Shareholder Loan 2027................ 10 10
-------------- ------------
Principal Amount Outstanding (C)............................................. 762 330
Amounts Due Within One Year (D).............................................. (41) (96)
-------------- -------------
Total Long-Term Debt of Global...................................... 721 234
-------------- -------------
Resources
- ---------
8.60% - Bank Loan 2001-2020........... 22 24
-------------- -------------
Principal Amount Outstanding (C)............................................. 22 24
Amounts Due Within One Year (D)..............................................
(1) (1)
-------------- -------------
Total Long-Term Debt of Resources................................... 21 23
-------------- -------------
Energy Technologies
- -------------------
2.90% - 11.65% Various Loans 2002-2005........... 1 1
-------------- -------------
Total Long-Term Debt of Energy Technologies......................... 1 1
-------------- -------------
Total Long-Term Debt of Energy Holdings........................ 2,639 1,432
============== =============
Consolidated Long-Term Debt (H)............................ $10,301 $5,297
============== =============
89
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
(A) In June 1999, we issued $300 million of Extendible Notes, Series C, due
June 15, 2001. At December 31, 2000, the interest rate on Series C was
6.955%. These Extendible Notes were repurchased in 2001 and are no longer
outstanding. In November 2000, we issued $275 million of Floating Rate
Notes due May 21, 2002 with an interest rate is at three-month LIBOR,
plus 0.875%.
(B) PSE&G's First and Refunding Mortgage (Mortgage), securing the Bonds,
constitutes a direct first mortgage lien on substantially all of PSE&G's
property and franchises.
(C) For information concerning fair value of financial instruments, see Note
8. Financial Instruments Energy Trading and Risk Management.
(D) The aggregate principal amounts of mandatory requirements for sinking
funds and maturities for each of the five years following December 31,
2001 are as follows:
Transition PSEG Energy PSEG
Year PSEG PSE&G Funding Power Holdings Capital Global Resources Total
------ -------- -------- ----------- ------- ---------- -------- ------- -------- --------
2002 275 547 -- -- -- 228 41 1 1,092
2003 -- 300 -- -- -- 252 56 1 609
2004 -- 286 52 -- 300 -- 116 1 755
2005 -- 125 -- 770 -- -- 39 1 935
2006 147 -- 500 -- -- 39 1 687
-------- -------- ----------- ------- ---------- -------- ------- -------- --------
275 1,405 52 1,270 300 480 291 5 4,078
======== ======== =========== ======= ========== ======== ======= ======== ========
(E) At December 31, 2001 and 2000, PSE&G's annual interest requirement on
long-term debt was $220 million and $256 million, of which $220 million
and $233 million, respectively, was the requirement for Mortgage Bonds.
The embedded interest cost on long-term debt on such dates was 7.46% and
7.30%, respectively. The embedded interest cost on long-term debt due
within one year at December 31, 2001 was 6.76%.
(F) PSEG Capital has provided up to $750 million debt financing for Energy
Holdings' businesses, except Energy Technologies, on the basis of a net
worth maintenance agreement with PSEG. Since 1995, PSEG Capital has
limited its borrowings to no more than $650 million.
(G) Global's projects are generally financed with non-recourse debt at the
project level, with the balance in the form of equity investments by the
sponsors in the project. The non-recourse debt shown in the above table
is that of consolidated subsidiaries which have equity investments in
distribution facilities in Argentina, Chile and Peru and generation
facilities under construction in Poland and Tunisia. Global's capital at
risk on the projects is limited to its original investment.
(H) At December 31, 2001 and 2000, our annual interest requirement on
long-term debt was $645 million and $440 million. The embedded interest
cost on long-term debt on such dates was 7.83% and 7.66%, respectively.
(I) At January 31, 2001, Transition Funding issued $2.525 billion of Bonds in
eight classes with estimated final payment dates from one year to fifteen
years. The net proceeds were remitted to PSE&G as consideration for the
property right in the TBC. At December 31, 2001, Transition Funding
annual interest requirement on securitization bonds was $148 million. The
current portion of Transition Funding's debt is based on estimated
payment dates, with final estimated payment dates at two years earlier
than the final maturity dates for each respective class of Bonds. At
December 31, 2001, Transition Funding's annual interest requirement on
its Bonds was $137 million.
90
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
(J) At November 20, 2001 & December 5, 2001, Power issued $124 million of
Pollution Control Notes in four classes with maturities ranging from 11
years to 30 years.
(K) In August 2001, subsidiaries of Power closed with a group of banks on
$800 million of non-recourse project financing for projects in Waterford,
Ohio and Lawrenceburg, Indiana. The Waterford project will be completed
in two phases and will increase Power's capacity by 850 MW. The first
phase and second phase of the project are expected to achieve commercial
operation in June 2002 and May 2003, respectively. The Lawrenceburg
project will increase Power's capacity by 1,150 MW and is expected to
achieve commercial operation by May 2003. The total combined project cost
for Waterford and Lawrenceburg is estimated at $1.2 billion. Power's
required estimated equity investment in these projects is approximately
$400 million. In connection with these projects, ER&T has entered into a
tolling agreement pursuant to which it is obligated to purchase the
output of these facilities at stated prices. As a result, ER&T bears the
price risk related to the output of these generation facilities.
(L) On December 7, 2000, PSE&G issued $300 million of Floating Rate Notes at
7.4275%, due December 7, 2002. The proceeds were used for general
corporate purposes including the repayment of short-term debt. These
notes were repurchased during 2001.
SHORT-TERM DEBT
At December 31, 2001, we and Energy Holdings had a $753 million and $585
million of short-term debt as detailed below. As of December 31, 2001 the
weighted-average short-term debt rates for us and Energy Holdings were 2.8% and
3.3%, respectively.
Commercial
Maturity Total Primary Amount Paper (Cp)
Company Date Facility Purpose Outstanding Outstanding
- ------------------------------------------- -------- -------- ------- ----------- -----------
(MILLIONS OF DOLLARS)
PSEG
- -------------------------------------------
364-day Credit Facility March 2002 $570 CP Support $ -- $475
5-year Credit Facility March 2002 280 CP Support -- N/A
5-year Credit Facility December 2002 150 Funding 125 N/A
Bilateral Credit Agreement N/A No Limit Funding 153 N/A
PSE&G
- -------------------------------------------
364-day Credit Facility June 2002 390 CP Support -- --
5-year Credit Facility June 2002 450 CP Support -- --
Bilateral Credit Agreement June 2002 60 CP Support -- --
Bilateral Credit Agreement N/A No Limit Funding -- N/A
Energy Holdings
- -------------------------------------------
364-day Credit Facility May 2002 200 Funding -- N/A
5-year Credit Facility May 2004 495 Funding 250 N/A
Bilateral Credit Agreement N/A 100 Funding 50 N/A
---- ----
Total N/A $578 $475
==== ====
91
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 8. Financial Instruments, Energy Trading and Risk Management
Our operations are exposed to market risks from changes in commodity
prices, foreign currency exchange rates, interest rates and equity prices that
could affect results of operations and financial conditions. We manage our
exposure to these market risks through our regular operating and financing
activities and, when deemed appropriate, hedge these risks through the use of
derivative financial instruments. We use the term hedge to mean a strategy
designed to manage risks of volatility in prices or rate movements on certain
assets, liabilities or anticipated transactions and by creating a relationship
in which gains or losses on derivative instruments are expected to
counterbalance the losses or gains on the assets, liabilities or anticipated
transactions exposed to such market risks. We use derivative instruments as risk
management tools consistent with our business plans and prudent business
practices and for energy trading purposes.
92
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or
values of instruments with similar terms, credit ratings, remaining maturities
and redemptions at December 31, 2001 and December 31, 2000, respectively.
December 31, 2001 December 31, 2000
------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ -----------
(Millions of Dollars)
Long-Term Debt (A):
PSEG.................................................. $275 $275 $575 $575
Energy Holdings....................................... 2,909 2,971 1,699 1,725
PSE&G................................................. 3,173 3,290 3,690 3,453
Transition Funding.................................... 2,472 2,575 -- --
Power................................................. 2,685 2,835 -- --
Preferred Securities Subject to Mandatory Redemption:
PSE&G Cumulative Preferred Securities................. -- -- 75 60
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 60 60 210 212
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 95 96 303 304
Quarterly Guaranteed Preferred Beneficial Interest in
PSEG's Subordinated Debentures..................... 525 520 525 474
(A) Includes current maturities. At December 31, 2001 we, Energy Holdings,
Power and Transition Funding had interest rate swap agreements
outstanding with notional amounts up to $150 million, $599 million, $178
million and $497 million, respectively. For additional information
concerning consolidated debt, see Note 7. Schedule of Consolidated Debt.
For additional information concerning preferred securities, see Note 6.
Schedule of Consolidated Capital Stock and Other Securities.
Global had $1.048 billion of project debt that is non-recourse to PSEG,
Energy Holdings and Global associated with investments in Argentina,
India, Chile, Peru Oman, Poland and Tunisia.
Energy Trading
Effective January 1, 1999, we adopted EITF 98-10, which requires that
energy trading contracts be recognized on the balance sheet at fair value with
resulting realized and unrealized gains and losses included in current earnings.
In 2001 we recorded $147 million of gains from our Energy Trading segment,
including realized gains of $169 million and unrealized losses of $22 million.
In 2000 we recorded gains of $77 million, including $22 million of realized
gains and $55 million of unrealized gains and in 1999 recorded gains of $42
million, including $37 million of realized gains and $5 million of unrealized
gains. Net of broker fees and other trading related expenses, our energy trading
business earned margins of $140 million, $72 million and $39 million for the
years ended December 31, 2001, 2000 and 1999, respectively. As of December 31,
2001, we had a total of $9 million of unrealized gains on our balance sheet,
over 90% of which related to contracts with terms of less than two years.
[Chart to Come]
93
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
We engage in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights and emissions
allowances in the spot, forward and futures markets primarily in PJM, but also
throughout the Super Region. We are also involved in the financial transactions
that include swaps, options and futures in the electricity markets.
The fair values as of December 31, 2001 and December 31, 2000 and the
average fair values for the periods then ended of our financial instruments
related to the energy commodities in the energy trading segment are summarized
in the following table:
December 31, 2001 December 31, 2000
----------------------------------------- ---------------------------------------------
Notional Notional Fair Average Notional Notional Fair Average
(mWh) (MMBTU) Value Fair Value (mWh) (MMBTU) Value Fair Value
------------------------------ ---------- ----------------------- ---------------------
(Millions) (Millions)
Futures and Options NYMEX .. -- 16.0 $(1.2) $(2.0) 17.0 167.0 $5.7 $(1.4)
Physical forwards........... 41.0 9.0 $(2.6) $12.1 50.0 10.0 $13.5 $13.6
Options-- OTC............... 8.0 803.0 $(19.4) $18.5 12.0 437.0 $184.2 $68.0
Swaps....................... -- 1,131.0 $23.9 $2.3 -- 218.0 $(137.8) $(42.5)
Emission Allowances......... -- -- $8.3 $23.8 -- -- $6.0 $9.5
We routinely enter into exchange traded futures and options transactions
for electricity and natural gas as part of our energy trading operations.
Generally, exchange-traded futures contracts require deposit of margin cash, the
amount of which is subject to change based on market movement in exchange rules.
The amount of the margin deposits as of December 31, 2001 and 2000 were
approximately $2.6 million and $1 million, respectively.
Derivative Instruments and Hedging Activities
Commodity Contracts
During 2001, Power entered into electric physical forward contracts and gas
futures and swaps with a maximum term of approximately one year, to hedge our
forecasted BGS requirements and gas purchases requirements for generation. These
transactions qualified for hedge accounting treatment under SFAS 133 and were
settled prior to the end of 2001. The majority of the marked-to-market
valuations were reclassified from OCI to earnings during the quarter ended
September 30, 2001. As of December 31, 2001, we did not have any outstanding
derivatives accounted for under this methodology. However, there was substantial
activity during the year ended December 31, 2001. In 2001, the values of these
forward contracts, gas futures and swaps as of June 30 and September 30 were
$(34.2) million and $(0.4) million.
Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas
futures, options and swaps to hedge forecasted requirements. As of December 31,
2001, the fair value of those instruments was $(137) million with a maximum term
of approximately one year. PSE&G utilizes derivatives to hedge its gas
purchasing activities which, when realized, are recoverable through its
Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts
are recognized at fair value as derivative assets or liabilities on the balance
sheet and the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.
We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.
The measured VAR using a variance/co-variance model with a 95% confidence
level and assuming a one-week time horizon as of December 31, 2001 was
approximately $18 million, compared to the December 31, 2000 level of $19
million. This estimate, however, is not necessarily indicative of actual
results, which may differ due to the fact that actual market rate fluctuations
may differ from forecasted fluctuations and due to the fact that the portfolio
of hedging instruments may change over the holding period and due to certain
assumptions embedded in the calculation.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of
fluctuating interest rates in the normal course of business. Their policy is to
manage interest rate risk through the use of fixed rate debt, floating rate
debt, interest rate swaps and interest rate lock agreements. As of December 31,
2001, a hypothetical 10% change in market interest rates would result in a $3
million, $4 million, and $2 million, change in annual interest costs related to
short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings,
respectively. The following table shows details of the interest rate swaps at
PSEG, PSE&G, Power and Energy Holdings and their associated values that are
still open at December 31, 2001:
Total Fair Other
Project Notional Pay Receive Market Comprehensive
Underlying Securities Percent Amount Rate Rate Value Income
- -------------------------------------------------------------------------------------------------------------------
PSEG:
Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0)
Securities
PSE&G:
Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ -
Power:
Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Total Fair Other
Project Notional Pay Receive Market Comprehensive
Underlying Securities % Amount Rate Rate Value Income
- ----------------------------------------------------------------------------------------------------------------
Energy Holdings:
Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7)
Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6)
Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5)
Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3)
Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7)
Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2)
Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7)
Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9)
----------- ---------- -------------- --------------------------
Total Energy Holdings $590.4 $(73.1) $(29.6)
----------- ---------- -------------- --------------------------
Total PSEG $1,414.9 $(94.4) $(31.3)
=========== ========== ============== ==========================
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
We expect to reclass approximately $14.0 million of open interest rate
swaps from OCI to earnings during the next twelve months. As of December 31,
2001, there was a $31.3 million balance remaining in the Accumulated Other
Comprehensive Loss Account, as indicated in the table above.
We have also entered into several interest rate swaps that were closed out
during 2001 and are being amortized to earnings over the life of the underlying
debt. These items, along with their current and anticipated effect on earnings
discussed.
In February 2001, we entered into various forward-interest rate swaps, with
an aggregate notional amount of $400 million, to hedge the interest rate risk
related to the anticipated issuance of debt. On April 11, 2001, Power issued
$1.8 billion in fixed-rate Senior Notes and closed out the forward starting
interest rate swaps. The aggregate loss, net of tax, of $3.2 million was
classified as Accumulated Other Comprehensive Loss and is being amortized and
charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects it will amortize approximately $0.8 million from
OCI to earnings during the next twelve months.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
an interest rate of 6.47% and $100 million due 2011 at an interest rate of
6.62%. An extraordinary loss of $2 million (after-tax) was recorded in
connection with the refinancing of the $160 million non-recourse bank debt.
Equity Securities
Resources has investments in equity securities and limited partnerships.
Resources carries its investments in equity securities at their approximate fair
value as of the reporting date. Consequently, the carrying value of these
investments is affected by changes in the fair value of the underlying
securities. Fair value is determined by adjusting the market value of the
securities for liquidity and market volatility factors, where appropriate. The
aggregate fair values of such investments, which had quoted market prices at
December 31, 2001 and December 31, 2000 were $34 million and $115 million,
respectively. The potential change in fair value resulting from a hypothetical
10% change in quoted market prices of these investments amounted to $3 million
and $9 million at December 31, 2001 and December 31, 2000, respectively.
Foreign Currencies
The objective of our foreign currency risk management policy is to preserve
the economic value of cash flows in non-functional currencies. Toward this end,
Holdings' policy is to hedge all significant firmly committed cash flows
identified as creating foreign currency exposure. In addition, we typically
hedge a portion of exposure resulting from identified anticipated cash flows,
providing the flexibility to deal with the variability of longer-term forecasts
as well as changing market conditions, in which the cost of hedging may be
excessive relative to the level of risk involved.
As of December 31, 2001, Global and Resources had assets located or held in
international locations of approximately $3.4 billion and $1.3 billion,
respectively.
Resources' international investments are primarily leveraged leases of
assets located in Australia, Austria, Belgium, China, Germany, the Netherlands,
the United Kingdom, and New Zealand with associated revenues denominated in
United States Dollars ($US) and therefore, not subject to foreign currency risk.
Global's international investments are primarily in companies that generate
or distribute electricity in Argentina, Brazil, Chile, China, India, Italy,
Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign
countries involves certain additional risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries are likely to result
in declining values in such countries' currencies. As currencies fluctuate
against the $US, there is a corresponding change in Global's investment value in
terms of the $US. Such change is reflected as an increase or decrease in the
investment value and Other Comprehensive Income (Loss), a separate component of
Stockholder's Equity. As of December 31, 2001, net foreign currency devaluations
have reduced the reported amount of Energy Holdings' total Stockholder's Equity
by $258 million (after-tax), of which $79 million (after-tax) was caused by
the devaluation of the Chilean Peso and $169 million (after-tax) was caused by
the devaluation of the Brazilian Real.
Global holds a 60% ownership interest in a Tunisian generation facility
under construction. The Power Purchase Agreement, signed in 1999, contains an
embedded derivative that indexes the fixed Tunisian dinar payments to United
States Dollar exchange rates. The embedded derivative is being marked to market
through the income statement. As of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
January 1, 2001, a $9 million gain was recorded in the cumulative effect of
accounting change for SFAS No. 133. During 2001, an additional gain of $1.4
million was recorded to the income statement as a result of favorable movements
in the United States Dollar to Tunisian dinar exchange rate.
Global holds approximately a 32% ownership interest in RGE, a Brazilian
distribution company whose debt is denominated in United States Dollars. In
December 2001, the distribution company entered into a series of three forward
exchange contracts to purchase United States Dollars for Brazilian Reals in
order to hedge the risk of fluctuations in the exchange rate between the two
currencies associated with the upcoming principal payments on the debt. These
contracts expire in May, June and July 2002. As of December 31, 2001, Global's
share of the fair value and aggregate notional value of the contracts was
approximately $13 million. These contracts were established as hedges for
accounting purposes resulting in an after tax charge to Other Comprehensive
Income (OCI) of approximately $1.2 million. In addition, in order to hedge the
foreign currency exposure associated with the outstanding portion of the debt,
Global entered into a forward exchange contract in December 2001 to purchase
United States Dollars for Brazilian Reals in approximately their share of the
total debt outstanding ($61 million). The contract expired prior to December 31,
2001 and was not designated as a hedge for accounting purposes. As a result of
unfavorable movements in the United States Dollars to Brazilian Real exchange
rates, a loss of $4 million, after-tax was recorded related to this derivative
upon maturity of the contract. This amount was recorded in Other Income.
Through its 50% joint venture, Meiya Power Company, Global holds a 17.5%
ownership interest in a Taiwanese generation project under construction where
the construction contractor's fees, payable in installments through July 2003,
are payable in Euros. To manage the risk of foreign exchange rate fluctuations
associated with these payments, the project entered into a series of forward
exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of
December 31, 2001, Global's share of the fair value and aggregate notional value
of these forward exchange contracts was approximately $1 million and $16
million, respectively. These forward exchange contracts were not designated as
hedges for accounting purposes, resulting in an after-tax gain of approximately
$0.5 million. In addition, after-tax gains of $1 million were recorded during
2001 on similar forward exchange contracts expiring during the year.
During 2001, Global purchased approximately 100% of a Chilean distribution
company. In order to hedge final Chilean peso denominated payments required to
be made on the acquisition, Global entered into a forward exchange contract to
purchase Chilean Pesos for United States Dollars. This transaction did not
qualify for hedge accounting, and, as such, upon settlement of the transaction,
Global recognized an after-tax loss of $0.5 million. Furthermore, as a
requirement to obtain certain debt financing necessary to fund the acquisition,
and in order to hedge against fluctuations in the United States Dollars to
Chilean Peso foreign exchange rates, Global entered into a forward contract with
a notional value of $150 million to exchange Chilean Pesos for United States
Dollars. This transaction expires in October 2002 and is considered a hedge for
accounting purposes. As of December 31, 2001, the derivative asset value of $4
million has been recorded to OCI, net of taxes ($1.4 million). In addition,
Global holds a 50% interest in another Chilean distribution company, which was
anticipating paying its U.S. investors a return of capital. In order to hedge
the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the
distribution company entered into a forward exchange contract to purchase United
States Dollars for Chilean Pesos. Global's after-tax share of the loss on
settlement of this transaction (recorded by the distribution company) was $0.3
million.
In January 2002, RGE entered into a series of nine cross currency interest
rate swaps for the purpose of hedging its exposure to fluctuations in the
Brazilian Real to United States Dollars exchange rates with respect to its
United States Dollars denominated debt principal payments due in 2003 through
2006. The instruments convert the variable LIBOR based interest payments on the
loan balance to variable CDI based interest payments. CDI is the Brazilian
interbank interest rate. As a result, the distribution company has hedged its
foreign currency exposure but is still at risk for variability in the Brazilian
CDI interest rate during the terms of the instruments. Global's share of the
notional value of the instruments is approximately $15 million for the
instruments maturing in May, June and July of
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
2003 through 2005 and approximately $19 million for the instruments maturing in
May, June and July 2006. Also in January 2002, the distribution company entered
into two similar cross currency interest rate swaps to hedge the United States
Dollars denominated interest payments due on the debt in February 2002 and May
2002. Global's share of the notional value of these two instruments is
approximately $3 million each.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We have established credit policies that we believe significantly
minimize credit risk. These policies include an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances and the use of standardized agreements,
which may allow for the netting of positive and negative exposures associated
with a single counterparty.
As a result of the BGS auction, Power has contracted to provide generating
capacity to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. These bilateral contracts are subject to
credit risk. This credit risk relates to the ability of counterparties to meet
their payment obligations for the power delivered under each BGS contract. This
risk is substantially higher than the risk associated with potential nonpayment
by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect
these payments under the new BGS contracts could have a material impact on our
results of operations, cash flows, and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of
energy trading contracts with Enron and its affiliates in the Pennsylvania-New
Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities.
We took proper steps to mitigate our exposures to both Enron and other
counterparties who could have been affected by Enron. As of December 31, 2001,
we owed Enron approximately $23 million, net, and Enron held a letter of credit
from Power for approximately $40 million.
As a result of the California Energy Crisis, Pacific Gas Electric Company
(PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April
16, 2001. GWP, Hanford and Tracy had combined pre-petition receivables due from
PG&E, for all plants amounting to approximately $62 million. Of this amount,
approximately $25 million had been reserved as an allowance for doubtful
accounts resulting in a net receivable balance of approximately $37 million.
Global's pro-rata share of this gross receivable and net receivable was
approximately $30 million and $18 million, respectively.
In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E
which stipulates that PG&E will make full payment of the $62 million in 12 equal
installments, including interest by the end of 2002. On December 31, 2001, PG&E
paid GWF $8 million, repesenting the initial installment payment and all accrued
interest due, pursuant to the agreement.
As of December 31, 2001, GWF, Hanford and Tracy still had combined
pre-petition receivables due from PG&E for all plants amounting to approximately
$57 million. Global's pro-rata share of this receivable was $27 million. As a
result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25
million which increased operating income by $25 million (of which Global's share
was $11 million).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 9. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Our insurance coverages and maximum retrospective assessments for its
nuclear operations are as follows:
Total Site Power
Type and Source of Coverages Coverage Assessments
- ------------------------------------------------------- -------------------- ------------------
(Millions of Dollars)
Public and Nuclear Worker Liability (Primary Layer):
American Nuclear Insurers...................... $200.0 (A) $10.7
Nuclear Liability (Excess Layer):
Price-Anderson Act............................. 9,338.1 (B) 277.3
-------------------- ------------------
Nuclear Liability Total.................. $9,538.1 (C) $288.0
==================== ==================
Property Damage (Primary Layer):
Nuclear Electric Insurance Limited (NEIL)
Primary
(Salem/Hope Creek/Peach Bottom)....................... $500.0 $19.3
Property Damage (Excess Layers):
NEIL II (Salem/Hope Creek/Peach Bottom)........ 1,250.0 13.2
NEIL Blanket Excess
(Salem/Hope Creek/Peach Bottom)............. 1,000.0 (D) 2.1
-------------------- ------------------
Property Damage Total (Per Site)............... $2,750.0 (E) $34.6
==================== ==================
Accidental Outage:
NEIL I (Peach Bottom).......................... $245.0 (F) $6.0
NEIL I (Salem)................................. 281.3 7.7
NEIL I (Hope Creek)............................ 490.0 4.9
-------------------- ------------------
Replacement Power Total ................. $1,016.3 $18.6
==================== ==================
(A) The primary limit for Public Liability is a per site aggregate limit with
no potential for assessment. The Nuclear Worker Liability represents the
potential liability from workers claiming exposure to the hazard of
nuclear radiation. This coverage is subject to an industry aggregate
limit, includes annual automatic reinstatement if the Industry Credit
Rating Plan (ICRP) Reserve Fund exceeds $400 million, and has an
assessment potential under former canceled policies.
(B) Retrospective premium program under the Price-Anderson liability
provisions of the Atomic Energy Act of 1954, as amended. Nuclear is
subject to retrospective assessment with respect to loss from an incident
at any licensed nuclear reactor in the United States. This retrospective
assessment can be adjusted for inflation every five years. The last
adjustment was effective as of August 20, 1998. This retrospective
program is in excess over the Public and Nuclear Worker Liability primary
layers.
(C) Limit of liability under the Price-Anderson Act for each nuclear
incident.
(D) For property limits excess of $1.75 billion, we participate in a Blanket
Limit policy where the $1 billion limit is shared by Amergen, Exelon, and
us among the Clinton,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Oyster Creek, TMI-1, Peach Bottom, Salem and Hope Creek sites. This limit
is not subject to reinstatement in the event of a loss. Participation in
this program significantly reduces our premium and the associated
potential assessment.
(E) Effective January 1, 2002, NEIL II coverage was reduced to $600 million.
(F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity
of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for
68 weeks. Salem has an aggregate indemnity limit based on a weekly
indemnity of 2.5 million for 52 weeks followed by 80% of the weekly
indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based
on a weekly indemnity of $3.5 million for 52 weeks followed by 80% of the
weekly indemnity for 110 weeks.
The Price-Anderson Act sets the "limit of liability" for claims that could
arise from an incident involving any licensed nuclear facility in the nation.
The "limit of liability" is based on the number of licensed nuclear reactors and
is adjusted at least every five years based on the Consumer Price Index. The
current "limit of liability" is $9.5 billion. All utilities owning a nuclear
reactor, including us, have provided for this exposure through a combination of
private insurance and mandatory participation in a financial protection pool as
established by the Price-Anderson Act. Under the Price-Anderson Act, each party
with an ownership interest in a nuclear reactor can be assessed its share of
$88.1 million per reactor per incident, payable at $10 million per reactor per
incident per year. If the damages exceed the "limit of liability," the President
is to submit to Congress a plan for providing additional compensation to the
injured parties. Congress could impose further revenue raising measures on the
nuclear industry to pay claims. PSEG Nuclear's LLC maximum aggregate assessment
per incident is $277.3 million (based on our ownership interests in Hope Creek,
Peach Bottom and Salem) and its maximum aggregate annual assessment per incident
is $31.5 million. This does not include the $10.7 million that could be assessed
under the nuclear worker policies.
Further, a decision by the U.S. Supreme Court, not involving us, has held
that the Price-Anderson Act did not preclude awards based on state law claims
for punitive damages.
We are a member of an industry mutual insurance company, Nuclear Electric
Insurance Limited (NEIL). NEIL provides the primary property and decontamination
liability insurance at Salem/Hope Creek and Peach Bottom. NEIL also provides
excess property insurance through its decontamination liability, decommissioning
liability, and excess property policy and replacement power coverage through its
accidental outage policy. NEIL policies may make retrospective premium
assessments in case of adverse loss experience. Our maximum potential
liabilities under these assessments are included in the table and notes above.
Certain provisions in the NEIL policies provide that the insurer may suspend
coverage with respect to all nuclear units on a site without notice if the NRC
suspends or revokes the operating license for any unit on a site, issues a
shutdown order with respect to such unit or issues a confirmatory order keeping
such unit down.
Guaranteed Obligations
Power has guaranteed certain energy trading contracts of ER&T. As of
December 31, 2001 Power has issued or primarily executed $506 million of
guarantees on behalf of ER&T, of which Power's exposure is $153 million.
We, Energy Holdings or Global have guaranteed certain obligations of
Global's affiliates, including the successful completion, performance or other
obligations related to certain of the projects, in an aggregate amount of
approximately $230 million as of December 31, 2001. A substantial portion of
such guarantees is eliminated upon successful completion, performance and/or
refinancing of construction debt with non-recourse project debt.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations
concerning site investigation and remediation require an ecological evaluation
of potential injuries to natural resources in connection with a remedial
investigation of contaminated sites. The NJDEP is presently working with
industry to develop procedures for implementing these regulations. These
regulations may substantially increase the costs of remedial investigations and
remediations, where necessary, particularly at sites situated on surface water
bodies. PSE&G and predecessor companies owned and/or operated certain facilities
situated on surface water bodies, certain of which are currently the subject of
remedial activities. The financial impact of these regulations on these projects
is not currently estimable. We do not anticipate that the compliance with these
regulations will have a material adverse effect on its financial position,
results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with NJDEP under a program (Remediation Program)
to assess, investigate and, if necessary, remediate environmental conditions at
PSE&G's former manufactured gas plant sites. To date, 38 sites have been
identified. The Remediation Program is periodically reviewed and revised by
PSE&G based on regulatory requirements, experience with the Remediation Program
and available remediation technologies. The long-term costs of the Remediation
Program cannot be reasonably estimated, but experience to date indicates that at
least $20 million per year could be incurred over a period of about 30 years
since inception of the program in 1988 and that the overall cost could be
material. The costs for this remediation effort are recovered through the SBC.
Net of insurance recoveries, costs incurred from January 1, 2001 through
December 31, 2001 for the Remediation Program amounted to approximately $22.8
million. Net of insurance recoveries, costs incurred through December 31, 2001
for the Remediation Program amounted to $164.6 million. In addition, at December
31, 2001, PSE&G's estimated liability for remediation costs through 2004
aggregated $87 million. Expenditures beyond 2004 cannot be reasonably
estimated.
Passaic River Site
The EPA has determined that a six mile stretch of the Passaic River in
Newark, New Jersey is a "facility" within the meaning of that term under the
Federal Comprehensive Environmental Response, Compensation and Liability Act of
1980 (CERCLA) and that, to date, at least thirteen corporations, including
PSE&G, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the Passaic River "facility." PSE&G
and certain of its predecessors operated industrial facilities at properties
within the Passaic River "facility," comprised of four former manufactured gas
plants (MGP), one operating electric generating station and one former
generating station. Costs to clean up former MGPs are recoverable from utility
customers under the SBC. The operating station has been transferred to Power,
which is responsible for its clean up. We cannot predict what action, if any,
the EPA or any third party may take against PSE&G and Power with respect to
these matters, or in such event, what costs PSE&G and Power may incur to address
any such claims. However, such costs may be material.
Prevention of Significant Deterioration (PSD)/New Source Review
The EPA and NJDEP issued a demand in March 2000 under section 114 of the
Federal Clean Air Act (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/New Source Review regulations. We
completed our response to the section 114 information request in November 2000.
In January 2002, we reached an agreement with the state
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
and federal governments to resolve allegations of noncompliance with federal and
State of New Jersey New Source Review (NSR) regulations. Under that agreement,
we will install advanced air pollution controls over 10 years that will
dramatically reduce emissions of NOx, SO2, particulate matter, and mercury from
the Hudson and Mercer coal units. The estimated cost of the program is $337
million. We also will pay a $1.4 million civil penalty and spend up to $6
million on supplemental environmental projects.
The EPA had also asserted that PSD requirements are applicable to Bergen 2,
such that we were required to have obtained a permit before beginning actual
on-site construction. We disputed that PSD requirements were applicable to
Bergen 2. The agreement resolving the NSR allegations concerning Hudson and
Mercer also resolved the dispute over Bergen 2, and allowed construction of the
unit to be completed and operation to commence.
New Generation and Development
Power
PSEG Power New York Inc., an indirect subsidiary of Power, is in the
process developing the Bethlehem Energy Center, a 750 MW combined-cycle power
plant that will replace the 400 MW Albany Steam Station, which was acquired from
Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000. Pending a final
project certification decision that is expected within 12 months, Power will be
obligated to pay Niagara Mohawk up to $9 million if it redevelops the Albany
Station. However, Power expects this payment will be reduced based on conditions
related to the service date and regulatory requirements.
Power is constructing a 546 MW natural gas-fired, combined cycle electric
generation plant at Bergen Generation Station at a cost of approximately $290
million with completion expected in June 2002. Power is also constructing an
1,218 MW combined cycle generation plant at Linden for approximately $590
million expected to be completed in May 2003.
In August 2001, subsidiaries of Power closed with a group of banks on
non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg,
Indiana. The Waterford project will be completed in two phases and are expected
to achieve commercial operation in June 2002 and May 2003, respectively. The
Lawrenceburg project is expected to achieve commercial operation by May 2003.
The total combined project cost for Waterford and Lawrenceburg is estimated at
$1.2 billion. Power's required estimated equity investments for these projects
is approximately $400 million. In connection with these projects, ER&T has
entered into a five-year tolling agreement pursuant to which it is obligated to
purchase the output of these facilities at stated prices. As a result, ER&T
will bear the price risk related to the output of these generation facilities
which are scheduled to be completed in 2003.
Power has filed an application with the New York State Public Service
Commission for permission to construct and operate a direct generator lead
(dedicated transmission line) that would deliver up to 1,200 MW of electricity
to the West Side of Manhattan from the Bergen Generating Station. Applications
for New Jersey and Federal approvals are expected to be filed in the near
future. Estimated costs are not expected to exceed $100 million for one 500 MW
line.
In addition, Power has other commitments to purchase equipment and services
to meet its current plans to develop additional generating capacity. The
aggregate amount due under these commitments is approximately $ 500 million.
Energy Holdings
In March 2001, Global, through Dhofar Power Company (DPCO), signed a
20-year concession with the government of Oman to privatize the electric system
of Salalah. The project commenced construction in September
103
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
2001 and is expected to achieve commercial operation by March 2003. Total
project cost is estimated at $277 million. Global's equity investment, including
contingencies, is expected to be approximately $82 million.
In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between
Global and Harbinger GWF LLC, entered into a 10-year power purchase agreement
with the California Department of Water Resources to provide 340 MW of electric
capacity to California from three new natural gas-fired peaker plants that GWF
Energy expects to build and operate in California. Total project cost is
estimated at $325 million. The first plant, a 90 MW facility, was completed and
began operation in August 2001. Global's permanent equity investment in these
plants, including contingencies, is not expected to exceed $100 million after
completion of project financing, expected to occur in 2002.
On February 25, 2002 the Public Utilities Commission of the State of
California (CPUC) filed a complaint with the Federal Energy Regulatory
Commission (FERC) under Section 206 of the Federal Power Act against sellers
who, pursuant to long-term, FERC authorized contracts, provide power to the
California Division of Water Resources (DWR).
GWF Energy LLC, an affiliate of PSEG Global, as a long-term contract to
sell wholesale power to the DWR and is a named respondent in this proceeding.
The CPUC's complaint, which addresses 44 transactions embodied in 32 contracts
with 22 sellers, alleges that collectively, the specified long term wholesale
power contracts are priced at unjust and unreasonable levels and requests FERC
to abrogate the contracts to enable the State to obtain replacement contracts
as necessary or in the alternative, to reform the contracts to provide for
just and reasonable pricing, reduce the length of the contracts, and strike
from the contracts the specific non-price and conditions found to be unjust
and unreasonable. In the event of an adverse ruling by the FERC, Energy
Holdings and Global would reconsider any plans to invest in generation
facilities in California.
As of December 31, 2001, Global had $281 million invested in two 1000 MW
gas-fired combined cycle electric generating facilities in Texas, including
approximately $165 million of notes receivable earning an annual rate of 12%. Of
the $165 million outstanding at December 31, 2001, $88 million was repaid in
February 2002. Texas Independent Energy's (TIE) funding for these payments to
Global were made from equity contributions of $44 million from Global and $44
million from Panda Energy, our partner for this project. Earnings and cash
distributions from TIE during 2001 were $15 million and $25 million,
respectively, below expectations due to lower energy prices resulting from the
over-supply of energy in the Texas power market and mild summer temperatures
surpressing demand in the region. Global expects this trend to continue until
the 2004-2005 time frame when market prices are expected to increase, as older
less efficient plants in the Texas power market are expected to be retired and
the demand for electricity is expected to increase. However, no assurances can
be given as to the accuracy of these estimates. Current projections of future
cash flows for each plant, using independent market studies for estimating gas
and electricity prices, market heat rates and capacity prices, do not indicate
the investment to be impaired. We believe that those independent market studies
are the best available for estimating future prices.
Potential Asset Impairments
Global has total investment exposure in Argentina of approximately $632
million. The investments include the following minority interests, with
investment exposure of approximately $420 million, jointly owned by Global and
AES, which are the subject of the Stock Purchase Agreement: a 30% interest in
three Argentine electric distribution companies, Empresa Distribuidora de
Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES), and
Empresa Distribuidora La Plata S.A. (EDELAP); a 19% share in the 650 MW Central
Termica San Nicolas power plant (CTSN); and a 33% interest in the 850 MW Parana
power plant (Parana) nearing completion of construction. In addition to these
investments, Global owns a 90% interest in another Argentine company, Empresa
Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), with about $212
million of investment exposure.
Global's Argentine properties continue to operate, but are faced with
considerable fiscal and cash flow uncertainties due to economic, political and
social conditions in Argentina. Moreover, Parana, EDEN, EDES and EDELAP have
recently received notices of default from its international lenders related to
their non recourse financings. If Argentine conditions do not improve soon,
Global's other Argentine properties may also default on their international
financings. Under a worst case scenario, if PSEG Global were to cease all
operations in Argentina, it would record a pre-tax write off of approximately
$632 million. See Note 18. "Subsequent Events" for a discussion of the sale to
AES.
As of December 31, 2001, we had recorded unamortized goodwill in the amount
of $649 million, of which $479 million was recorded in connection with Global's
acquisitions of SAESA and Electroandes in Chile and Peru in August and December
of 2001, respectively. The amortization expense related to goodwill was
approximately $3 million for the year ended December 31, 2001.
104
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
As of December 31, 2001, our pro-rata share of goodwill included in equity
method investees totaled $375 million. Such goodwill is not consolidated on our
balance sheet in accordance with generally accepted accounting principles.
Global's share of the amortization expense related to such goodwill was
approximately $8 million.
We are currently evaluating the effect of adopting SFAS 142 on the recorded
amount of goodwill. Some or all of the goodwill at: Rio Grande Energia (RGE)
totaling $142 million (PSEG share), EDEERSA totaling $63 million and Energy
Technologies totaling $53 million could be impaired upon completion of our
evaluation. The impact of adopting SFAS 142 is likely to be material to our
financial position and results of operations. As of December 31, 2001, our
unamortized goodwill and pro-rata share of goodwill in equity method investees
was as follows:
As of
December 31, 2000
----------------------------------------------------------------------
(Millions of dollars)
EDEERSA...................................... $63
SAESA........................................ 315
ElectroAndes................................. 164
Tanir Bavi................................... 27
Chorzow...................................... 6
Total Global............................ 575
Energy Technologies.......................... 53
Power........................................ 21
-----------------------
Total On Balance Sheet................ $649
-----------------------
Global
---------------------------------------------
RGE.......................................... $142
Chilquinta/Luz............................... 174
Luz Del Sur.................................. 34
Kalaeloa..................................... 25
-----------------------
Total Off Balance Sheet 375
-----------------------
Total Goodwill $1,024
=======================
Minimum Lease Payments
We and our subsidiaries lease administrative office space under various
operating leases. As of December 31, 2001 our rental expense under these leases
was approximately $10 million dollars. Total future minimum lease payments as of
December 31, 2001 are:
(Millions of Dollars)
---------------------
2002 $14
2003 10
2004 10
2005 7
2006 4
Thereafter 19
-----------
Total minimum lease payments $64
===========
PSE&G has entered into a capital lease for administrative office space. The
total future minimum payments and present value of this capital lease as of
December 31, 2001 are:
105
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
(Millions of Dollars)
---------------------
2002 $8
2003 8
2004 8
2005 8
2006 8
Thereafter 62
-----------
Total minimum lease payments 102
-----------
Less: Imputed Interest (42)
-----------
Present Value of net minimum lease payments $60
===========
Note 10. Nuclear Decommissioning Trust
In accordance with Federal regulations, entities owning an interest in
nuclear generating facilities are required to determine the costs and funding
methods necessary to decommission such facilities upon termination of operation.
As a general practice, each nuclear owner places funds in independent external
trust accounts it maintains to provide for decommissioning. PSE&G currently
recovers from its customers the amounts to be paid into the trust fund each year
and remits these amounts to Power.
Power maintains the external master nuclear decommissioning trust
previously established by PSE&G. This trust contains two separate funds: a
qualified fund and a non-qualified fund. Section 468A of the Internal Revenue
Code limits the amount of money that can be contributed into a "qualified" fund.
Contributions made into a qualified fund are tax deductible. In the most recent
study the total cost of decommissioning its share of its five nuclear units was
estimated at $986 million in year-end 1995 dollars, excluding contingencies.
Pursuant to the Final Order, PSE&G will collect $29.6 million annually
through the SBC and will remit to Power an equivalent amount solely to fund the
trust. The fair market value of these funds as of December 31, 2001 and 2000 was
$817 million and $716 million, respectively.
Contributions made into the Nuclear Decommissioning Trust Funds are
invested in debt and equity securities. These marketable debt and equity
securities are recorded at amounts that approximate their fair market value.
Those securities have exposure to market price risk. The potential change in
fair value, resulting from a hypothetical 10% change in quoted market prices of
these securities amounts to $82 million. The ownership of the Nuclear
Decommissioning Trust Funds was transferred to Nuclear with the transfer of the
generation-related assets from PSE&G to Power.
With the purchase of Atlantic City Electric Company's (ACE) and Delmarva
Power and Light Company (DP&L)'s interests in Salem, Peach Bottom and Hope
Creek, we received a transfer of $82 million and $50 million representing those
companies respective NDT funds related to the stations in 2001 and 2000,
respectively.
106
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 11. Income Taxes
A reconciliation of reported income tax expense with the amount computed by
multiplying pretax income by the statutory Federal income tax rate of 35% is as
follows:
2001 2000 1999
-------------- -------------- ---------------
(Millions of Dollars)
Net Income (Loss)............................................. $770 $764 $(81)
Extraordinary Item (Net of Tax 2001, $1; 1999 $345)...... 2 -- 804
Cumulative Effect of a Change in Accounting Principle (9) -- --
(Net of Tax)
-------------- -------------- ---------------
Net Income before Extraordinary Item.......................... 763 764 723
Preferred securities (net).................................... 5 9 9
-------------- -------------- ---------------
Subtotal............................................ 768 773 732
-------------- -------------- ---------------
Income taxes:
Federal - Current........................................ 249 150 398
Deferred ...................................... 57 228 63
ITC............................................ (3) (2) (12)
-------------- -------------- ---------------
Total Federal............................... 303 376 449
-------------- -------------- ---------------
State - Current.......................................... 63 160 132
Deferred ......................................... (1) (50) (13)
-------------- -------------- ---------------
Total State................................. 62 110 119
-------------- -------------- ---------------
Foreign - Current........................................ 1 -- --
Deferred ...................................... 7 4 (5)
-------------- -------------- ---------------
Total Foreign............................... 8 4 (5)
-------------- -------------- ---------------
Total............................................... 373 490 563
-------------- -------------- ---------------
Pretax income................................................. $1,141 $1,263 $1,295
============== ============== ===============
Reconciliation between total income tax provisions and tax computed at the
statutory tax rate on pretax income:
2001 2000 1999
------------- -------------- ---------------
(Millions of Dollars)
Tax computed at the statutory rate............................ $399 $442 $453
Increase (decrease) attributable to flow through of certain
tax adjustments:
Plant Related Items...................................... (41) (15) 35
Amortization of investment tax credits................... (3) (2) (12)
Tax Effects Attributable to Foreign Operations........... (20) (14) (7)
New Jersey Corporate Business Tax........................ 41 74 84
Other.................................................... (3) 5 10
------------- -------------- ---------------
Subtotal............................................ (26) 48 110
------------- -------------- ---------------
Total income tax provisions......................... $373 $490 $563
============= ============== ===============
Effective income tax rate..................................... 32.8% 38.8% 43.5%
We provide deferred taxes at the enacted statutory tax rate for all
temporary differences between the financial statement carrying amounts and the
tax bases of existing assets and liabilities irrespective of the treatment for
rate-making purposes. Management believes that it is probable that the
accumulated tax benefits that previously have been treated as a flow-through
item to PSE&G customers will be recovered from utility customers in the future.
Accordingly, an offsetting regulatory asset was established. As of December 31,
2001, PSE&G had a deferred tax liability and an offsetting regulatory asset of
$302 million representing the tax costs expected to be recovered
107
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--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
through rates based upon established regulatory practices which permit recovery
of current taxes payable. This amount was determined using the enacted Federal
income tax rate of 35% and State income tax rate of 9%.
The following is an analysis of deferred income taxes:
December 31,
-----------------------------
2001 2000
------------- -------------
Deferred Income Taxes (Millions of Dollars)
- ---------------------
Assets:
Current (net)........................................... $21 $23
------------- -------------
Non-current:
Unrecovered Investment Tax Credits.................... 19 20
Nuclear Decommissioning............................... 25 26
FASB 133.............................................. 16 --
New Jersey Corporate Business Tax..................... 544 544
OPEB ................................................. 83 64
Cost of Removal....................................... 54 55
Development Fees...................................... 21 17
Foreign Currency Translation.......................... 29 23
Contractual Liabilities and Environmental Costs....... 35 35
Market Transition Charge.............................. 59 40
------------- -------------
Total Non-current................................ 885 824
------------- -------------
Total Assets..................................... 906 847
------------- -------------
Liabilities:
Non-current:
Plant Related Items................................... 905 842
Securitization-EMP.................................... 1594 1,657
Leasing Activities.................................... 1146 987
Partnership Activities................................ 73 101
Conservation Costs.................................... 24 124
Pension Costs......................................... 94 58
Taxes Recoverable Through Future Rates (net).......... 130 90
Income from Foreign Operation......................... 41 14
Other................................................. 11 (16)
------------- -------------
Total Non-current................................ 4,018 3,857
------------- -------------
Total Liabilities................................ 4,018 3,857
------------- -------------
Summary -- Accumulated Deferred Income Taxes
Net Current Assets...................................... 21 23
Net Non-current Liability............................... 3,133 3,033
------------- -------------
Total.............................................. $3,112 $3,010
============= =============
108
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 12. Pension, Other Postretirement Benefit and Savings Plans
We sponsor several qualified and nonqualified pension plans and other
postretirement benefit plans covering our, as well as our participating
affiliates, current and former employees who meet certain eligibility
criteria. The following table provides a reconciliation of the changes in the
benefit obligations and fair value of plan assets over each of the two years
in the period ended December 31, 2001 and a reconciliation of the funded
status for at the end of both years.
The pension benefits table above provides information relating to the funded
status of all qualified and nonqualified pension plans and other
postretirement benefit plans on an aggregate basis.
Pension and Other Postretirement Benefit Plans
- -----------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------------------- -----------------------------------
$ in Millions 2001 2000 2001 2000
- -----------------------------------------------------------------------------------------------------------------------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Year $ 2,494.4 $ 2,383.6 $ 702.7 $ 691.2
Service Cost 62.8 60.5 16.3 12.0
Interest Cost 181.6 172.6 46.6 53.9
Actuarial (Gain)/Loss 90.0 (6.2) 8.2 (20.1)
Benefits Paid (153.3) (145.3) (40.4) (36.6)
Plan Amendments -- 22.2 (59.6) 0.0
Business Combinations -- 7.0 -- 2.3
------------ ------------- ------------ ---------------
Benefit Obligation at End of Year 2,675.5 2,494.4 673.8 702.7
------------ ------------- ------------ ---------------
Change in Plan Assets
Fair Value of Assets at Beginning of Year 2,376.1 2,525.6 28.4 28.5
Actual Return on Plan Assets (85.3) (11.8) (1.2) (0.1)
Employer Contributions 90.3 2.8 53.4 36.6
Benefits Paid (153.3) (145.3) (40.4) (36.6)
Business Combinations -- 4.8 -- 0.0
------------ ------------- ------------ ---------------
Fair Value of Assets at End of Year 2,227.8 2,376.1 40.2 28.4
------------ ------------- ------------ ---------------
Reconciliation of Funded Status
Funded Status (447.7) (118.3) (633.6) (674.3)
Unrecognized Net
Transition Obligation 12.7 20.8 275.8 337.9
Prior Service Cost 113.6 129.4 -- 25.1
(Gain)/Loss 455.6 70.3 (120.1) (139.0)
------------ ------------- ------------ ---------------
Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3)
============ ============= ============ ===============
Amounts Recognized In Statement
Of Financial Position
Prepaid Benefit Cost $ 160.5 $ 125.4 $ -- $ 0.0
Accrued Cost (53.3) (49.5) (477.9) (450.3)
Intangible Asset 19.8 22.6 N/A N/A
Accumulated Other Comprehensive Income 7.2 3.7 N/A N/A
------------ ------------- ------------ ---------------
Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3)
============ ============= ============ ===============
Separate Disclosure for Pension Plans
With Accumulated Benefit Obligation
In Excess of Plan Assets:
Projected Benefit Obligation at End of Year $ 76.3 $ 66.7
Accumulated Benefit Obligation at End of Year $ 61.3 $ 52.7
Fair Value of Assets at End of Year $ 8.4 $ 4.5
109
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
- ------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------------------ ---------------------------------------
$ in Millions 2001 2000 1999 2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------
Components of Net Periodic Benefit Cost
Service Cost $ 62.8 $ 60.5 $ 68.0 $ 16.3 $ 12.0 $ 13.1
Interest Cost 181.6 172.6 163.3 46.6 53.9 51.3
Expected Return on Plan Assets (211.1) (221.0) (197.3) (3.1) (2.6) (1.7)
Amortization of Net
Transition Obligation 8.1 8.1 8.1 27.3 30.4 30.4
Prior Service Cost 15.9 14.3 14.1 0.0 2.2 2.2
(Gain)/Loss 0.4 0.5 0.8 (5.9) (3.4) (3.0)
----------- ------------ ----------- ------------- ------------ ------------
Net Periodic Benefit Cost $ 57.7 $ 35.0 $ 57.0 $ 81.2 $ 92.5 $ 92.3
=========== ============ =========== ============= ============ ============
Components of Total Benefit Expense
Net Periodic Benefit Cost $ 57.7 35.0 57.0 $ 81.2 $ 92.5 $ 92.3
Effect of Regulatory Asset 0.0 0.0 0.0 19.3 19.3 19.3
Total Benefit Expense Including Effect of
----------- ------------ ----------- ------------- ------------ ------------
Regulatory Asset $ 57.7 $ 35.0 $ 57.0 $ 100.5 $ 111.8 $ 111.6
=========== ============ =========== ============= ============ ============
Components of Other Comprehensive Income
Decrease in Intangible Asset $ 2.8 $ 0.9 $ 2.6
Increase in Additional Minimum Liability 0.7 (1.8) (3.4)
----------- ------------ ----------- ------------- ------------ ------------
Other Comprehensive Income $ 3.5 $ (0.9) $ (0.8) N/A N/A N/A
=========== ============ =========== ============= ========== ============
Weighted-Average Assumptions as of December 31
Discount Rate 7.25% 7.50% 7.50% 7.25% 7.50% 7.50%
Expected Return on Plan Assets 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Rate of Compensation Increase 4.69% 4.69% 4.69% 4.69% 4.69% 4.69%
Rate of Increase in Health Benefit Costs
Administrative Expense 5.00% 5.00% 5.00%
Dental Costs 6.00% 6.00% 5.00%
Pre-65 Medical Costs
Immediate Rate 9.50% 10.00% 11.00%
Ultimate Rate 6.00% 6.00% 5.00%
Year Ultimate Rate Reached 2008 2008 2011
Post-65 Medical Costs
Immediate Rate 7.50% 8.00% 7.00%
Ultimate Rate 6.00% 6.00% 5.00%
Year Ultimate Rate Reached 2004 2004 2003
Effect of a Change in the Assumed Rate of
Increase in Health Benefit Costs
Effect of a 1% Increase On
Total of Service Cost and Interest Cost 4.6 4.5 4.5
Postretirement Benefit Obligation 45.4 48.5 45.7
Effect of a 1% Decrease On
Total of Service Cost and Interest Cost (3.9) (3.8) (4.7)
Postretirement Benefit Obligation (39.1) (41.4) (39.3)
In 1999, $12 million was funded, as allowed. Remaining OPEB costs will not
be funded in an external trust, as mandated by the BPU.
110
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In October 1999, PSE&G recorded deferred assets and liabilities associated
with the payment and collection of co-owner related OPEB costs. Such costs will
be amortized over the remainder of the twenty-year period through 2013, in
accordance with SFAS 106. No assurances for recovery of such assets and
liabilities can be given.
401K Plans
We sponsor two defined contribution plans. Represented employees of PSE&G,
Power and Services are eligible for participation in the PSEG Employee Savings
Plan (Savings Plan), while non-represented employees of PSE&G, Power, Energy
Holdings and Services are eligible for participation in the PSEG Thrift and
Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which
eligible employees may contribute up to 25% of their compensation. Employee
contributions up to 7% for Savings Plan participants and up to 8% for Thrift
Plan participants are matched with employer contributions of cash or PSEG
common stock equal to 50% of such employee contributions. For periods prior to
March 1, 2002, Employer contributions, related to participant contributions in
excess of 5% and up to 7%, were made in shares of PSEG common stock for
Savings Plan participants. For periods prior to March 1, 2002, Employer
contributions, related to participant contributions in excess of 6% and up to
8%, were made in shares of PSEG common stock for Thrift Plan participants.
Beginning on March 1, 2002, and thereafter, all Employer contributions will be
made in cash to the each plan. The amount expensed for Employer matching
contributions to the plans was approximately $23, $22 million, and $21 million
in 2001, 2000, and 1999, respectively.
Note 13. Stock Options, Stock Purchase Plan and Stock Repurchase Program
Stock Options
We apply APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related Interpretations in accounting for stock-based compensation plans,
which are described below. Accordingly, compensation expense has been
recognized for performance units and dividend equivalent rights issued in
tandem with an equal number of options under its fixed stock option grants
under the 1989 Long-Term Incentive Plan (1989 LTIP). Performance units and
dividend equivalents provide cash payments, dependent upon our future
financial performance in comparison to other companies and dividend payments
made on our Common Stock, to assist recipients in exercising options granted.
Prior to 1997, all options were granted in tandem with performance units and
dividend equivalent rights. In 2001, 2000 and 1999, there were no options
granted in tandem with performance units and dividend equivalent rights. No
compensation cost has been recognized for fixed stock option grants since the
exercise price of the stock options equaled the market price of the underlying
stock on the date of grant. Had compensation costs for stock option grants
been determined based on the fair value at the grant dates for awards under
these plans in accordance with SFAS No. 123 "Accounting for Stock-Based
Compensation," there would have been a charge to our net income of
approximately $9.6 million, $3.6 million and $1.8 million in 2001, 2000 and
1999, respectively, with a $(0.05), $(0.02) and $(0.01) impact on earnings per
share in 2001, 2000 and 1999, respectively.
Under our 1989 LTIP and 2001 Long-Term Incentive Plan (2001 LTIP),
non-qualified options to acquire shares of common stock may be granted to
officers and other key employees selected by the Organization and Compensation
Committee of our Board of Directors, the plan's administrative committee (the
"Committee"). Payment by option holders upon exercise of an option may be made
in cash or, with the consent of the Committee, by delivering previously acquired
shares of PSEG common stock. In instances where an optionee tenders shares
acquired from a grant previously exercised that were held for a period of less
than six months, an expense will be recorded for the difference between the fair
market value at exercise date and the option price. Options are exercisable over
a period of time designated by the Committee (but not prior to one year from the
date of grant) and
111
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
are subject to such other terms and conditions as the Committee determines.
Vesting schedules may be accelerated upon the occurrence of certain events, such
as a change in control. Options may not be transferred during the lifetime of a
holder.
The 1989 LTIP currently provides for the issuance of up to 15,000,000
options to purchase shares of common stock. At December 31, 2001, there were
10,759,350 options available for future grants under the 1989 LTIP.
The 2001 LTIP currently provides for the issuance of up to 15,000,000
options to purchase shares of common stock. At December 31, 2001, there were
11,169,500 options available for future grants under the 2001 LTIP.
Since the 1989 LTIP's inception, we have purchased shares on the open
market to meet the exercise of stock options. The difference between the cost of
the shares (generally purchased on the date of exercise) and the exercise price
of the options has been reflected in Stockholders' Equity except where otherwise
discussed.
Changes in common shares under option for the three fiscal years in the
period ended December 31, 2001 are summarized as follows:
2001 2000 1999
---------------------------- ---------------------------- -----------------------------
Weighted Weighted Weighted
Average Average Average
Options Exercise Price Options Exercise Price Options Exercise Price
----------- ---------------- ----------- ---------------- ------------ ----------------
Beginning of year 5,186,099 40.38 2,561,883 $34.60 1,243,800 $36.01
Granted 2,833,000 41.84 2,745,500 45.33 1,367,000 33.13
Exercised (303,135) 32.83 (110,684) 29.87 (44,167) 30.37
Canceled (63,501) 41.27 (10,600) 31.23 (4,750) 28.01
----------- ----------- ----------- ---------- ------------ ----------
End of year 7,652,463 41.22 5,186,099 40.38 2,561,883 34.60
----------- ----------- ----------- ---------- ------------ ----------
Exercisable at end of year 2,767,830 39.19 1,170,278 $34.91 412,738 $35.07
----------- ----------- ----------- ---------- ------------ ----------
-----------------------------------------------------------------------------------------------
Weighted average fair
value of options granted
during the year $7.22 $8.73 $4.20
=========== ========== ==========
For this purpose, the fair value of each option grant is estimated on the
date of grant using the Black-Scholes option-pricing model with the following
weighted average assumptions used for grants in 2001, 2000, and 1999,
respectively: expected volatility of 28.22%, 26.63%, and 21.45%, risk free
interest rates of 4.40%, 6.06%, and 6.16%, expected lives of 4.2 years, 4.4
years, and 4 years, respectively. There was a dividend yield of 5.18% in 2001,
4.77% in 2000, and 6.52% in 1999 on the non-tandem grants.
The following table provides information about options outstanding at
December 31, 2001:
- -------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
- -------------------------------------------------------------------------- -------------------------------------
Weighted Weighted Weighted
Average Average Average
Range of Outstanding at Remaining Exercise Exercisable at Exercise
Exercise Prices December 31, 2001 Contractual Life Price December 31, 2000 Price
- -------------------------------------------------------------------------- -------------------------------------
$25.03-$30.02 173,300 5.6 years $ 29.56 173,300 $ 29.56
$30.03-$35.03 1,158,663 7.6 years 33.13 782,322 33.13
$35.04-$40.03 774,500 5.9 years 39.31 774,500 39.31
$40.04-$45.04 3,263,000 9.1 years 41.79 400,000 44.06
$45.05-$50.05 2,283,000 8.8 years 46.06 637.708 46.06
- -------------------------------------------------------------------------- -------------------------------------
$25.03-$50.05 7,652,463 8.3 years $ 41.22 2,767,830 $ 39.19
- -------------------------------------------------------------------------- -------------------------------------
112
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In June 1998, the Committee granted 150,000 shares of restricted common
stock to a key executive. An additional 60,000 shares or restricted stock was
granted to this executive in November 2001. These shares are subject to
restrictions on transfer and subject to risk of forfeiture until earned by
continued employment. The shares vest on a staggered schedule beginning on March
31, 2002 and become fully vested on March 31, 2007. The unearned compensation
related to this restricted stock grant as of December 31, 2001 is approximately
$5 million and is included in retained earnings on the consolidated balance
sheets.
In addition the Committee granted 100,000 shares of restricted common stock
to another key executive. These shares are subject to restrictions on transfer
and subject to risk of forfeiture until earned by continued employment. The
shares vest on at one-third per year beginning on July 1, 2002 and become fully
vested on July 1, 2004. The unearned compensation related to this restricted
stock grant as of December 31, 2001 is approximately $4 million and is included
in retained earnings on the consolidated balance sheets.
Our Stock Plan for Outside Directors provides non-employee directors, as
part of their annual retainer, 600 shares of common stock, increased from 300
shares per year beginning in 1999. With certain exceptions, the restrictions on
the stock provide that the shares are subject to forfeiture if the individual
ceases to be a director at any time prior to the Annual Meeting of Stockholders
following his or her 70th birthday. The fair value of these shares is recorded
as compensation expense in the consolidated statements of income.
Employee Stock Purchase Plan
We maintain an employee stock purchase plan for all eligible employees.
Under the plan, shares of the common stock may be purchased at 95% of the fair
market value. Employees may purchase shares having a value not exceeding 10% of
their base pay. During 2001, 2000 and 1999, employees purchased 85,552, 101,986,
and 98,099 shares at an average price of $44.02, $37.06, and $38.21 per share,
respectively. At December 31, 2001, 1,289,780 shares were available for future
issuance under this plan.
Stock Repurchase Program
In September 1998, our Board of Directors authorized the repurchase of 30
million shares of Common Stock. A total of 24.3 million shares were repurchased
at a cost of approximately $905 million under this program as of December 31,
2000, when the authorization expired. In September 2001, the board re-authorized
the purchase of the balance of 5.7 million shares. As of December 31, 2001, an
additional 2.2 million shares were repurchased at a cost of approximately $92
million.
Note 14. Financial Information by Business Segments
Basis of Organization
The reportable segments were determined by Management in accordance with
SFAS 131, "Disclosures About Segments of an Enterprise and Related Information"
(SFAS 131). These segments were determined based on how Management measures the
performance based on segment net income, as illustrated in the following table,
and how it allocates resources to our businesses. Our organizational structure
supports these segments.
113
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Generation
The generation segment of our business earns revenues by selling energy on
a wholesale basis under contract to power marketers and to load serving entities
(LSEs) and by bidding the energy, capacity and ancillary services of Power into
the market.
Electrical energy is produced by generation plants and is ultimately
delivered to customers for use in lighting, heating and air conditioning and
operation of other electrical equipment. Energy is our principal product and is
priced on a usage basis, typically in cents per thousand Watt-hours (kWh) or
dollars per million Watt-hours (mWh). Capacity, as a product that is distinct
from energy, is a commitment to the ISO that a given unit will be available for
dispatch if it is needed to meet system demand. Capacity is typically priced in
dollars per MW for a given sale period (e.g., mW-day or mW-year). Capacity
generally refers to the power output rating of a generation plant, measured on
an instantaneous basis. Ancillary services constitutes another category of
energy-related activities supplied by generation unit owners to the ISO.
Energy Trading
The energy trading segment of our business earns revenues by trading
energy, capacity, fixed transmission rights, fuel and emission allowances in the
spot, forward and futures markets. Our energy trading segment also earns
revenues through financial transactions, including swaps, options and futures in
the electricity markets.
We engage in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights, fuel and emission
allowances in the spot, forward and futures markets primarily within PJM, but
also throughout the Super Region. We are also involved in financial transactions
that include swaps, options and futures in the electricity markets. In addition
to participating in each of the major electricity supply and capacity markets in
the Super Region, we also market and trade a broad spectrum of other energy and
energy-related products. These products include coal, oil, natural gas, sulfur
dioxide and nitrous oxide emissions allowances and financial instruments
including fixed transmission rights. Our marketing and energy trading activity
for these products extends throughout the United States and involves physical
and financially settled transactions, futures, options, swaps and basis
contracts. None of our trading revenue with any individual counterparty exceeds
10%.
We have developed a hedging and overall risk management strategy to limit
our risk exposure and to track our positions in the wholesale markets. Hedging
is used as the primary method for protecting against adverse price fluctuations
and involves taking a position in a related financial instrument that is
designed to offset the risk associated with the original position. We only use
hedging instruments that correspond to the generation, purchase or sale of
electricity and the purchase or sale of fuel.
PSE&G
All operations of this segment are conducted by PSE&G. The PSE&G segment
generates revenue from its tariffs under which it provides electric transmission
and electric and gas distribution services to residential, commercial and
industrial customers in New Jersey. The rates charged for electric transmission
are regulated by FERC while the rates charged for electric and gas distribution
are regulated by the BPU. Revenues are also earned from a variety of other
activities such as sundry sales, the appliance service business, wholesale
transmission services and other miscellaneous services.
114
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Global
Global earns revenues from its investment in and operation of projects in
the generation and distribution of energy, both domestically (exclusive of the
Super Region included in the Generation segment above) and internationally.
Resources
Resources receives revenues from its passive investments in leveraged
leases, limited partnerships, leveraged buyout funds and marketable securities.
Resources operates both domestically and internationally.
Energy Technologies
Energy Technologies earns its revenues from constructing, operating and
maintaining heating, ventilating and air conditioning (HVAC) systems and
providing energy related services to industrial and commercial customers.
Other
Our other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation), EGDC and intercompany
eliminations, primarily relating to intercompany transactions between Power and
PSE&G. The net losses primarily relate to financing and certain administrative
and general costs at the parent corporations.
Information related to the segments of our business is detailed below:
Generation Energy Energy Consolidated
(B) Trading PSE&G Resources Global Technologies Other Total
------------ ---------- --------- ------------ ---------- --------------- -------- ------------
(Millions of Dollars)
- -------------------------------------
For the Year Ended December 31, 2001:
Electric Revenues................. $2,311 $-- $3,798 $-- $172 $-- $(2,125) $4,156
Gas Distribution Revenues......... -- -- 2,293 -- -- -- -- 2,293
Trading Revenues.................. -- 2,403 -- -- -- -- -- 2,403
Other Revenues.................... -- -- -- 215 280 467 1 963
Total Operating Revenues.......... 2,311 2,403 6,091 215 452 467 (2,124) 9,815
Depreciation and Amortization..... 95 -- 384 4 15 8 16 522
Interest Income................... 1 -- 21 1 1 4 5 33
Net Interest Charges.............. 143 -- 356 100 84 5 17 705
Operating Income Before Income
Taxes............................. 504 140 324 100 169 (26) (75) 1,136
Income Taxes...................... 193 57 89 30 40 (9) (27) 373
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- -- 55 143 -- -- 198
Segment Earnings (Loss)........... 311 83 230 64 116 (18) (16) 770
Gross Additions to Long-Lived
Assets............................ 1,456 6 398 1 167 1 24 2,053
As of December 31, 2001:
Total Assets...................... $4,830 $790 $12,936 $3,026 $4,074 $290 $(549) 25,397
Investments in equity method
subsidiaries...................... -- -- -- 163 1,541 3 19 1,726
115
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
For the Year Ended December 31, 2000:
- -------------------------------------
Electric Revenues................. $2,203 $-- $2,505 $-- $-- $-- $(871) $3,837
Gas Distribution Revenues......... -- -- 2,140 -- -- -- -- 2,140
Trading Revenues.................. -- 2,724 -- -- -- -- -- 2,724
Other Revenues.................... -- -- -- 206 169 417 2 794
Total Operating Revenues.......... 2,203 2,724 4,645 206 169 417 (869) $9,495
Depreciation and Amortization..... 136 -- 213 5 1 7 -- 362
Interest Income................... 1 -- 21 2 1 4 3 32
Net Interest Charges.............. 198 -- 208 79 53 3 33 574
Operating Income Before Income
Taxes............................. 449 72 638 111 69 (14) (71) 1,254
Income Taxes...................... 179 29 260 40 12 (4) (26) 490
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- -- 13 157 2 -- 172
Segment Earnings (Loss)........... 270 43 369 65 40 (10) (13) 764
Gross Additions to Long-Lived
Assets............................ 479 -- 401 -- 56 7 16 959
As of December 31, 2000:
Total Assets...................... $3,439 $1,091 $15,267 $2,565 $2,271 $312 $(3,419) $21,526
Investments in equity method
subsidiaries...................... -- -- -- 239 1,900 -- 24 2,163
For the Year Ended December 31, 1999:
- -------------------------------------
Electric Revenues................. $2,652 $-- $1,429 $-- $-- $-- $-- $4,081
Gas Distribution Revenues......... -- -- 1,717 -- -- -- -- 1,717
Trading Revenues.................. -- 1,842 -- -- -- -- -- 1,842
Other Revenues.................... -- -- -- 179 211 297 -- 687
Total Operating Revenues.......... 2,652 1,842 3,146 179 211 297 -- 8,327
Depreciation and Amortization..... 224 -- 305 1 1 5 -- 536
Interest Income................... -- -- 12 1 -- 2 -- 15
Net Interest Charges.............. 112 -- 275 46 48 -- 9 490
Operating Income Before Income
Taxes............................. 768 39 356 123 69 (9) (60) 1,286
Income Taxes...................... 275 16 219 50 24 (2) (19) 563
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- -- 78 129 -- -- 207
Segment Income before
Extraordinary Item................ 490 23 131 66 28 (6) (9) 723
Extraordinary Item (A)............ (3,204) -- 2,400 -- -- -- -- (804)
Segment Earnings (Loss)........... (2,714) 23 2,531 66 28 (6) (9) (81)
Gross Additions to Long-Lived
Assets............................ 92 -- 387 -- 1 8 94 582
(A) See Note 3. Regulatory Issues and Accounting Impacts of Deregulation for
discussion of the extraordinary charge recorded by the generation segment
in 1999 and the related regulatory asset for securitization recorded by
the T&D segment.
(B) Includes approximately $2.1 billion and $870 million charges in 2001 and
2000, respectively, to PSE&G related to the BGS Contract which commenced
in August 2000, following the generation-related asset transfer to Power.
116
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Geographic information for us is disclosed below. The foreign assets and
operations noted below were made solely through Energy Holdings.
Revenues (1) Identifiable Assets (2)
----------------------------------------------- -------------------------------
December 31, December 31,
----------------------------------------------- -------------------------------
2001 2000 1999 2001 2000
----------------------------------------------- -------------------------------
(Millions of Dollars) (Millions of Dollars)
United States................. $9,391 $9,307 $8,178 $20,633 $18,536
Foreign - Resources........... 132 109 89 1,348 1,194
Foreign - Global.............. 292 79 60 3,416 1,796
------------- ------------- ------------- -------------- ------------
Total.................... $9,815 $9,495 $8,327 $25,397 $21,526
============= ============= ============= ============== ============
Identifiable assets in foreign countries include:
Argentina $737 $470
Brazil $282 $295
Chile $880 $270
Peru $520 $250
Netherlands $911 $815
Other $1,434 $880
- --------------------------------------------------------------------------------
(1) Revenues are attributed to countries based on the locations of the
investments. Global's revenue includes its share of the net income from
joint ventures recorded under the equity method of accounting.
(2) Total assets are net of foreign currency translation adjustment of $(283)
million (pre-tax) as of December 31, 2001 and $(225) million (pre-tax) as
of December 31, 2000.
The table below reflects our investment exposure in Latin American
countries:
INVESTMENT EXPOSURE (C)
--------------------------------
DECEMBER 31,
--------------------------------
2001 2000
--------------- --------------
(MILLIONS OF DOLLARS)
Argentina..................................... $ 632 $ 622
Brazil........................................ 467 462
Chile......................................... 542 180
Peru.......................................... 387 224
Venezuela..................................... 53 51
(C) The investment exposure consists of invested equity plus equity
commitment guarantees. The investments in these Latin American
countries are Global's.
117
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 15. Property, Plant and Equipment and Jointly Owned Facilities
Information related to Property, Plant and Equipment of PSEG and its
subsidiaries is detailed below:
December 31,
----------------------------------
2001 2000
---------------- ----------------
Property, Plant and Equipment: (Millions of Dollars)
Generation:
Fossil Production (A).................. $2,233 $1,829
Nuclear Production..................... 154 130
Nuclear Fuel in Service................ 486 417
Construction Work in Progress (A)...... 2,004 483
Other.................................. 7 1
---------------- ----------------
Total Generation.................. 4,884 2,860
---------------- ----------------
Transmission and Distribution:
Electric Transmission (A).............. 1,685 1,183
Electric Distribution.................. 4,254 4,056
Gas Transmission....................... 74 69
Gas Distribution....................... 3,121 2,978
Construction Work in Progress (A)...... 54 43
Plant Held for Future Use.............. 20 20
Other.................................. 292 130
---------------- ----------------
Total Transmission and Distribution 9,500 8,479
---------------- ----------------
Other.................................... 502 608
---------------- ----------------
Total........................... $14,886 $11,947
================ ================
(A) These items include the following amounts which relate to our Global
segment:
December 31,
----------------------------------
2001 2000
---------------- ----------------
Generation: (Millions of Dollars)
Fossil Production...................... $335 $10
Construction Work in Progress.......... 317 172
---------------- ----------------
Total Generation.................. $652 $182
---------------- ----------------
Transmission and Distribution:
Electric Transmission.................. 484 -
Construction Work in Progress.......... 28 -
---------------- ----------------
Total Transmission and Distribution 512 -
---------------- ----------------
Total............................ $1,164 $182
================ ================
PSE&G and Power have ownership interests in and are responsible for
providing their share of the necessary financing for the following jointly owned
facilities. All amounts reflect the share of PSE&G's and Power's jointly owned
projects and the corresponding direct expenses are included in Consolidated
Statements of Income as operating expenses.
118
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Plant--December 31, 2001
--------------------------------------------------------------------
Ownership Accumulated
Interest Plant Depreciation
-------------------- -------------------- -----------------
(Millions of Dollars)
Coal Generating
Conemaugh.............................. 22.50% 199 70
Keystone............................... 22.84% 128 51
Nuclear Generating
Peach Bottom........................... 50.00% 249 156
Salem.................................. 57.41% 671 582
Nuclear Support Facilities............. Various 5 1
Pumped Storage Facilities
Yards Creek............................ 50.00% 28 12
Transmission Facilities..................... Various 80 30
Merrill Creek Reservoir..................... 13.91% 2 --
Linden SNG Plant............................ 90.00% 5 4
Plant--December 31, 2000
--------------------------------------------------------------------
Ownership Accumulated
Interest Plant Depreciation
-------------------- -------------------- -----------------
(Millions of Dollars)
Coal Generating
Conemaugh.............................. 22.50% 198 63
Keystone............................... 22.84% 122 47
Nuclear Generating
Peach Bottom........................... 50.00% 88 10
Hope Creek............................. 95.00% 606 508
Salem.................................. 50.00% 645 544
Nuclear Support Facilities............. Various 5 1
Pumped Storage Facilities
Yards Creek............................ 50.00% 28 11
Transmission Facilities..................... Various 97 33
Merrill Creek Reservoir..................... 13.91% 2 --
Linden SNG Plant............................ 90.00% 16 15
119
--------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 16. Selected Quarterly Data (Unaudited)
The information shown below, in our opinion, includes all adjustments,
consisting only of normal recurring accruals, necessary to a fair presentation
of such amounts. Due to the seasonal nature of the utility business, quarterly
amounts vary significantly during the year.
Calendar Quarter Ended
-----------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
--------------------- --------------------- ----------------------- ---------------------
2001 2000 2001 2000 2001 2000 2001 2000
---------- ---------- ---------- ---------- ---------- ------------ ---------- ----------
(Millions where Applicable)
Operating Revenues......... $2,814 $2,483 $2,171 $2,159 $2,401 $2,207 $2,429 $2,646
Operating Income........... 577 603 402 393 431 392 482 501
Income before Extraordinary Item 254 270 143 142 172 142 194 210
Extraordinary Item......... (2) -- -- -- -- -- -- --
Cumulative Effective Adjustment 9 -- -- -- -- -- -- --
Net Income................. 261 270 143 142 172 142 194 210
Earnings per Share
(Basic and Diluted)...... 1.25 1.25 0.68 0.66 0.82 0.66 0.95 0.98
Weighted Average Common
Shares and Potential
Dilutive Effect of Stock
Options Outstanding..... 208 216 209 215 208 215 208 215
Note 17. Related Party Transactions
We enter into a number of contracts with various suppliers, customers and
other counterparties in the ordinary course of business. Certain contracts were
entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, our
Chairman of the Board, President and Chief Executive Officer, serves on the
Board of Directors of Foster Wheeler. Richard J. Swift, who serves on our
Board of Directors, was the President and Chief Executive Officer of Foster
Wheeler Ltd. at the time the contract was entered into. The open commitment
under the contracts is for approximately $200 million of engineering,
procurement and construction services related to the development of certain
generating facilities for Power and Global. We believe that the contracts were
entered into on commercial terms no more favorable than those available in an
arms-length transaction from other parties and the pricing is consistent with
that available from other third parties.
Note 18. Subsequent Events
On August 24, 2001, Global, an indirect subsidiary of us and a direct
subsidiary of Holdings, entered into a Stock Purchase Agreement to sell its
minority interests in certain assets located in Argentina to the AES Corporation
(AES), the majority owner. These assets are "Assets Held for Sale" in the
December 31, 2001 balance sheet. The sale has not closed, pending receipt of
certain lender consents and regulatory approvals.
On February 6, 2002, AES notified Global of its intent to terminate the
Stock Purchase Agreement. In the Notice of Termination, AES alleged that a
"Political Risk Event", within the meaning of the Stock Purchase Agreement, had
occurred, by virtue of certain decrees of the Government of Argentina, thereby
giving AES the right to terminate. We disagree that a "Political Risk Event", as
defined in the Stock Purchase Agreement, has occurred and have so notified AES.
We will vigorously pursue our rights under the Stock Purchase Agreement
including ongoing discussions with AES to successfully resolve the matter. We
cannot predict the ultimate outcome.
As of December 31, 2001, Global had total investment exposure in Argentina
of approximately $632 million. The investments include the following minority
interests, with investment exposure of approximately $420 million,
120
--------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
including $92 million of goodwill, jointly owned by Global and AES, which are
the subject of the Stock Purchase Agreement: a 30% interest in three Argentine
electric distribution companies, Empresa Distribuidora de Energia Norte S.A.
(EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES), and Empresa
Distribuidora La Plata S.A. (EDELAP); a 19% share in the 650 MW Central Termica
San Nicolas power plant (CTSN); and a 33% interest in the 850 MW Parana power
plant (Parana) nearing the completion of construction.
In addition to these investments, Global has $212 million of investment
exposure with respect to its 90% interest in another Argentine company,
Inversora en Distribucion de Entre Rios S.A. (EDEERSA), inclusive of $63 million
of goodwill.
We have approximately $18 million of interest receivables due from AES, as
provided for in the Stock Purchase Agreement and is due upon resolution of the
pending sale.
121
FINANCIAL STATEMENT RESPONSIBILITY
Our management is responsible for the preparation, integrity and
objectivity of our consolidated financial statements and related notes. The
consolidated financial statements and related notes are prepared in accordance
with generally accepted accounting principles. The financial statements reflect
estimates based upon the judgment of management where appropriate. Management
believes that the consolidated financial statements and related notes present
fairly our financial position and results of operations. Information in other
parts of this Annual Report is also the responsibility of management and is
consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to
audit our consolidated financial statements and related notes and issue a report
thereon. Deloitte & Touche's audit is conducted in accordance with generally
accepted auditing standards. Management has made available to Deloitte & Touche
all the corporation's financial records and related data, as well as the minutes
of directors' meetings. Furthermore, management believes that all
representations made to Deloitte & Touche during its audit were valid and
appropriate.
Management has established and maintains a system of internal accounting
controls to provide reasonable assurance that assets are safeguarded, and that
transactions are executed in accordance with management's authorization and
recorded properly for the prevention and detection of fraudulent financial
reporting, so as to maintain the integrity and reliability of the financial
statements. The system is designed to permit preparation of consolidated
financial statements and related notes in accordance with generally accepted
accounting principles. The concept of reasonable assurance recognizes that the
costs of a system of internal accounting controls should not exceed the related
benefits. Management believes the effectiveness of this system is enhanced by an
ongoing program of continuous and selective training of employees. In addition,
management has communicated to all employees its policies on business conduct,
safeguarding assets and internal controls.
The Internal Auditing Department of Services conducts audits and appraisals
of accounting and other operations of PSEG and its subsidiaries and evaluates
the effectiveness of cost and other controls and, where appropriate, recommends
to management improvements thereto. Management considers the internal auditors'
and Deloitte & Touche's recommendations concerning the corporation's system of
internal accounting controls and has taken actions that, in its opinion, are
cost-effective in the circumstances to respond appropriately to these
recommendations. Management believes that, as of December 31, 2001, the
corporation's system of internal accounting controls was adequate to accomplish
the objectives discussed herein.
Our Board of Directors carries out its responsibility of financial overview
through its Audit Committee, which presently consists of six directors who are
not our employees or any of our affiliates. The Audit Committee meets
periodically with management as well as with representatives of the internal
auditors and Deloitte & Touche. The Audit Committee reviews the work of each to
ensure that its respective responsibilities are being carried out and discusses
related matters. Both the internal auditors and Deloitte & Touche periodically
meet alone with the Audit Committee and have free access to the Audit Committee
and its individual members at all times.
E. JAMES FERLAND THOMAS M. O'FLYNN
Chairman of the Board, Executive Vice President and
President and Chief Executive Officer Chief Financial Officer
PATRICIA A. RADO
Vice President and Controller
(Principal Accounting Officer)
February 15, 2002
122
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of
Public Service Enterprise Group Incorporated:
We have audited the consolidated balance sheets of Public Service
Enterprise Group Incorporated and its subsidiaries (the "Company") as of
December 31, 2001 and 2000, and the related consolidated statements of income,
common stockholders' equity and cash flows for each of the three years in the
period ended December 31, 2001. Our audits also included the consolidated
financial statement schedule listed in the Index in Item 14(B)(a). These
consolidated financial statements and the consolidated financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these consolidated financial statements and the
consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31,
2001 and 2000, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such consolidated financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects, the information set forth therein.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheets of the
Company as of December 31, 1999, 1998, and 1997, and the related consolidated
statements of income, common stockholders' equity and cash flows for the years
ended December 31, 1998 and 1997 (none of which are presented herein), and we
expressed unqualified opinions on those consolidated financial statements.
In our opinion, the information set forth in the Selected Financial Data
for each of the five years in the period ended December 31, 2001, presented in
Item 6, is fairly stated in all material respects, in relation to the
consolidated financial statements from which it has been derived.
As discussed in Note 1 to the consolidated financial statements, on January
1, 2001, the Company adopted Statement of Financial Accounting Standards No.
133, "Accounting for Derivative Instruments and Hedging Activities", as amended.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 15, 2002
123
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
--------
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The information required by Item 10 of Form 10-K with respect to (i)
present directors who are nominees for election as directors at PSEG's Annual
Meeting of Stockholders to be held on April 16, 2002, and directors whose terms
will continue beyond the meeting, and (ii) compliance with Section 16(a) of the
Securities Exchange Act of 1934, as amended, is set forth under the heading
"Election of Directors" and "Section 16 Beneficial Ownership Reporting
Compliance" in our definitive Proxy Statement for such Annual Meeting of
Stockholders, which definitive Proxy Statement is expected to be filed with the
Securities and Exchange Commission on or about March 1, 2002 and which
information set forth under said heading is incorporated herein by this
reference thereto.
=============================================================================================================================
AGE EFFECTIVE DATE FIRST ELECTED
NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION
- -----------------------------------------------------------------------------------------------------------------------------
E. James Ferland 59 Chairman of the Board, President and July 1986 to present
Chief Executive Officer (PSEG)
Chairman of the Board and Chief July 1986 to present
Executive Officer (PSE&G)
Chairman of the Board and Chief June 1989 to present
Executive Officer (Energy Holdings)
Chairman of the Board and Chief June 1999 to present
Executive Officer (Power)
Chairman of the Board, President and November 1999 to present
Chief Executive Officer (Services)
- -----------------------------------------------------------------------------------------------------------------------------
Thomas M.O'Flynn 41 Executive Vice President and Chief July 2001 to present
Financial Officer (PSEG)
Executive Vice President- Finance
(Services)
- -----------------------------------------------------------------------------------------------------------------------------
Robert J. Dougherty, 50 President and Chief Operating Officer January 1997 to present
Jr. (Energy Holdings)
President (Enterprise Ventures and February 1995 to December 1996
Services Corporation)
- -----------------------------------------------------------------------------------------------------------------------------
Alfred C. Koeppe 55 President and Chief Operating February 2000 to present
Officer (PSE&G)
Senior Vice President--Corporate October 1996 to February 2000
Services and External Affairs (PSE&G)
Senior Vice President--External October 1995 to October 1996
Affairs (PSE&G)
=============================================================================================================================
124
Executive Officers of the Registrant
The following table sets forth certain information concerning our executive
officers.
=============================================================================================================================
AGE EFFECTIVE DATE FIRST ELECTED
NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION
- -----------------------------------------------------------------------------------------------------------------------------
R. Edwin Selover 56 Vice President and General Counsel April 1988 to present
(PSEG)
Senior Vice President and General January 1988 to present
Counsel (PSE&G)
Senior Vice President and General November 1999 to present
Counsel (Services)
- -----------------------------------------------------------------------------------------------------------------------------
Robert E. Busch 55 Senior Vice President and March 1998 to present
Chief Financial Officer (PSE&G)
President & COO November 1999 to present
(Services)
- -----------------------------------------------------------------------------------------------------------------------------
Frank Cassidy 55 President and July 1999 to present
Chief Operating Officer (Power)
President (Energy Technologies) November 1996 to June 1999
Senior Vice President--Fossil February 1995 to November 1996
Generation (PSE&G)
- -----------------------------------------------------------------------------------------------------------------------------
Patricia A. Rado 59 Vice President and Controller April 1993 to present
(PSEG)
Vice President and Controller April 1993 to present
(PSE&G)
Vice President and Controller June 1999 to present
(Power)
Vice President and Controller November 1999 to present
(Services)
=============================================================================================================================
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K is set forth under the
heading "Executive Compensation" in our definitive Proxy Statement for the
Annual Meeting of Stockholders to be held April 16, 2002 which definitive Proxy
Statement is expected to be filed with the Securities and Exchange Commission on
or about March 1, 2002 and such information set forth under such heading is
incorporated herein by this reference thereto.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K with respect to directors,
executive officers and certain beneficial owners is set forth under the heading
`Security Ownership of Directors, Management and Certain Beneficial Owners' in
our definitive Proxy Statement for the Annual Meeting of Stockholders to be held
April 16, 2002 which definitive Proxy Statement is expected to be filed with the
Securities and Exchange Commission on or about March 1, 2002, and such
information set forth under such heading is incorporated herein by this
reference thereto.
125
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K is set forth under the
heading "Executive Compensation" in our definitive Proxy Statement for the
Annual Meeting of Stockholders to be held April 16, 2002, which definitive Proxy
Statement is expected to be filed with the Securities and Exchange Commission on
or about March 1, 2002. Such information set forth under such heading is
incorporated herein by this reference thereto.
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) Financial Statements:
a. PSEG Consolidated Statements of Income for the years ended December 31,
2001, 2000 and 1999 on page 66.
PSEG Consolidated Balance Sheets for the years ended December 31, 2001
and 2000 on pages 67 and 68.
PSEG Consolidated Statements of Cash Flows for the years ended December
31, 2001, 2000 and 1999 on page 69.
PSEG Statements of Common Stockholders' Equity for the years ended
December 31, 2001, 2000 and 1999 on page 66.
PSEG Notes to Consolidated Financial Statements on pages 71 to 121.
(B) The following documents are filed as a part of this report:
a. PSEG Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the three
years in the period ended December 31, 2001 (page 127)
Schedules other than those listed above are omitted for the reason that
they are not required or are not applicable, or the required information is
shown in the consolidated financial statements or notes thereto.
The following exhibits are filed herewith:
Exhibit 10a(10): Amended Employment Agreement with E. James Ferland
dated November 20, 2001
Exhibit 10a(12): Amended Employment Agreement with Thomas M. O'Flynn
dated December 21, 2001
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
Exhibit 21: Subsidiaries of Registrant
Exhibit 23: Independent Auditors' Consent
(See Exhibit Index on pages 130 to 135)
(C) The following reports on Form 8-K were filed during the last quarter of
2001 and the 2002 period covered by this report under Item 5:
Date of Report Items Reported
-------------- --------------
February 7, 2002 Item 5
January 25, 2002 Items 5 and 7
October 24, 2001 Items 5 and 7
126
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II -- Valuation and Qualifying Accounts
Years Ended December 31, 2001 -- December 31, 1999
Column A Column B Column C Column D Column E
-------- ------------- ----------------------------- ------------- -------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
beginning cost and other accounts Deductions- end of
Description of period expenses Describe describe Period
- ------------------------------------------- ------------- ----------------------------- ------------- -------------
(Millions of Dollars)
2001:
- -----
Allowance for Doubtful Accounts.......... $44 $45 $-- $46(A) $43
Materials and Supplies Valuation Reserve. 11 -- -- 9(D) 2
Other Valuation Allowances............... 22 -- -- -- 22
2000:
- -----
Allowance for Doubtful Accounts.......... $40 $45 $-- $41(A) $44
Materials and Supplies Valuation Reserve. 11 -- -- -- 11
Other Valuation Allowances............... 22 -- -- -- 22
1999:
- -----
Allowance for Doubtful Accounts.......... $38 $40 $-- $38(A) $40
Discount on Property Abandonments........ 1 -- -- 1(B) --
Materials and Supplies Valuation Reserve. 12 41 -- 42(C) 11
Other Valuation Allowances............... 11 11 -- -- 22
(A) Accounts Receivable/Investments written off.
(B) Amortization of discount to income.
(C) Inventory written off.
(D) Reduced reserve to appropriate level and to remove obsolete inventory.
127
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Public Service Enterprise Group Incorporated
By E. JAMES FERLAND
------------------------------------------
E. James Ferland
Chairman of the Board, President
and Chief Executive Officer
Date: March 1, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
E. JAMES FERLAND Chairman of the Board, March 1, 2002
- -------------------------------------------- President and Chief Executive Officer
E. James Ferland and Director (Principal Executive Officer)
THOMAS M. O'FLYNN Executive Vice President and Chief March 1, 2002
- -------------------------------------------- Financial Officer
Thomas M. O'Flynn (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller March 1, 2002
- -------------------------------------------- (Principal Accounting Officer)
Patricia A. Rado
ERNEST H. DREW Director March 1, 2002
- --------------------------------------------
Ernest H. Drew
T. J. DERMOT DUNPHY Director March 1, 2002
- --------------------------------------------
T. J. Dermot Dunphy
ALBERT R. GAMPER, JR. Director March 1, 2002
- --------------------------------------------
Albert R. Gamper, Jr.
RAYMOND V. GILMARTIN Director March 1, 2002
- --------------------------------------------
Raymond V. Gilmartin
CONRAD K. HARPER Director March 1, 2002
- --------------------------------------------
Conrad K. Harper
WILLIAM V. HICKEY Director March 1, 2002
- --------------------------------------------
William V. Hickey
SHIRLEY ANN JACKSON Director March 1, 2002
- --------------------------------------------
Shirley Ann Jackson
MARILYN M. PFALTZ Director March 1, 2002
- --------------------------------------------
Marilyn M. Pfaltz
RICHARD J. SWIFT Director March 1, 2002
- --------------------------------------------
Richard J. Swift
128
EXHIBIT INDEX
Certain Exhibits previously filed with the Commission and the appropriate
securities exchanges are indicated as set forth below. Such Exhibits are not
being refiled, but are included because inclusion is desirable for convenient
reference.
(a) Filed by PSE&G with Form 10-K under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-00973.
(b) Filed by PSE&G with Form 10-Q under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-00973.
(c) Filed by PSEG with Form 10-K under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-09120.
(d) Filed with registration statement of PSE&G under the Securities Exchange
Act of 1934, File No. 1-973, effective July 1, 1935, relating to the
registration of various issues of securities.
(e) Filed with registration statement of Public Service Enterprise Group
Incorporated under the Securities Act of 1933, No. 33-2935 filed January
28, 1986, relating to PSE&G's plan to form a holding company as part of a
corporate restructuring.
(f) Filed with PSEG Form 10-K under the Securities Exchange Act of 1934, on the
respective dates indicated, File No. 001-09120.
129
PSEG
- ---------------------------------------------------
Exhibit Number
- ---------------------------------------------------
This Previous Filing
------------------------------------
Filing Commission Exchanges
------ ---------- ---------
3a (e) 3a (e) 3a Certificate of Incorporation Public Service Enterprise
Group Incorporated
3b (c) 3b (c) 3b By-Laws of Public Service Enterprise
4/11/88 Group Incorporated
3c (c) 3c (c) 3c Certificate of Amendment of Certificate of
4/11/88 Incorporation of Public Service Enterprise Group
Incorporated,
effective April 23, 1987
3d (d) (d) Trust Agreements for Enterprise Capital Trust I and
III
12/24/97
3e (b) 3 (b) 3 Amended and Restated Trust Agreement for Enterprise
8/14/98 8/14/98 Capital Trust II
4a(1) (b) 4f (b) 4f Indenture between Public Service Enterprise Group
5/13/98 5/13/98 Incorporated and First Union National Bank, as
Trustee, dated January 1, 1998 providing for
Deferrable Interest Subordinated Debentures in
Series (relating to Quarterly Preferred Securities)
4a(2) (b) 4a (b) 4a First Supplemental Indenture to Indenture dated as
8/14/98 8/14/98 of January 1, 1998 between Public Service Enterprise
Group Incorporated and First Union National Bank, as
Trustee, dated June 1, 1998 providing for the issuance of
Floating Rate Deferrable Interest Subordinated Debentures,
Series B (relating to Trust Preferred Securities)
4a(3) (b) 4b (b) 4b Second Supplemental Indenture to Indenture dated as
8/14/98 8/14/98 of January 1, 1998 between Public Service Enterprise
Group Incorporated and First Union National Bank, as
Trustee, dated July 1, 1998 providing for the issuance of
Deferrable Interest Subordinated Debentures, Series C
(relating to Trust Preferred Securities)
4b (a) 4f (a) 4f Indenture dated as of November 1, 1998 between Public
11/1/00 11/1/00 Service Enterprise Group Incorporated and First Union
National Bank providing for the issuance of Senior Debt
Securities
9 Inapplicable
10a(1) (c) 10a(1) (c) 10a(1) Directors' Deferred Compensation Plan
2/25/00 2/25/00
10a(2) (c) 10a(2) (c) 10a(2) Deferred Compensation Plan for Certain Employees
2/25/00 2/25/00
10a(3) (c) 10a(3) (c) 10a(3) Limited Supplemental Benefits Plan for Certain Employees
2/25/00 2/25/00
10a(4) (c) 10a(4) (c) 10a(4) Mid Career Hire Supplemental Retirement Plan
2/25/00 2/25/00
10a(5) (c) 10a(5) (c) 10a(5) Retirement Income Reinstatement Plan
2/25/00 2/25/00
10a(6) (c) 10a(6) (c) 10a(6) 1989 Long-Term Incentive Plan
2/22/99 2/22/99
10a(7) (c) 10a(7) (c) 10a(7) 2001 Long-Term Incentive Plan
3/06/01 3/06/01
10a(8) (c) 10a(8) (c) 10a(8) Restated and Amended Management Incentive Compensation Plan
3/06/01 3/06/01
130
PSEG
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
Filing Commission Exchanges
------ ---------- ---------
10a(9) (b) 10 (b) 10 Employment Agreement with E. James Ferland dated
8/14/98 8/14/98 June 16, 1998
10a(10) Amended Employment Agreement with E. James Ferland dated
November 20, 2001
10a(11) (b) 10a(22) (b) 10a(22) Employment Agreement with Thomas M. O'Flynn dated
11/13/00 11/13/00 April 18, 2001
10a(12) Amended Employment Agreement with Thomas M. O'Flynn
dated December 21, 2001
10a(13) (a) 10a(14) (a) 10a(14) Letter Agreement with Patricia A. Rado dated
2/26/94 3/9/94 March 24, 1993
10a(14) (b) 10a(21) (b) 10a(21) Employment Agreement with Alfred C. Koeppe dated
11/13/00 11/13/00 October 17, 2000
10a(15) (b) 10a(19) (b) 10a(19) Employment Agreement with Frank Cassidy dated
11/13/00 11/13/00 October 17, 2000
10a(16) (b) 10a(20) (b) 10a(20) Employment Agreement with Robert J. Dougherty, Jr. dated
11/13/00 11/13/00 October 17, 2000
10a(17) (c) 10a(14) (c) 10a(14) Directors' Stock Plan
2/22/99 2/22/99
10a(18) (a) 10a(16) (a) 10a(16) Letter Agreement with Harold W. Keiser dated January 5,
2/23/98 2/23/98 1998
10a(19) (c) 10a(16) (c) 10a(16) Global Deferred Compensation Plan
2/22/99 2/22/99
10a(20) (c) 10a(17) (c) 10a(17) Global 2001 Executive Long-Term Incentive Compensation
Plan
2/22/99 2/22/99
10a(21) (c) 10a(20) (c) 10a(20) Energy Technologies Executive Incentive Compensation Plan
2/22/99 2/22/99
10a(22) (c) 10a(22) (c) 10a(22) Resources Annual Incentive Compensation Plan
2/22/99 2/22/99
10a(23) (f) 10a(23) (f) 10a(23) Employment Agreement with Robert E. Busch dated April
24, 2001
8/09/01 8/09/01
11 Inapplicable
12 Computation of Ratios of Earnings to Fixed Charges
13 Inapplicable
16 Inapplicable
18 Inapplicable
21 Subsidiaries of the Registrant
22 Inapplicable
23 Independent Auditors' Consent
24 Inapplicable
28 Inapplicable
99 Inapplicable
127