PUBLIC SERVICE ENTERPRISE GROUP INC - 10-K - 20030226 - PART_I
PART I
This
combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated
(PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC
(Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained
herein relating to any individual company is filed by such company on its own
behalf. PSE&G, Power and Energy Holdings each make representations only
as to itself and its subsidiaries and makes no other representations whatsoever as to any other company.
ITEM 1. BUSINESS
GENERAL
PSEG, PSE&G, Power and Energy Holdings
PSEG, incorporated
under the laws of the State of New Jersey on July 25, 1985, 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).
PSEG has four principal
direct wholly-owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG
Services Corporation (Services). The following organization chart shows PSEG
and its principal subsidiaries, as well as the principal operating subsidiaries
of Power: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy
Resources & Trade LLC (ER&T); and of Energy Holdings: PSEG Global Inc.
(Global) and PSEG Resources LLC (Resources):
The
regulatory structure which has historically governed the electric and gas utility
industries in the United States has changed dramatically in recent years and
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 (US). States have acted independently to deregulate the electric
and gas utility industries. Experience in deregulating California, with energy
shortages, high costs and financial difficulties of utilities and high profile
bankruptcies 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, building, buying or selling generation
capacity and the anticipated resulting industry consolidation have had, and
are likely to continue to have, a profound effect on PSEG and its subsidiaries,
providing it with new opportunities and exposing it to new risks. For further
information, see Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operation (MD&A) — Overview of 2002 and Future
Outlook.
1
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 Federal Energy Regulatory Commission’s (FERC) 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
initiated regulatory actions that resulted in expanded access to transmission
lines, providing eligible third-party wholesale marketers clear transmission
access. These actions have afforded power marketers, merchant generators, Exempt
Wholesale Generators (EWGs) and utilities the opportunity to compete actively
in wholesale energy markets, and afforded consumers the right to choose their
energy suppliers.
Worldwide energy
industry deregulation, restructuring, privatization and consolidation are creating
opportunities and risks for PSEG, PSE&G, Power and Energy Holdings. Over
recent years, PSEG has realigned its organizational structure to address the
competitive environment brought about by the deregulation of the electric generation
industry and has transitioned from primarily being a regulated New Jersey utility
to operating as a competitive energy company with operations primarily in the
Northeastern US and in other select domestic and international markets. 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. As of December 31, 2002, Power, PSE&G, and
Energy Holdings comprised approximately 27%, 48% and 27% of PSEG’s consolidated
assets and contributed approximately 60%, 26% and 18% of PSEG’s results, excluding certain charges.
For additional information, see Item 7. MD&A — Overview of 2002 and
Future Outlook.
PSE&G and Power
Following the enactment
of the New Jersey Electric Discount and Energy Competition Act, as amended (Energy
Competition Act), the New Jersey Board of Public Utilities (BPU) rendered its
Final Decision and Order (Final Order) in 1999 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 $2.4 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 in August 2000 for $2.8 billion.
Subsequently, Power
entered into a BPU approved fixed price requirements contract (Basic Generation
Service (BGS) contract) to supply all of PSE&G’s load requirement for
its electric customers not choosing an alternative supplier, which terminated
on July 31, 2002, under which Power sold energy directly to PSE&G which
in turn sold this energy to its customers. Subsequent to July 31, 2002, Power
primarily sells its energy and capacity to third parties that supply New Jersey’s
electric distribution companies (EDCs) participating in the BPU approved BGS
auctions in New Jersey. PSE&G purchases the energy required to meet its
customers’ needs from third party suppliers through such auction process.
BGS Supply
PSE&G is required
to determine BGS suppliers by competitive bid in accordance with BPU requirements.
In February 2002, an internet auction was held to determine who would supply
BGS to PSE&G and the other three BPU regulated New Jersey electric utility
companies for the period August 1, 2002 to July 31, 2003. As conditions of qualification
to participate in this auction, energy suppliers agreed to execute the BGS Master
Service Agreement and provide required security bonds within two days of BPU
Certification of auction results, in addition to satisfying BPU credit worthiness
requirements.
In February 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 through 96 notional
tranches of 100 MW each. Under these contracts, the suppliers have the full
load serving responsibility and bear the risks of volatility in energy prices
due to various factors such as changes in weather, seasonality and transmission
constraints. Subsequently, certain BGS suppliers experienced adverse credit
issues and therefore, these suppliers assigned contracts to other parties. Under
the BPU approved supply contracts, PSE&G is paying $.0511 per kWh to obtain
electricity for BGS 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 PSE&G’s current rate structure,
the difference is being
2
deferred and is expected to be recovered with interest
through a future securitization. PSE&G estimates that the underrecovery
relating to the BGS for the one-year period ending July 31, 2003 will amount
to approximately $241 million.
As a result of the
initial New Jersey BGS auction, Power contracted to provide energy to the direct
suppliers of New Jersey electric utilities, including PSE&G, commencing
August 1, 2002. Subsequently, a portion of the contracts with those bidders
was reassigned to Power. Therefore, for a limited portion of the New Jersey
retail load, Power will be a direct supplier to one utility, although this utility
is not PSE&G.
New Jersey’s EDCs,
including PSE&G, will provide two types of BGS service beginning in August
2003. The BPU authorized two concurrent auctions of New Jersey’s Basic
Generation Service which were held in February 2003. The first was a general
auction to procure approximately 15,500 MW of supply for ten-month and 34-month
periods for smaller commercial and residential customers at seasonally-adjusted
fixed prices. The other auction was held to procure approximately 2,600 MW of
supply for larger customers for a 10-month period at hourly market prices. In
total, the EDCs sought and obtained over 18,000 MW of combined full-requirements
electric service. In February 2003, the BPU approved the auction results and
PSE&G secured contracts from a number of suppliers to meet its requirements.
Under the contracts, PSE&G is paying $.05386 and $.05560 per kWh for the
ten-month tranche and 34-month tranche, respectively, to obtain electricity
for customers for the periods beginning August 1, 2003.
Power was a participant
in the BGS auction held in February 2003. Power entered into hourly energy price
contracts to be a direct supplier of certain large customers for a ten-month
period beginning August 1, 2003. Power also entered into contracts with third
parties who are direct suppliers of New Jersey’s EDCs. Through these seasonally-adjusted
fixed price contracts, Power will indirectly serve New Jersey’s smaller
commercial and residential customers for ten-month and 34-month periods beginning
August 1, 2003. Power believes that its obligations under these contracts are
reasonably balanced by its available supply.
BGSS
On April 17, 2002,
the BPU issued the Final Order approving the transfer of PSE&G’s gas
supply business. Pursuant to such order, in May 2002, PSE&G transferred
its gas supply contracts and gas inventory to Power for approximately $183 million
and similarly, entered into a requirements contract with Power under which Power
sells gas supply services directly to PSE&G needed to meet PSE&G’s
Basic Gas Supply Service (BGSS) requirements. The contract term ends March 31,
2004, after which PSE&G has a three-year renewal option. As part of the
agreement, PSE&G is providing Power the use of its peak shaving facilities
at cost.
On May 1, 2002, the
New Jersey Ratepayer Advocate filed a motion for the reconsideration of the
BPU’s approval of the gas contract transfer. On October 31, 2002, the BPU
issued an order denying the motion for reconsideration, except for the issue
of valuation. The BPU retains the right to review the valuation of the contracts
transferred if FERC modifies the capacity release rules prior to the contract
expirations.
PSE&G
PSE&G is a New
Jersey corporation, incorporated on July 25, 1924, 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. PSE&G continues to own and operate its electric and gas transmission
and distribution business. PSE&G Transition Funding LLC (Transition Funding),
a bankruptcy remote subsidiary of PSE&G, was formed solely to issue $2.525
billion principal amount of transition bonds in connection with the securitization
of $2.4 billion of PSE&G’s approved stranded costs approved for recovery
by the BPU under the Energy Competition Act.
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 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
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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. Pursuant to BPU requirements, PSE&G serves as
the supplier of last resort for electric and gas customers within its service
territory who do not choose an alternate supplier. PSE&G earns no margin
on the commodity portion of its electric and gas sales. PSE&G earns margins
through the transmission and distribution of electricity and gas. PSE&G’s
revenues are based upon tariffs approved by the BPU and the FERC for these services.
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. Rates for gas sold in interstate commerce are not subject
to cost of service ratemaking but are subject to competitive pricing. See Regulatory
Issues and Item 7. MD&A, for a further discussion of these matters.
Power
Power is a Delaware
limited liability company, formed on June 16, 1999, with its principal executive offices at 80 Park Plaza,
Newark, New Jersey 07102. Power is a multi-regional, independent wholesale energy
supply company that integrates its generating asset operations with its wholesale
energy, fuel supply, energy trading and marketing and risk management function
with three principal direct wholly-owned subsidiaries: Nuclear, which owns and
operates nuclear generating stations, Fossil, which develops, owns and operates
domestic fossil generating stations and ER&T, which markets the capacity
and production of Fossil’s and Nuclear’s stations and manages the
commodity price risks or market risks related to generation. Power’s subsidiary,
PSEG Power Capital Investment Company (Power Capital), provides certain financing
for Power’s subsidiaries.
Power’s target
market, which it refers to as the Super Region, extends from Maine to the Carolinas
and from the Atlantic Coast to Indiana, encompassing 36% of the nation’s power
consumption. Power is the single largest power supplier in its primary market,
the PJM Interconnection area, one of the nation’s largest and most well
developed energy markets.
Power’s generation
portfolio consists of 13,055 MW of installed capacity which is diversified by
fuel source and market segment. In addition, Power is currently constructing
projects which are expected to increase capacity by over 2,900 MW through 2005,
net of planned retirements. For additional information, see Item 2. Properties.
Power participates
primarily in the PJM market, where the pricing of energy is based upon the locational
marginal price (LMP) set through power providers’ bids. Because of transmission
constraints, 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 megawatt-hour (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.
As Exempt Wholesale Generators (EWGs) under FERC,
Power’s subsidiaries do not directly serve any retail customers. Power
uses its generation facilities primarily for the production of electricity for
sale at the wholesale level. For a discussion of BGS Supply in New Jersey, see
PSE&G and Power above.
4
Electric
Fuel Supply
The following table
indicates MWh output of Power’s generating stations by source of energy
in 2002 and the estimated MWh output by source for 2003:
Actual
Estimated
Source
2002
2003 (A)
Nuclear:
New Jersey facilities
41
%
38%
Pennsylvania
facilities
21
%
19%
Fossil:
Coal:
New
Jersey facilities
13
%
11%
Pennsylvania
facilities
13
%
12%
Connecticut
facilities
—
5%
Oil and Natural
Gas:
New
Jersey facilities
11
%
9%
New
York facilities
—
—
Connecticut
facilities
—
3%
Mid-West
facilities
—
2%
Pumped Storage
1
%
1%
Total
100
%
100%
(A)
No assurances can be
given that actual 2003 output by source will match estimates.
Fossil
Fuel Supply
Fossil
has an ownership interest in twelve fossil generating stations in New Jersey,
one fossil generating station in New York, two fossil generating stations
in Connecticut and two fossil generating stations in Pennsylvania. Fossil
is also in the process of constructing a fossil generating station in Ohio
and another in Indiana. Fossil has an 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. The majority
of Power’s fossil generating stations obtain their fuel supply from
within the US. In order to minimize emissions levels, the Connecticut generating
facilities use a specific type of coal which is obtained from Indonesia.
Fossil does not anticipate any difficulties in obtaining adequate coal,
natural gas and oil supplies for these facilities over the next several
years, however, if the supply of coal from Indonesia or equivalent coal
from other sources was not available for the Connecticut facilities, additional
capital expenditures could be required to modify the existing plants. For
additional information, see Item 2. Properties — Power.
Nuclear
Fuel Supply
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.
Power
has several long-term purchase contracts with uranium suppliers, converters,
enrichers and fabricators to meet the currently projected fuel requirements
for Salem and Hope Creek. On average, Power has various multi-year requirements-based
purchase commitments that total approximately $88 million per year to meet
Salem and Hope Creek fuel needs. Power has been advised by Exelon that it
has similar purchase contracts to satisfy the fuel requirements for Peach
Bottom. Nuclear does not anticipate any difficulties in obtaining adequate
fuel supplies for these facilities over the next several years.
5
Gas Supply
As described
above, Power sells gas to PSE&G. About 40% of the peak daily gas requirements
are provided through firm transportation which is available every day of the
year. The remainder comes from field storage, liquefied natural gas, seasonal
purchases, contract peaking supply, propane and refinery/landfill gas. Following
the gas contract transfer in May 2002, Power purchased gas for its gas operations
directly from natural gas producers and marketers. These supplies were transported
to New Jersey by four interstate pipeline suppliers.
Power has
approximately 1.1 billion cubic feet per day of firm transportation capacity
under contract to meet the primary needs of the gas consumers of PSE&G.
In addition, Power supplements that supply with a total storage capacity of
81 billion cubic feet that provides .94 billion cubic feet per day of gas during
the winter season.
Power expects to meet
the energy-related demands of its firm customers during the 2002-2003 and 2003-2004
winter seasons. However, the sufficiency of supply could be affected by several
factors not within Power’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. The
adequacy of supply of all types of gas is affected by the nationwide availability
of all sources of fuel for energy production.
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.
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 wholesale energy marketing and trading organization that is
active in the long-term and spot wholesale energy markets.
ER&T’s principal
objectives are to sell and deliver physical power from Power’s generating
assets, reduce earnings volatility through hedging activities, manage gas supply
and BGSS contracts, procure low cost fuel and natural gas supplies and produce
net earnings from trading energy-related products around Power’s physical
assets. ER&T does not engage in the practice of simultaneous trading for
the purpose of increasing trading volume or revenue (also known as round trips).
Consistent with its business objectives, ER&T measures performance based
on net earnings and overall team performance, not on volume or gross revenues.
These are also the metrics used to measure performance under its incentive compensation
programs. For further information, see Note 12. Risk Management of the Notes
to the Consolidated Financial Statements (Notes).
Energy
Holdings
Energy Holdings is
a New Jersey limited liability company formed on October 31, 2002, which merged wth PSEG Energy Holdings Inc., which was incorporated on June 20, 1989. Energy Holdings
principal executive offices are
located at 80 Park Plaza, Newark, New Jersey 07102. Energy Holdings has two
principal direct wholly-owned subsidiaries; Global and Resources. During the
second quarter of 2002, Energy Holdings announced its intention to sell the
businesses of PSEG Energy Technologies Inc. (Energy Technologies). See Note
5. Discontinued Operations of the Notes.
Global and Resources
have more than 100 financial and operating investments. Energy Holdings has
pursued investment opportunities in the rapidly changing global energy markets,
with Global focusing on the operating segments of the electric industries and
Resources primarily making financial investments in these industries.
6
Energy Holdings’
portfolio is diversified by number, type and geographic location of investments.
As of December 31, 2002, assets were comprised of the following types:
December
31, 2002
Leveraged Leases (A)
42
%
International Electric Facilities
20
%
International Generation Plants
22
%
Domestic Generation Plants
10
%
Energy Services
3
%
Other Passive Financial Investments
2
%
Other
1
%
(A) Leveraged Leases
are primarily in energy related facilities and are discussed further under Resources.
The characteristics
of each of these investment types are described in more detail below.
Global
Global is an independent
power producer and distributor which develops, acquires, owns and operates electric
generation, transmission and distribution facilities and is engaged in power
production and distribution, including wholesale and retail sales of electricity,
in selected domestic and international markets.
Global realized substantial
growth prior to 2002, but has been faced with significant challenges as the
electricity privatization model has experienced stress. These challenges include
the Argentine economic, political and social crisis, recent issues in India,
financial and political pressures in Brazil and Venezuela and the soft power
market in Texas. A worldwide recession and a series of disruptive events have
slowed privitization in many countries. See Item 7. MD&A — Overview of
2002 and Future Outlook for further details.
Generally, Global has
sought to minimize risk in the development and operation of its generation projects
by selecting partners with complementary skills, structuring long-term power
purchase contracts, arranging financing prior to the commencement of construction
and contracting for adequate fuel supply. Historically, Global’s operating
affiliates have entered into long-term power purchase contracts, thereby selling
the electricity produced for the majority of the project life. However, two
plants in Texas and two plants in China operate as merchant plants without
long-term power purchase contracts and a plant in Poland will likely do so as
well. For a further discussion of the oversupply of energy in the Texas power market, see Item 7.
MD&A — Future Outlook.
Fuel supply arrangements
are designed to balance long-term supply needs with price considerations. Global’s
project affiliates generally utilize long-term contracts and spot market purchases.
Energy Holdings believes that there are adequate fuel supplies for the anticipated
needs of its generating projects. Energy Holdings also believes that transmission
access and capacity are sufficient at this time for its generation projects.
Global, to the extent
practical, attempts to limit its financial exposure associated with each project
and to mitigate development risk, foreign currency exposure, interest rate risk
and operating risk, including exposure to fuel costs, through contracts. For
a further discussion of these risks, see Item 7A. Qualitative and Quantitative
Disclosures About Market Risk. In addition, project loan agreements are generally
structured on a non-recourse basis. Further, Global generally structures project
financing so that a default under one project’s loan agreement will have
no effect on the loan agreements of other projects or Energy Holdings’
debt.
Global has ownership
interests in 34 operating generation projects (excluding those in Argentina
which were fully impaired in 2002) totaling 5,384 MW (2,476 MW net) and eight
projects totaling 2,329 MW (1,042 MW net) in construction. Of Global’s
generation projects in operation or construction, 1,449 MW net or 41% are located
in the United States. Global is actively involved, through its joint ventures,
in managing the operations of 28 operating generation projects and will be actively
involved in managing the operations of 6 projects in construction.
Global has invested
in four distribution companies (excluding those in Argentina which were fully
impaired in 2002) which serve approximately 2.9 million customers in Brazil,
Chile and Peru. Global is actively involved in
7
managing the operations of these distribution companies
in accordance with shareholder agreements and/or operating contracts. Rate-regulated
distribution assets represented 37% of Global’s assets, or $1.4 billion,
as of December 31, 2002.
As of December 31,
2002, Global’s assets, which include consolidated projects and those accounted
for under the equity method, and share of project MW, by region are as follows:
2002
MW
(Millions)
Generation
North America
$
647
1,449
Latin America (1)
359
247
Asia Pacific
148
738
Europe (2)
772
856
India (3)
200
228
Distribution
Latin America (1)
1,391
N/A
Other
Other (4)
285
N/A
Total Assets
$
3,802
3,518
(1)
Investments in Argentina
were fully impaired in 2002.
(2)
Europe and Africa.
(3)
India and the Middle
East. The Tanir Bavi Power Company Ltd. (Tanir Bavi) plant in India was
sold in October 2002.
(4)
Assets not allocated
to a specific project, including corporate receivables.
For
additional information, see Item 7. MD&A — Future Outlook.
Global’s
strategic focus has shifted to one of improving profitability for currently
held investments, from one of significant growth. Near-term emphasis will
be placed on liquidity and completing current projects. Global has developed
or acquired interests in electric generation and/or distribution facilities
in the United States, Brazil, Chile, China, India, Italy, Peru, Poland,
Tunisia and Venezuela. In addition, projects are in construction in the
United States, China, Italy, Oman, Poland, South Korea and Taiwan. While
Energy Holdings still expects certain of its investments in Latin America
to contribute significantly to its earnings in the future, the political
and economic risks associated with this region could have a material adverse
impact on its remaining investments in the region. See Item 7. MD&A
— Future Outlook for additional information.
For
a discussion of the asset impairments due to the Argentine economic, political
and social crisis, see Note 13. Commitments and Contingent Liabilities and
Note 4. Asset Impairments of the Notes. Also see Note 4. Asset Impairments
and Note 5. Discontinued Operations of the Notes for a discussion of Global’s
sale of Tanir Bavi located in India.
For
additional information on Global’s investments in generation and
distribution facilities, see Item 2. Properties.
Resources
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. Also, the Demand
Side Management (DSM) business previously managed by Energy Technologies
was transferred
8
to Resources as of December 31, 2002. Since it was
established in 1985, Resources has grown its portfolio to include more than
60 separate investments. Resources expects to curtail its investment activity
in the near-term.
DSM revenues are earned
principally from monthly payments received from utilities, which represent shared
electricity savings from the installation of the energy efficient equipment.
For further discussion of the transfer of DSM to Resources, see Note 22. Related-Party
Transactions of the Notes.
The major components
of Resources’ investment portfolio as a percent of its total assets as
of December 31, 2002 were:
As of December 31,
2002
Amount
%
of
Resources’
Total Assets
(Millions)
Leveraged
Leases
Energy-Related
Foreign
$
1,181
38
%
Domestic
1,272
41
%
Real
Estate – Domestic
192
6
%
Aircraft
Foreign
44
2
%
Domestic
61
2
%
Commuter
Railcars – Foreign
86
3
%
Industrial
– Domestic
8
—
Total
Leveraged Leases, net
2,844
92
%
Limited Partnerships
Leveraged
Buyout Funds
93
3
%
Other
25
1
%
Total
Limited Partnerships
118
4
%
Marketable
Securities
5
—
Other Investments
33
1
%
Owned Property
59
2
%
Current and
Other Assets
27
1
%
Total Resources’
Assets
$
3,086
100
%
As of December 31,
2002, no single investment represented more than 7.5% of Resources’ total
assets.
Leveraged Lease
Investments
Resources seeks a portfolio
that provides a fixed rate of return, predictable income and cash flow and depreciation
and amortization deductions for federal income tax purposes. Income on leveraged
leases is recognized by a method which produces a constant rate of return on
the outstanding net investment in the lease, net of the related deferred tax
liability, in the years in which the net investment is positive. Any gains or
losses incurred as a result of a lease termination are recorded as revenues
as these events occur in the ordinary course of business of managing the investment
portfolio.
In a leveraged lease,
the lessor acquires an asset by investing equity representing approximately
15% to 20% of the cost and incurring non-recourse lease debt for the balance.
The lessor acquires economic and tax ownership of the asset and then leases
it to the lessee for a period of time no greater than 80% of its remaining useful
life. As the owner, the lessor is entitled to depreciate the asset under applicable
federal and state tax guidelines. In addition, the lessor receives income from
lease payments made by the lessee during the term of the lease and from tax
receipts associated with interest and depreciation deductions with respect to
the leased property. Lease rental payments are unconditional obligations of
the lessee and are set at levels at least sufficient to service the non-recourse
lease debt. The lessor is also entitled to any residual value associated with
the leased asset at the end of the
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lease term. An evaluation of the after-tax cash
flows to the lessor determines the return on the investment. Under generally
accepted accounting principles, the lease investment is recorded on a net basis
and income is recognized as a constant return on the net unrecovered investment.
Resources evaluates
lease investment opportunities with respect to specific risk factors. Any future
leveraged lease investments are expected to be made in energy-related assets.
For further information relating to the curtailment of Energy Holdings’
investments in the near term, see Item 7. MD&A – Overview. The assumed
residual value risk, if any, is analyzed and verified by third-parties at the
time the investment is made. Credit risk is assessed and, if necessary, mitigated
or eliminated through various structuring techniques, such as defeasance mechanisms
and letters of credit. Resources does not take currency risk in its cross-border
lease investments. Transactions are structured with rental payments denominated
and payable in US Dollars. Resources, as a passive lessor or investor, does
not take operating risk with respect to the assets it owns, so leases are structured
with the lessee having an absolute obligation to make rental payments whether
or not the assets operate. The assets subject to lease are an integral element
in Resources’ overall security and collateral position. If such assets
were to be impaired, the rate of return on a particular transaction could be
affected. The operating characteristics and the business environment in which
the assets operate are, therefore, important and must be understood and periodically
evaluated. For this reason, Resources retains experts to conduct regular appraisals
on the assets it owns and leases.
The ten largest lease
investments for Resources as of December 31, 2002 were as follows:
Investment
Description
Gross
Investment
Balances as of
December 31,
2002
% of
Resources’
Total
Assets
(Millions)
Reliant
Three generating stations
$
221
7
%
(Keystone, Conemaugh and
Shawville)
EME
Collins Electric Generation
185
6
%
Station
Seminole
Seminole Generation Station
175
6
%
Unit #2
Dynegy
Two electric generating stations
172
6
%
EME
Two electric generating stations
170
6
%
(Powerton and Joliet)
ENECO
Gas distribution network
141
5
%
(Netherlands)
Grand Gulf
Nuclear generating station
131
4
%
Merrill Creek
Merrill Creek Reservoir Project
129
4
%
ESG
Electric distributing system
108
3
%
(Austria)
EZH
Electric generating station
107
3
%
(Netherlands)
$
1,539
50
%
For further details
on leases, see Item 7A. Qualitative and Quantitative Disclosures About Market
Risk-Credit Risk-Energy Holdings.
Energy Technologies
Energy Technologies
is an energy management company whose primary objective was to construct, operate
and maintain heating, ventilating and air conditioning (HVAC) systems for and
provide energy-related engineering, consulting and mechanical contracting services
to industrial and commercial customers in the Northeastern and
10
Middle Atlantic United States. In June 2002, Energy
Holdings adopted a plan to sell its interests in these HVAC/mechanical operating
companies. The sale of these companies is expected to be completed by June 30,
2003. For more details, see Note 5. Discontinued Operations of the Notes
and Item 7. MD&A — Results of Operations — Discontinued Operations
— Energy Technologies.
Other Subsidiaries
Enterprise Group Development
Corporation (EGDC), a commercial real estate property management business, has
been conducting a controlled exit from the real estate business since 1993.
EGDC’s strategy is to preserve the value of its assets to allow for the
controlled disposition of its properties as favorable sales opportunities arise.
EGDC directly owns a 100% interest in two parcels of land available for development
located in New Jersey totaling $19 million. One of these parcels is classified
as Assets Held for Sale. EGDC also owns an 80% general partnership interest
in four partnerships which own and operate two buildings and land in New Jersey
totaling $15 million. EGDC also owns a 100% interest in development land located
in Maryland valued at $12 million. Together, the 100% wholly-owned land and
the 80% general partnership interests represent 72% of the total assets of EGDC.
Additionally, EGDC owns a 50% partnership interest in development land located
in Virginia. Total assets of EGDC as of December 31, 2002 and 2001 were $63
million and $65 million, respectively.
PSEG Capital Corporation
(PSEG Capital) has served as the financing vehicle, borrowing on the basis of
a minimum net worth maintenance agreement with PSEG. As of December 31, 2002
PSEG Capital had debt outstanding of $252 million, which matures in May 2003,
at which time the program will be terminated. For additional information including
certain restrictions relating to the BPU Focused Audit, see Item 7. MD&A
— Liquidity and Capital Resources.
Services
Services is a New Jersey
Corporation with its principal executive offices at 80 Park Plaza, Newark, New
Jersey 07102. Services provides management and administrative services to PSEG
and its subsidiaries. These include accounting, legal, communications, human
resources, information technology, treasury and financial, investor relations,
stockholder services, real estate, insurance, risk management, tax, library
and information services, security, corporate secretarial and certain planning,
budgeting and forecasting services. Services charges PSEG, PSE&G, Power
and Energy Holdings a fair market rate for services provided.
COMPETITIVE ENVIRONMENT
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 alternate electric or gas suppliers.
Power
Power primarily contracts
to provide energy to the direct suppliers of New Jersey electric utilities.
In recent years Power has expanded into other areas of its target market, the
Super Region, with acquisitions in New York and Connecticut and development
in the Midwest. As markets continue to evolve, several types of competitors
have or will emerge in Power’s target market. These competitors include
merchant generators with or without trading capabilities, other utilities that
have formed generation and/or trading affiliates, aggregators, wholesale power
marketers or combinations thereof. These participants will compete with Power
and one another buying and selling in wholesale power pools, entering into bilateral
contracts and/or selling to aggregated retail customers. These participants
can also be expected to adapt to changing market conditions, including developing
new generating stations where a perceived capacity shortfall may exist. Power
believes that its asset size and location, regional market knowledge and integrated
functions will allow it to compete effectively in its selected markets. However,
actions by developers, including Power, to build new generating stations has
lead to an overbuild situation, causing energy and capacity prices to be depressed
and possibly making some of its units uneconomical. The Midwest
11
market is expected to have excess capacity due to
recent additions, which will negatively impact the expected returns of Power’s
Lawrenceburg, Indiana and Waterford, Ohio facilities, presently under construction.
Additional legislation
has been introduced within the last few years to further encourage competition
at the retail level (often referred to as customer choice or retail access).
No legislative proposal exists at the federal level. However, there is also
a risk of re-regulation, if states decide to turn away from deregulation and
allow regulated utilities to continue to own or reacquire and operate generating
stations in a regulated and potentially uneconomical manner.
Power’s
businesses are also under competitive pressure due to technological advances in
the power industry and increased efficiency in certain energy markets. It is
possible that advances in technology will reduce the cost of alternative methods
of producing electricity to a level that is competitive with that of most central
station electric production.
Energy Holdings
Energy Holdings and
its subsidiaries are subject to substantial competition in the US as well as
in the international markets from independent power producers, 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. Energy Holdings
faces competition from companies of all sizes, having varying levels of experience,
financial and human capital and differing strategies. Competition can be based
on a number of factors, including price, reliability of service, the ability
of Energy Holdings’ customers to utilize other sources of energy and credit
quality of lease investments and partners.
Many states and countries
are considering or implementing different types of regulatory and privatization
initiatives that are aimed specifically at increasing competition in the power
industry. The increased competition that has resulted from some of these initiatives,
combined with certain overbuild situations, has contributed to a reduction in
electricity prices in some markets, and puts pressure on Energy Holdings and
other electric utilities to lower costs. Achieving and maintaining a lower cost
of production will be increasingly important to compete effectively in the energy
business. In the Texas market, excess capacity has led to uneconomical energy pricing,
negatively effecting two generating stations in Texas. For additional information
regarding the Texas power market, see Item 7. MD&A — Future Outlook.
Energy Holdings’
businesses are also under competitive pressure due to technological advances in
the power industry and increased efficiency in certain energy markets. It is
possible that advances in technology will reduce the cost of alternative methods
of producing electricity to a level that is competitive with that of most central
station electric production.
REGULATORY ISSUES
State Regulation
PSEG, PSE&G, Power and Energy Holdings
Focused Audit
In 1992, the BPU conducted a
Focused Audit of the impact of PSEG’s non-utility businesses, owned by Energy
Holdings, on PSE&G. Among other things, the BPU ordered that PSEG not permit
Energy Holdings’ investments to exceed 20% of PSEG’s consolidated assets without
prior notice to the BPU. In the Final Order issued in 1999, the BPU noted that,
due to significant changes in the industry and, in particular PSEG’s corporate
structure as a result of the Final Order, modifications to or relief from the
BPU’s Focused Audit order might be warranted. PSE&G has notified the BPU that
PSEG will eliminate PSEG Capital debt by the end of the second quarter of 2003
and that it believes that the Final Order otherwise supercedes the requirements
of the Focused Audit. While, PSE&G and Energy Holdings believe that this issue
will be satisfactorily resolved, no assurances can be given.
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 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. On February 8, 2002 and March
7, 2002, the BPU issued orders adopting the Competitive Service Audit reports
on New Jersey’s electric and gas utilities. The audit report generally
concluded that PSE&G was in compliance with the BPU’s affiliate standards.
On July 1, 2002, PSE&G filed its Affiliate Standards compliance plan in
accord with the BPU’s regulations. Also in July 2002, the BPU commenced
its next regular audit of the state’s electric and gas utilities’
competitive activities. The objectives of these audits are to assure that neither the utilities nor
their related competitive business segments enjoy an unfair competitive
advantage over their competitors and to assure that there is no form of
cross-subsidization of competitive services by utility operations or affiliates
with which they are associated. The audits will be guided by the BPU’s Affiliate
Standards requirements. A report is expected to be issued in the first quarter
of 2003. The outcome cannot be determined at this time.
PSEG, Power and Energy Holdings
PSEG, Power and Energy Holdings’ affiliates 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.
PSE&G
As a New Jersey public
utility, PSE&G is 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.
Electric Base
Rate Case
On May 24, 2002, PSE&G
filed an electric rate case with the BPU requesting an annual $250 million rate
increase for its electric distribution business. The proposed rate increase
includes $187 million of increased revenues relating to a $1.7 billion increase
in PSE&G’s rate base, which is primarily due to the investment that
PSE&G has made in its electric distribution facilities since its last rate
case in 1992; $18 million in higher depreciation rates and $45 million to recover
various other expenses, such as wages, fringe benefits and enhancements to security
and reliability. The requested increase proposes a return on equity of 11.75%
for PSE&G’s electric distribution business.
12
The proposed rate increase would significantly
impact PSE&G’s earnings and operating cash flows. The non-depreciation
portion of the noticed rate increase ($232 million) would have a positive effect
on PSE&G’s earnings and operating cash flows. The depreciation portion
of the rate increase ($18 million) would have no impact on PSE&G’s
earnings, as the increased operating cash flows would be offset by higher depreciation
charges.
In October 2002, the
New Jersey Ratepayer Advocate and other parties filed testimony, with the Ratepayer
Advocate recommending rate relief of approximately $87 million. Included in
the Ratepayer Advocate’s position is a 9.50% return on equity compared
to PSE&G’s requested 11.75% (approximately $45 million), a reduction
in electric distribution depreciation expenses (approximately $100 million),
and numerous other adjustments to PSE&G’s filing. The BPU has consolidated
PSE&G’s service company filing relating to the transfer of certain
assets from PSE&G to Services and its Street Lighting Tariff filing, which
adjusts tariff levels for electricity for certain street lights, into the base
rate proceeding for disposition.
In accordance with
BPU’s Final Order implementing parts of the Energy Competition Act, PSE&G
was required to provide temporary billing discounts in four steps totaling 13.9%
during the four-year transition period ending July 31, 2003. The last step,
a 4.9% decrease
,
took effect August 1, 2002. The combined effects of
base rate relief, the BGS auction and amortization
of various deferral balances, discussed below, is expected to yield rates comparable
to those in effect at the beginning of the deregulation process.
Neither PSEG nor PSE&G can predict the
outcome of these rate proceedings at the current time. Discussions are continuing
and hearings were held with an initial decision scheduled to be issued by May
1, 2003. The new rates are proposed to be effective August 1, 2003, consistent
with the Final Order.
Non-Utility
Generation (NUG) Contract Amendments
In June 2002, PSE&G
announced that it had amended its NUG power purchase agreements with El Paso
Corporation (El Paso) for its Camden, Bayonne and Eagle Point cogeneration facilities.
El Paso paid PSE&G $167 million for the amendment and agreed to provide
specified amounts of electric energy and capacity to PSE&G at a fixed price
and obtain this energy and capacity either from existing plants or in the open
market. The amended agreement has been approved by the BPU.
Deferral Proceeding
In August 2002, PSE&G
filed a petition proposing changes to two components of its rates, the Societal
Benefits Clause (SBC) and the Non-Utility Generation Transition Charge (NTC).
The proposed result, if adopted, will result in an annual reduction of revenues
of approximately $122 million or approximately a 3.4% reduction in amounts paid
by customers effective on August 1, 2003. The case has been transferred to the
Office of Administrative Law and a pre-hearing conference was held October 24,
2002. PSE&G cannot predict the outcome of this matter.
Deferral Audit
In September 2002,
the BPU retained the services of two outside firms to conduct a review of New
Jersey’s electric utilities’ deferred costs for compliance with BPU
mandates. Audit work has been completed and a final draft report was filed with
the BPU on December 16, 2002, with PSEG responding on December 30, 2002. Formal
comments on the final report are to be incorporated in the Deferral Proceedings,
discussed above.
PSE&G believes
that the final report will support its current practices and not impact its
financial position or results of operations.
13
Gas Base Rate
Case and Commodity Charges
In January 2002, the
BPU issued an order approving a settlement of PSE&G’s Gas Base Rate
case under which PSE&G is receiving an additional $90 million of gas base
rate revenues, approximately $8 million of which results from gas depreciation
rate changes. This occurred simultaneously with PSE&G’s implementation
of its previously approved Gas Cost Underrecovery Adjustment (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. 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 recovery of the GCUA over three years has no impact
on earnings, however it 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.
BGSS Filing
In September 2002, PSE&G filed to increase
its Residential BGSS Commodity Charge on November 1, 2002 to recover approximately
$89 million in additional revenues ($82 million of which is associated with
an underrecovered balance) or a 7.4% rate increase for the typical residential
gas heating customer. On January 8, 2003, the BPU approved the increase on a
provisional basis, to be effective immediately and the case has been transferred
to the Office of Administrative Law for hearings.
BGSS Design
On December 18, 2002,
the BPU approved BGSS Commodity filing procedure changes based upon the form
of generic settlement negotiated by the parties. An annual filing will be made
each year by June 1 for rate relief expected by October 1. That rate relief
may be supplemented by two potential self-implementing rate increases to the
maximum of 5% of the residential customer’s bill on December 1st and February
1st. All increases will be reconciled in the annual filing. As a result of the
delay in the implementation of the BGSS increase discussed above, PSE&G
has filed for a 5% self-implementing rate increase to be effective on March
1, 2003 which would reduce the expected underrecovery from $61 million to $37
million. PSE&G cannot predict the outcome of this matter.
Federal Regulation
PSEG, PSE&G,
Power and Energy Holdings
Public Utility
Holding Company Act of 1935 (PUHCA)
PSEG has claimed
an exemption from regulation by the Securities and Exchange Commission (SEC)
as a registered holding company under the 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
14
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 PSEG were no longer
exempt under PUHCA, PSEG and its 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. PSEG does not believe,
however, that this would have a material adverse effect on it and its subsidiaries.
Other
PSE&G’s,
Power’s and Energy Holdings’ domestic operations are subject to regulation
by FERC with respect to certain matters, including interstate sales and exchanges
of electric transmission, capacity and energy. PSE&G, Fossil, Nuclear and
Global are also subject to the rules and regulations of the US Environmental
Protection Agency (EPA), the US Department of Transportation (DOT) and the US
Department of Energy (DOE). For information on environmental regulation, see
Environmental Matters.
FERC
Regional Transmission Organization (RTO) Orders
In July 2002, the United
States Court of Appeals, D.C. Circuit, issued an opinion in favor of PSE&G
and certain other utility petitioners, reversing a previous order of the FERC
relating to the restructuring of PJM into an Independent System Operator (ISO).
The court ruled that
FERC lacked authority to require the utility owners
to give up certain statutory rights and should not have required a modification
to the PJM ISO Agreement eliminating utility owners rights to file changes to
rate design. The Court further noted that FERC lacked authority to require the
utility owners to obtain approval of their withdrawal from the PJM ISO, finding
that FERC had no jurisdiction to eliminate the withdrawal rights to which the
utilities had agreed. Further, in ruling on a specific argument raised by PSE&G,
the Court held that PSE&G did not have to modify a contract with Old Dominion
Electric Cooperative to accommodate the PJM restructuring. See Note 13. Commitments
and Contingent Liabilities of the Notes for additional information.
On remand, in December
2002, FERC refused to disclaim jurisdiction over a transmission owner’s
withdrawal from an ISO. In January 2003, PSE&G together with several of
the transmission owners filed for rehearing of the FERC decision. The potential
outcome of this rehearing could have implications for FERC’s jurisdiction
and authority to implement its standard market design, discussed below.
In January 2002, PJM
and the Midwest ISO (MISO) announced that it had entered into negotiations to
create a virtual uniform seamless market encompassing these two RTOs, shortly
after the FERC granted RTO status to the MISO. PSE&G also is participating
in a rate investigation by FERC into whether the “regional through-and-out
rates” between MISO and PJM should be eliminated. The proceeding could
result in lower rates paid by transmission customers. The impact of these developments
on PSE&G, Power and Energy Holdings is uncertain because specific rules
will not be known for some time and are subject to FERC approval, which cannot
be assured.
In April 2002, PJM
successfully implemented its “PJM West” expansion. Also, in December
2002, several major utilities in the Midwest and mid-atlantic area petitioned
FERC to become transmission owners within PJM. Implementation of this filing
would more than double the size of the current PJM region and would result in
a market encompassing more than 153,000 MW of generation capacity and more than
128,000 MW of peak load. Portions of this expansion could become effective as
early as Spring 2003 although a date for implementation cannot be determined
with certainty even if the filing is accepted by FERC.
In December 2002, FERC granted full RTO status to
PJM.
Standard Market Design
In July 2002, FERC
issued a Notice of Proposed Rulemaking (NOPR) to create a Standard Market Design
for the wholesale electricity markets in the United States. The NOPR seeks to
improve the consistency of market rules
15
throughout the country, including issues related
to reliability, market power concerns, transmission, pricing, congestion, governance
and other issues. If adopted, standard market design could significantly affect
transmission and generation operations in the various markets in which PSE&G,
Power and Energy Holdings operate.
Other
FERC issued an advance
NOPR seeking comments to help form the basis for a proposed rule to standardize
power-plant interconnection requirements to ease market entry for new generation
facilities. As part of the rulemaking, FERC also will 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 PSEG, PSE&G, Power
and Energy Holdings cannot be predicted.
PJM also filed an alternative
proposal to standardize its generator interconnection agreement and procedures
within PJM. FERC accepted this proposal, which is currently in effect in PJM.
In January 2003, FERC
also proposed a new transmission pricing policy that would give rate incentives
to engage in certain transactions, including transfer of control of transmission
facilities to a FERC-approved RTO; and joining an RTO but maintaining independence
from market participants. FERC also proposed to award an incentive
for new transmission facilities that are found appropriate
pursuant to an RTO transmission planning process. The ultimate outcome of this
proposal and its impact upon PSEG, PSE&G, Power and Energy Holdings cannot
be predicted.
Power
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.
The NRC has issued
orders to all nuclear power plants to implement compensatory security measures.
Some of the requirements formalize a series of security measures that licensees
had taken in response to advisories issued by the NRC in the aftermath of the
September 11, 2001 terrorist attacks. Power has evaluated these orders for the
Salem and Hope Creek facilities and does not expect the cost of implementation
of the NRC measures to be material.
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 has made the majority
of the necessary modifications to comply with these requirements, the cost of
which was approximately $26 million for Power. Minor completion activities remain,
the costs of which are not expected to be material.
Exelon has informed
Power that, on July 3, 2001, an application was submitted to the NRC to renew
the operating licenses for Peach Bottom 2 and 3. If approved, the current licenses
would be extended by 20 years, to 2033 and 2034 for Peach Bottom 2 and 3, respectively.
NRC review of the application is expected to take approximately two years.
In August 2002, the
NRC issued a bulletin requiring that all operators of pressurized water reactor
(PWR) nuclear unit submit certain information related to potential degradation
of reactor vessel heads. In September 2002, Power provided the requested information
for Salem. The response stated that a bare metal visual examination
will be performed on the Salem reactor vessel heads during each unit’s
next refueling outage, in compliance with the bulletin. If repairs are determined
to be necessary, it is estimated that the repair would extend the outage by
approximately four weeks. Bare metal visual inspections for Salem 1 and 2 were
completed during 2002 and no degradation of the reactor heads was observed.
On February 11, 2003 the NRC issued an order to all operators of PWR units concerning
reactor vessel head inspections. The order confirms the previous bulletin’s
16
requirements of more intrusive and frequent future
inspections, which apply to Salem 1 and 2. Power’s Hope Creek nuclear unit
and the Peach Bottom 2 and 3 are unaffected as they are Boiling Water Reactor
nuclear units. Power cannot predict what other actions the NRC may take on this
issue.
Foreign Regulation
Energy Holdings
Global
Global’s electric
distribution facilities in Latin America are rate-regulated enterprises. Rates
charged to customers are established by governmental authorities and, excluding
those rates at facilities in Argentina, which were fully impaired during 2002,
are currently sufficient to cover all operating costs and provide a fair return
in local currency terms. Global can give no assurances that future rates will
be established at levels sufficient to cover such costs, provide a return on
its investments or generate adequate cash flow to pay principal and interest
on its debt or to enable it to comply with the terms of its debt agreements.
Brazil
Rio Grande Energia
S.A. (RGE) is regulated by Agencia Nacional de Energia Eletrica (ANEEL), the
national regulatory authority. ANEEL’s functions include granting and supervising
electric utility concessions, approving electricity tariffs, issuing regulations
and auditing distribution systems’ performance. The rate setting process
for Brazilian distribution companies has two components, an annual adjustment
which RGE applies for every April and which is embedded in the concession contract,
and a rate revision which will be calculated for RGE in 2003 and every subsequent
fifth year anniversary.
The current regulatory
regime adjusts consumer electric tariffs based on a multiple-factor formula
that includes recovery of wholesale inflation for previous periods, as well
as an additional entitlement to pass through deferred US Dollar costs. This
current regulatory structure would result in an increase of approximately 40%
in the tariffs RGE would charge its customers starting in April 2003. ANEEL
has issued a resolution indicating that new distribution tariffs will be calculated
based on the replacement value of the electric utility companies’ assets
,
but has not yet determined the rate of return
to be allowed on this asset base
.
In addition, current electric regulation also allows ANEEL to apply an additional
upward or downward adjustment (known as the “X Factor”) to final tariff
determinations in order to adjust expected financial returns on the replacement
values of utility companies’ assets. The combination of these factors results
in considerable uncertainty regarding future revenue and cash flow levels associated
with Global’s investment in RGE. No assurances can be given that 2003 tariff
increases will be approved on a timely basis or at a sufficient level to support
planned levels of revenues and cash flows. For additional information, see Item
7. MD&A — Future Outlook.
ANEEL also monitors
service quality by auditing the duration and frequency of outages, as well as
several other performance measures. Global is implementing capital improvement
budgets which attempt to meet the quality of service standards. Failure to meet
required standards would result in penalties which, if assessed, would not be
expected to have a material negative impact on RGE’s results of operations,
although no assurances can be given.
RGE is currently engaged
in a dispute with ANEEL which is seeking to mandate a reduction in RGE’s
fixed asset base due to a pre-privatization review of Companhia Estadual de
Energia’s (CEEE) asset base. This pre-privatization review was not brought
to the attention of the bidders during the RGE privatization process. The result
of such a decrease in RGE’s fixed asset base would be a likely reduction
in RGE’s tariff of approximately $8 million during the next rate case as
RGE’s return on fixed assets would be above the accepted level. RGE is
currently contesting the matter.
17
Chile
Distribution companies
in Chile, including Chilquinta Energia S.A. (Chilquinta) and Sociedad Austral
de Electricidad S.A. (SAESA), are subject to rate regulation by the Comision
Nacional de Energia (CNE), a national governmental regulatory authority. The
Chilean regulatory framework has been in existence since 1982, with rates set
every four years based on a model company. The tariff which distribution companies
charge to regulated customers consists of two components: the actual cost of
energy purchased plus an additional amount to compensate for the value added
in distribution (DVA tariff). The DVA tariff considers allowed losses incurred
in the distribution of electricity, administrative costs of providing service
to customers, costs of maintaining and operating the distribution systems and
an annual real return on investment of 6% to 14%, based on the replacement cost
of distribution assets. Changes in electricity distribution companies’
cost of energy are passed through to customers, with no impact on the distributors’
margins (equal to the DVA tariff). Therefore, distributors, including SAESA
and Chilquinta, are not affected by changes in the generation sector which affect
prices.
The most recent tariff
adjustments for SAESA and Chilquinta occurred in 2000. The next tariff review
is scheduled for 2004. The DVA tariff index provides for monthly adjustments
based on variations in certain economic indicators whenever the component costs
increase by more than 3% over prior levels. This index provides inflation adjustments
and indirect partial devaluation protection. The CNE concluded a profitability
review of Chilean distribution companies in January 2002, with no resulting
adverse effects to SAESA or Chilquinta’s tariff rates. The CNE is in the
process of conducting its annual profitability reviews (similar to the one recently
completed) which may result in material adverse effects on tariffs for SAESA
and/or Chilquinta.
Chile has implemented
service quality standards and penalties; however, specific regulations have
not yet been published. Quality of service limits were published in Peru and
distribution companies are subject to penalties if these standards are not met.
Global is implementing capital improvement budgets which attempt to meet these
quality of service standards. Failure to meet required standards could result
in penalties, which, if assessed, are not expected to have a material impact
on the distribution system, although no assurances can be given.
Peru
Distribution companies
in Peru, including Global’s facility, Luz del Sur, are subject to rate
regulation by a national governmental regulatory authority. The Peruvian rate
setting mechanism was established in 1992 and is similar to the Chilean system
described above, except rates of return are between 8% and 16%. Rates are set
every four years. The latest rate case was completed in 2001. The next regularly
scheduled rate setting for Luz del Sur is in 2005.
CUSTOMERS
PSE&G
As of December 31,
2002, 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
Power sells energy
to the wholesale market in the Super Region, primarily in PJM. In the recent
New Jersey BGS auction, Power entered into hourly energy price contracts to
be a direct supplier of certain large customers and entered into contracts with
third parties who are direct suppliers of New Jersey’s EDCs.
Power currently has
over 177 active trading counterparties, which have passed a rigorous credit
analysis and contracting process. These include investor owned utilities, retail
aggregators and marketers.
18
Energy Holdings
Global
Global
has ownership interests in four distribution companies (excluding those in Argentina
which were fully impaired during 2002) which serve approximately 2.9 million
customers and has developed or acquired interests in electric generation facilities
which sell energy, capacity and ancillary 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—Energy Holdings—Electric
Distribution Facilities.
EMPLOYEE RELATIONS
PSE&G,
Power, Energy Holdings and Services believe that they maintain satisfactory
relationships with their employees. For information concerning employee pension
plans and other postretirement benefits, see Note 17. Pension, Other Postretirement
Benefit and Savings Plans of the Notes.
PSE&G
As of December
31, 2002, PSE&G had 6,376 employees. PSE&G has three-year collective
bargaining agreements in place with four unions, representing 4,927 employees,
which expire on April 30, 2005.
Power
As of December
31, 2002, Power had 3,398 employees. Power has collective bargaining agreements,
which expire on April 30, 2005, in place with three unions, representing 1,722
employees (901 employees, or approximately 68% of the workforce in Fossil and
821 employees, or approximately 44% of the workforce in Nuclear).
Energy Holdings
As of December
31, 2002, Energy Holdings had 2,109 employees. Energy Holdings had a total of
1,863 employees who are represented by various construction trade unions. Energy
Technologies and its operating subsidiaries are parties to agreements with various
trade unions through multi-employer associations.
Services
As of December
31, 2002, Services had 1,028 employees, none of which are unionized.
SEGMENT INFORMATION
Financial
information with respect to the business segments of PSEG, PSE&G, Power
and Energy Holdings is set forth in Note 19. Financial Information by Business
Segments of the Notes.
ENVIRONMENTAL MATTERS
PSEG, PSE&G, Power and Energy Holdings
Federal, regional,
state and local authorities regulate the environmental impacts of PSEG’s
operations within the United States. Environmental impacts associated with PSEG’s
operations in foreign countries are governed by laws and regulations particular
to the region, country, or locality where these operations are located. For
both domestic and foreign operations, areas of regulation may include air quality,
water quality, site remediation, land use, waste disposal, aesthetics, impact
on global climate, and other matters.
19
Power and Energy Holdings
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 in
the US that Power and Energy Holdings operate or in which they have an ownership
interest are subject to these Federal requirements, as well as requirements
established under state and local air pollution laws applicable where those
facilities are located. Except as noted below, capital costs of complying with
air pollution control requirements through 2004 are included in Power’s
estimate of construction expenditures in Item 7. MD&A.
Sulfur Dioxide
(SO
2
)/Nitrogen Oxide (NOx)
To
reduce emissions of SO
2
, the CAA sets a cap on total SO
2
emissions
from affected units and allocates SO
2
“allowances” (each
allowance authorizes the emission of one ton of SO
2
) to those units.
Generation units with emissions greater than their allocations can buy allowances
from sources that have excess allowances. Similarly, to reduce emissions of
NOx, 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. The NOx allowances can be bought and sold
through a regional trading program. In 2003, the cap will be reduced to limit
NOx emissions further.
The EPA has 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
from utility and industrial sources and subsequently cap these emissions. The
EPA has delayed the implementation until May 31, 2004. The NOx reduction requirements
are consistent with requirements already in place in New Jersey, New York, Connecticut
and Pennsylvania, and therefore are not likely to have an additional impact
on or change the capacity available from Power’s 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
SO
2
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 SO
2
program. Beginning in 2003, the NOx cap will be reduced in
New Jersey, New York, Pennsylvania, and other Northeastern states, which is
expected to materially increase the cost of complying with the NOx program in
those states. The extent of the increase across the region 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 impact of anticipated increases to the costs of
allowances. For additional information regarding the costs of these credits,
see Item 7. MD&A — Future Outlook.
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 SO
2
. In 2002, the EPA announced
that it would move forward with the process for identifying and designating
areas of the United States that fail to meet the revised federal health standard
for ozone or the new federal health standard for fine particulates. Designation
of these areas is expected in 2004, with states expected to develop regulatory
measures necessary to achieve and maintain the health standards thereafter.
Additionally, similar NOx and SO
2
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 Power’s 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.
20
CO
2
Emissions
In 2003, it is expected that the Kyoto Protocol
will become effective. This treaty will require substantial reductions of CO
2
and certain other greenhouse gases between 2008 and 2012. Although the US does
not intend to ratify the treaty, Energy Holdings’ assets in Europe will
be affected by implementation of the Kyoto Protocol, although the specific impacts
will depend upon the regulations adopted by the European Union (EU) and nations
looking to accede to the EU, such as Poland. At this juncture, costs or benefits
to Energy Holdings’ investments in Europe cannot be quantified with certainty.
On January 11,
2002, Power announced a voluntary agreement that calls for a goal of reducing
by December 31, 2005 the annual average CO
2
emission rate of its
fossil fuel fired electric generating units by 15% below the 1990 average annual
CO
2
emission rate of its New Jersey fossil fuel fired electric generating
units. Fossil also made a $1.5 million grant to the New Jersey Department of
Environmental Protection (NJDEP) to assist in the development of landfill gas
projects and has pledged to make an additional grant equal to $1 per ton of
CO
2
emitted greater than the 15% goal, up to $1.5 million, if that
reduction is not achieved.
There continues to
be a debate within the US over the direction of domestic climate change policy.
Congress is currently considering several bills that would impose mandatory
limitation of CO
2
emissions for the domestic power generation sector,
and several other states, primarily in the Northeastern US, are considering
state-specific or regional legislation initiatives to stimulate CO
2
emission reductions in the electric utility industry.
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 and 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.
Emissions of mercury
appear to be a focus of EPA rule-making for regulating HAP’s from
coal and oil-fired steam units. Several northeastern states also have expressed
an interest in regulating these emissions, including those states in which Power
owns and operates generation units. The impact on Power’s operations of
federal or state regulation of these emissions is still unknown.
The EPA missed the
May 2002 deadline for proposing HAP’s regulations for combustion turbines,
triggering a provision of the CAA that requires states to set HAP’s limits
on a case-by-case basis. In November 2002, the EPA proposed regulations for
combustion turbines, with the stated goal of adopting final standards before
companies would be required to fully engage the case-by-case standard setting
process with their state environmental agencies. Power and Energy Holdings are
currently assessing the impact of this rule proposal on their respective combustion
turbines.
Power
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 US, 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.
The EPA and the NJDEP
issued a demand in March 2000 under the CAA requiring information to assess
whether projects completed since 1978 at the Hudson and Mercer coal-fired units
were implemented in accordance
21
with applicable PSD/NSR regulations. Power completed
its response to the information request in November 2000. In January 2002, Power
reached an agreement with New Jersey and the 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 must install advanced
air pollution controls that are designed to reduce emissions of NOx, SO
2
,
particulate matter and mercury. The estimated cost of the program at the time
of the settlement was $337 million to be incurred through 2011. Power also paid
a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental
environmental projects. The agreement resolving the NSR allegations concerning
the Hudson and Mercer coal-fired units also resolved the dispute over Bergen
2 regarding the applicability of PSD requirements and allowed construction of
the unit to be completed and operation to commence.
Power has recently
notified the EPA and the NJDEP that it is evaluating the continued operation
of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity
markets and increases in the cost of pollution control equipment and other necessary
modifications. A decision is expected to be made in 2003 as to the Hudson unit’s
continued operation. The related costs associated with these modification have
not been included in Power’s capital expenditure projections.
As previously noted,
future environmental initiatives are expected to require reduced emissions of
NOx, SO
2
, mercury, and possibly CO
2
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.
Water Pollution Control
Power and Energy
Holdings
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 the EPA or by a state
under a federally authorized state program. The FWPCA authorizes the imposition
of technology-based and water quality-based effluent limits to regulate the
discharge of pollutants into surface waters and ground waters. The EPA has delegated
authority to a number of state agencies, including the NJDEP, to administer
the NPDES program through state acts. The New Jersey Water Pollution Control
Act (NJWPCA) authorizes the NJDEP to implement regulations and to administer
the NPDES program with EPA oversight, and to issue and enforce New Jersey Pollutant
Discharge Elimination System (NJPDES) permits. PSEG also has ownership interests
in domestic facilities in other jurisdictions that have their own laws and implement
regulations to regulate discharges to their surface waters and ground waters
that directly regulate Power’s 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 or in development
is subject to the Phase I rule.
EPA published for public comment on April 9, 2002
proposed draft Phase II rules covering large existing power plants and is expected
to issue final rules by February 16, 2004. The draft regulations propose to
establish three means of demonstrating
that a facility has the best technology available at an intake. 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 Power’s
existing facilities to meet the specific or performance criteria, identified
as an option under the draft rule, the retrofit would result in material costs
of compliance.
Power
Permit
Renewals
In June 2001, the
NJDEP issued a renewal permit for Salem, expiring in July 2006, allowing for
the continued operation of Salem with its existing cooling water system. Relating
to the implementation of the renewal permit,
22
Power has also reached a settlement with the Delaware
Department of Natural Resources and Environmental Control (DNREC). As part of
this agreement, Power deposited approximately $6 million into an escrow account
to be used for future costs related to this settlement.
The NJDEP is in the
process of reviewing the NJPDES permit renewal application for Power’s
Hudson Station. The consultant hired by NJDEP recommended that the Hudson Station
be retrofitted to operate with closed cycle cooling to address alleged adverse
impacts associated with the thermal discharge and intake structure. Power prepared
updated 316(a) and 316(b) demonstrations which proposed
certain modifications to the intake structure and resubmitted these demonstrations
to the NJDEP in 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
Power that it is reviewing a NJPDES permit renewal application for the Mercer
Station and, in connection with that renewal, will be reexamining the effects
of the Mercer Station’s cooling water system pursuant to FWPCA. Power has
submitted updated 316(a) and 316(b) 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 Power’s 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 its applications
to continue operations of its generating stations with present cooling water
intake structures.
Capital costs of complying
with water pollution control requirements through 2004 are included in Power’s
estimate of construction expenditures in Item 7. MD&A — Capital Requirements.
Control of Hazardous Substances
PSEG, PSE&G, Power and Energy Holdings
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.
PSE&G and
Power
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 “damages”
against persons who have discharged a hazardous substance, causing an “injury”
to natural resources. Pursuant to the Spill Act, the NJDEP requires all persons
conducting remediation to characterize “injuries” to natural resources
and to address those injuries through restoration or damages. PSE&G and
Power cannot assess the magnitude of the potential impact of this regulatory
change. Although not currently estimable, these costs could be material.
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 13. Commitments and
Contingent Liabilities of the Notes. For a discussion of remediation/clean-up
actions involving PSE&G and Power, see Item 3. Legal Proceedings.
Passaic
River Site
The EPA has
determined that a nine mile stretch of the Passaic River in the area of Newark,
New Jersey is a “facility” within the meaning of that term under CERCLA
and that, to date, at least thirteen corporations, including
23
PSE&G, may be potentially liable for performing
required remedial actions to address potential environmental pollution in the
Passaic River facility.
In a separate
matter, PSE&G and certain of its predecessors conducted industrial operations
at properties within the Passaic River facility. The operations included one
operating electric generating station, one former generating station, and four
former MGPs. PSE&G’s costs to clean up former MGPs are recoverable
from utility customers through the SBC. PSE&G has sold the site and obtained
releases and indemnities for liabilities arising out of the site in connection
with the sale. PSE&G cannot predict what action, if any, the EPA or any
third party may take against PSE&G with respect to this matter, or in such
event, what costs may be incurred to address any such claims. However, such
costs may be material.
PSE&G
Spill
Prevention Control and Countermeasure (SPCC)
In 1998, PSE&G
evaluated SPCC Plan compliance at all of its SPCC substations and identified
deficiencies. The necessary upgrades are now in the process of being made, the costs of
which are not expected to be material. It
is anticipated that these upgrades will take several years to complete. In July
2002, the EPA amended its SPCC regulations to, among other things, confirm the
regulations’ applicability to oil-filled electrical equipment.
Manufactured
Gas Plant Remediation Program (MGP)
For information
regarding PSE&G’s MGP, see Note 13. Commitments and Contingent Liabilities
of the Notes.
Power
Hudson
and Mercer Generation Stations
Approximately 150,000
tons of fly ash generated by the Hudson and Mercer Generating Stations was taken
by the ash marketer, that PSEG then worked with, and sold to the owner and operator
of a clay mine. The operator of the clay mine used the fly ash as fill material
to return the mine site to grade, without obtaining the necessary approvals
from the NJDEP. Upon discovery of this use, PSEG terminated the services of
this ash marketer and initiated discussions with NJDEP for the appropriate regulatory
approvals to allow this material to remain at the site. Power expects that the
NJDEP will likely require a clay cap and other engineering controls to ensure
that the ash is isolated from the environment if the ash is left in place. The
cost of resolving this matter will depend upon the results of the negotiations
with the NJDEP and the property owner. Although the precise extent of liability
is not currently estimable, it is not expected to be material.
Kearny
Generation Station
A preliminary review
of possible mercury contamination at the Kearny Station concluded that 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, which is expected in the next five years, dependent upon
market conditions.
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 US 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 $80 million (adjusted for inflation).
As of December 31, 2002, PSE&G had paid $58 million, resulting in a balance
due of $22 million. As of December 31, 2002, Power had a balance due of approximately
$5 million, which related to interests in certain nuclear units Power purchased
from Atlantic City Electric Company (ACE) and Delmarva Power and Light Company
(DP&L).
24
PSE&G and Power believe that they should not
be subject to collection of any such fund payments under the EPAct. A number
of nuclear generator owners filed
in the US Court of Claims and in the US District Court, Southern District of
New York to recover these costs. In July 2002, Power and PSE&G withdrew
from the lawsuit without prejudice, due to an unfavorable decision against
another nuclear generator owner in the lawsuit.
Power
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 nuclear fuel. To pay for this service, the nuclear plant owners
were required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001)
per kWh of nuclear generation ($21 million for 2002), subject to such escalation
as may be required to assure full cost recovery by the Federal government. Payments
made to the DOE for disposal costs are based on nuclear generation and are included
in Energy Costs in the Consolidated Statements of Operations.
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. If a DOE disposal facility is not available for
periods subsequent to the current license lives for Salem, Hope Creek and Peach Bottom,
construction of additional storage facilities would be necessary.
Under the NWPA, the
DOE was required to begin taking possession of the spent nuclear fuel by no
later than 1998. The DOE has announced that it does not expect a facility to
be available earlier than 2010. 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 incurred 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 DOE fees. Under this agreement, Power’s portion of Peach Bottom’s
Nuclear Waste Fund fees have been reduced by approximately $18 million through
August 31, 2002, at which point the credits were fully utilized and covered
the cost of Exelon’s storage facility.
In 2000, a group of
eight utilities filed a petition against the DOE in the US Court of Appeal,
for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon
out of the Nuclear Waste Fund, as stipulated in the Peach Bottom agreement.
On September 24, 2002, the US Court of Appeal, for the Eleventh Circuit, issued
an opinion upholding the challenge by the petitioners regarding the settlement
agreement’s compensation provisions. Under the terms of the agreement,
DOE and Exelon Generation are required to meet and discuss alternative funding
sources for the settlement credits. Initial meetings have occurred. The Eleventh
Circuit’s opinion suggests that the federal judgment fund should be available
as an alternate source. The agreement provides that if such negotiations are
unsuccessful, the agreement will be null and void. Any payments required by
us resulting from a disallowance of the previously reduced fees would be included
in Energy Costs in the Consolidated Statements of Operations.
In September 2001,
Nuclear filed a complaint in the US 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.
25
In October 2001, Nuclear
filed a complaint in the US 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.
In February 2002,
President Bush announced that Yucca Mountain in Nevada would be the permanent
disposal facility for nuclear wastes. On April 8, 2002, the Governor of Nevada
submitted his veto to the siting decision. On July 9, 2002, Congress affirmed
the President’s decision. The DOE must still license and construct the
facility. No assurances can be given regarding the final outcome of this matter,
however it may be several years before a permanent disposal facility is available.
Low
Level Radioactive Waste (LLRW)
As a by-product of
their operations, nuclear generation units produce LLRW. Such wastes include
paper, plastics, protective clothing, water purification materials and other
materials. LLRW materials are accumulated on site and disposed of at licensed
permanent disposal facilities. New Jersey, Connecticut and South Carolina have
formed the Atlantic Compact, which gives New Jersey nuclear generators, including
Power, continued access to the Barnwell LLRW disposal facility which is owned
by South Carolina. Power believes that the Atlantic Compact will provide for
adequate LLRW disposal for Salem and Hope Creek through the end of their current
licenses, although no assurances can be given. Both Power and Exelon have on-site
LLRW storage facilities for Peach Bottom, Salem and Hope Creek which have the
capacity for at least five years of temporary storage for each facility.
Other
Power has reported
to NRC and the NJDEP that it has detected the presence of tritium in three on-site
groundwater monitoring wells in excess of the applicable analytical method’s detection limit. Power is
continuing to investigate the source as well as the extent of the contamination.
At this time, it is not possible to determine whether the costs associated with
the investigation and/or remediation, if any, would be material.
ITEM 2. PROPERTIES
PSEG
PSEG does
not own any property. All property is owned by its subsidiaries.
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.
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 adequate insurance coverage against loss or damage
to its principal properties, subject to certain exceptions, to the extent such
property is usually insured and insurance is available at a reasonable cost.
Electric Transmission and Distribution Properties
As of December
31, 2002, PSE&G’s transmission and distribution system included approximately
21,873 circuit miles, of which approximately 7,518 circuit miles were underground,
and approximately 781,041 poles, of which approximately 536,260 poles were jointly
owned. Approximately 99% of this property is located in New Jersey.
26
In addition,
as of December 31, 2002, 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, 2002, the daily gas capacity of PSE&G’s 100%-owned peaking facilities
(the maximum daily gas delivery available during the three peak winter months)
consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG)
and aggregated 2,973,000 therms (approximately 2,886,000 cubic feet on an equivalent
basis of 1,030 Btu/cubic foot) as shown in the following table:
Plant
Location
Daily Capacity
(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, 2002, PSE&G owned and operated approximately 17,019 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.
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, 2002, PSE&G owned
41 switching stations in New Jersey with an aggregate installed capacity of
20,934 megavolt-amperes and 241 substations with an aggregate installed capacity
of 7,503 megavolt-amperes. In addition, 5 substations in New Jersey having an
aggregate installed capacity of 127 megavolt-amperes were operated on leased
property.
Power
Power rents
approximately 137,000 square feet of office space from PSE&G at its headquarters in Newark,
New Jersey. Other leased properties include office, warehouse, classroom and
storage space, primarily in New Jersey, used for system maintenance, procurement
and materials management staff, training and storage.
Through a subsidiary,
Power owns a 57.41% interest in approximately 12,000 acres of restored wetlands
and conservation facilities in the Delaware River Estuary that was formed to
acquire and own lands and other conservation facilities required to satisfy
the condition of the NJPDES permit issued for Salem. Power also owns several
other facilities, including the on-site Nuclear Administration and Processing
Center buildings.
Power has an 13.91%
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 companies that have generation facilities along the Delaware River or
its tributaries and use the river water in their operations. Power also owns
the Maplewood Test Services in Maplewood, New Jersey and the Central Maintenance
Shop at Sewaren, New Jersey.
27
Power believes that
it maintains adequate 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 Note 13. Commitments and Contingent Liabilities of
the Notes.
As of December 31,
2002, Power’s share of installed generating capacity was 13,055 MW, as
shown in the following table:
OPERATING POWER
PLANTS
Name
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principle
Fuels
Used
Mission
Steam:
Hudson, Jersey City
NJ
991
100%
991
Coal/Gas
Load Following
Mercer, Hamilton
NJ
648
100%
648
Coal/Gas
Load Following
Sewaren, Woodbridge Twp.
NJ
453
100%
453
Gas/Oil
Load Following
Linden, Linden (E)
NJ
430
100%
430
Oil
Load Following
Keystone, Shelocta (A)
PA
1,700
22.84%
388
Coal
Base Load
Conemaugh, New Florence (A)
PA
1,700
22.50%
382
Coal
Base Load
Kearny, Kearny (E)
NJ
300
100%
300
Oil
Load Following
Bethlehem, Albany (E)
NY
376
100%
376
Oil
Load Following
Bridgeport Harbor, Bridgeport
CT
534
100%
534
Coal/Oil
Base Load/Load
Following
New Haven Harbor, New Haven
CT
466
100%
466
Oil/Gas
Load Following
Total Steam
7,598
4,968
Nuclear:
Hope Creek, Lower Alloways Creek
NJ
1,049
100%
1,049
Nuclear
Base Load
Salem 1 & 2, Lower Alloways
Creek
NJ
2,221
57.41%
1,275
Nuclear
Base Load
Peach Bottom 2 & 3, Peach
Bottom (B)
PA
2,186
50%
1,093
Nuclear
Base Load
Total Nuclear
5,456
3,417
Combined Cycle:
Bergen, Ridgefield
NJ
1,221
100%
1,221
Gas
Load Following
Burlington, Burlington
NJ
245
100%
245
Gas
Load Following
Total Combined Cycle
1,466
1,466
Combustion Turbine:
Essex, Newark
NJ
617
100%
617
Gas/Oil
Peaking
Edison, Edison Township
NJ
504
100%
504
Gas/Oil
Peaking
Kearny, Kearny
NJ
443
100%
443
Gas/Oil
Peaking
Burlington, Burlington
NJ
557
100%
557
Oil
Peaking
Linden, Linden
NJ
324
100%
324
Gas/Oil
Peaking
Hudson, Jersey City
NJ
129
100%
129
Oil
Peaking
Mercer, Hamilton
NJ
129
100%
129
Oil
Peaking
Sewaren, Woodbridge Township
NJ
129
100%
129
Oil
Peaking
Bayonne, Bayonne
NJ
42
100%
42
Oil
Peaking
Bergen, Ridgefield
NJ
21
100%
21
Gas
Peaking
National Park, National Park
NJ
21
100%
21
Oil
Peaking
Kearny, Kearny
NJ
21
100%
21
Gas
Peaking
Linden, Linden (E)
NJ
21
100%
21
Gas/Oil
Peaking
Salem, Lower Alloways Creek
NJ
38
57.41%
22
Oil
Peaking
Bridgeport Harbor, Bridgeport
CT
19
100%
19
Oil
Peaking
Total Combustion Turbine
3,015
2,999
Internal Combustion:
Conemaugh, New
Florence
(A)
PA
11
22.50%
2
Oil
Peaking
Keystone, Shelocta (A)
PA
11
22.84%
3
Oil
Peaking
Total Internal Combustion
22
5
Pumped Storage:
Yards Creek,
Blairstown
(C)(D)
NJ
400
50%
200
Peaking
Total Operating Generation Plants
17,957
13,055
(A)
Operated by Reliant Resources
(B)
Operated by Exelon Generation LLC
(C)
Operated by Jersey Central Power
& Light Company
(D)
Excludes energy for pumping and
synchronous condensers.
(E)
These assets are scheduled for
retirement within the next three years, partially dependent upon new generation
going into service discussed below.
28
As of December 31,
2002, Power had 4,037 MW of generating capacity in construction or advanced development, as shown in
the following table:
POWER PLANTS IN CONSTRUCTION
OR ADVANCED DEVELOPMENT
Name
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principle
Fuels
Used
Scheduled
In Service
Date
Combined Cycle:
Bethlehem
NY
763
100%
763
Gas
June 2005
Lawrenceburg
IN
1,096
100%
1,096
Gas
November 2003
Waterford
OH
821
100%
821
Gas
June 2003
Linden
NJ
1,218
100%
1,218
Gas
March 2005
Total Construction
3,898
3,898
Nuclear Uprates
NJ/PA
139
100%
139
Nuclear
2003-2005
Total Advanced Development
139
139
Projected Capacity
(2002-2005)
Total
Capacity
(MW)
Total Owned Operating
Generating Plants
13,055
Under Construction
3,898
Advanced Development
139
Less: Planned Retirements
(1,127
)
Projected Capacity
15,965
Energy Holdings
Energy Holdings rents
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.
29
Global has invested
in the following generation facilities, which are in operation or under construction
as of December 31, 2002:
OPERATING POWER PLANTS
Name
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principle
Fuels
Used
United States (A)
Texas Independent Energy
Guadalupe
TX
1,000
50%
500
Natural gas
Odessa
TX
1,000
50%
500
Natural gas
Kalaeloa
HI
180
50%
90
Oil
GWF
Bay Area
I
CA
21
50%
10
Petroleum coke
Bay Area
II
CA
21
50%
10
Petroleum coke
Bay Area
III
CA
21
50%
10
Petroleum coke
Bay Area
IV
CA
21
50%
10
Petroleum coke
Bay Area
V
CA
21
50%
10
Petroleum coke
Hanford
CA
27
50%
14
Petroleum coke
GWF Energy:
Hanford
– Peaker Plant
CA
94
76%
71
Natural gas
Henrietta
– Peaker Plant
CA
96
76%
73
Natural gas
SEGS III
CA
30
9%
3
Solar
Tracy
CA
21
35%
7
Biomass
Bridgewater
NH
16
40%
6
Biomass
Conemaugh
PA
15
50%
8
Hydro
Total
United States:
2,584
1,322
International(B)
MPC
Jingyuan
– Units 5 and 6
China
600
15%
90
Coal
Tongzhou
China
30
40%
12
Coal
Nantong
China
30
46%
14
Coal
Jinqiao
(Thermal Energy)
China
N/A
30%
N/A
Coal/Oil
Zuojiang
– Units 1, 2 and 3
China
72
30%
22
Hydro
Fushi
– Units 1, 2 and 3
China
54
35%
19
Hydro
Shanghai
BFG
China
50
33%
16
Blast furnace gas
Haian
(Thermal Energy)
China
N/A
100%
N/A
Coal
Huangshi
Unit I
China
100
25%
25
Coal
PPN
India
330
20%
66
Naphtha/Natural gas
Prisma (C)
Crotone
Italy
20
25%
5
Biomass
Bando
D’Argenta I
Italy
10
50%
5
Biomass
Electroandes
Peru
183
100%
183
Hydro
Chorzow (Existing Facility)
Poland
100
55%
55
Coal
Skawina CHP
Poland
590
50%
295
Coal
Turboven
Maracay
Venezuela
60
50%
30
Natural gas
Cagua
Venezuela
60
50%
30
Natural gas
TGM
Venezuela
40
9%
4
Natural gas
Rades
Tunisia
471
60%
283
Natural gas
Total
International:
2,800
1,154
Total
Operating Power Plants:
5,384
2,476
30
Global has invested
in the following generation facilities which are under construction as of December
31, 2002:
POWER PLANTS IN CONSTRUCTION
Name
Location
Total
Capacity
(MW)
%
Owned
Owned
Capacity
(MW)
Principle
Fuels
Used
Scheduled
In
Service
Date
United States
GWF Energy
Tracy –
Peaker Plant
CA
167
76%
127
Natural gas
2003
International
MPC
Huangshi
Unit II
China
600
25%
150
Coal
2006
Yulchon
South Korea
612
50%
306
Natural Gas
2004
Kuo Kuang
Taiwan
480
18%
84
Natural gas
2003
Prisma (C)
Strongoli
Italy
40
25%
10
Biomass
2003
Bando D’Argenta
II
Italy
10
50%
5
Biomass
2003
Salalah
Oman
200
81%
162
Natural gas
2003
Chorzow
Poland
220
90%
198
Coal
2003
Total Construction:
2,329
1,042
TOTAL GENERATION FACILITIES:
7,713
3,518
(A)
In November 2002, Global sold its
interest in the generating station, Kennebec (Maine) to United American
Energy Corp.
(B)
Tanir Bavi (India) was sold in
October 2002 to GMR Vasavi Group. Also during 2002, assets in Argentina
were fully impaired. See Note 4. Asset Impairments and Note 5. Discontinued
Operations of the Notes.
(C)
All Prisma assets are currently
held for sale.
Domestic Generation
In Operation
Texas Independent
Energy, L.P. (TIE)
In
April 1999, Global and its partner, Panda Energy International, Inc., established
TIE, a 50/50 joint venture, which owns
and operates electric generation facilities in Guadalupe County in south
central Texas (Guadalupe) and Odessa in western Texas (Odessa).
Approximately
37.5% of the Guadalupe plant’s total output for 2003 has been sold
via bilateral power purchase agreements and the remainder will be sold in
the Texas spot market. In 2002, the plant generated approximately $145 million
of gross revenue.
Approximately
9.6% of the Odessa plant’s total output for 2003 has been sold via
bilateral power purchase agreements. The balance of the output will be sold
on a spot or short-term basis into the Texas power market. In 2002, the
plant generated approximately $161 million of gross revenue. For a discussion
of the Texas power market, see Item 7. MD&A — Future Outlook.
Kalaeloa
Global’s
partner in Kalaeloa is a power fund managed by Harbert Power. All of the
electricity generated by the Kalaeloa power plant is sold to the Hawaiian
Electric Company under a power purchase contract terminating in May 2016.
Under a steam purchase and sale agreement expiring in May 2016, the Kalaeloa
power plant supplies steam to Hawaiian Independent Refinery, Inc. In 2002,
the plant generated approximately $108 million of gross revenue. The plant
availability factor in 2002 was 99%.
31
GWF Power Systems
LP (GWF) and Hanford LP (Hanford)
Global and Harbert
Power each own 50% of the GWF plants. Power purchase contracts for the plants’
net output are in place with Pacific Gas and Electric Company (PG&E) ending
in 2020 and 2021. In 2002, the plants generated approximately $62 million of
gross revenue. The average availability factor of the five plants in 2002 was
95%.
Global and Harbert
Power each own 50% of Hanford. A power purchase contract for the plant’s
net output is in place with PG&E through 2011. The Hanford plant generated approximately $16 million
of gross revenue in 2002 and had an availability factor of 97%.
In July 2001, GWF,
Hanford and the Tracy biomass plant entered into an agreement with PG&E
and amendments to their power purchase agreements with PG&E
that contained the Public Utilities Commission of the State of California
approved pricing for a term of five years commencing July 16, 2001.
Hanford
and Henrietta Peaker Plants
In May 2001 GWF Energy
LLC (GWF Energy), a 50/50 joint venture between Global and Harbinger GWF LLC
(an affiliate of Harbert Power), entered into a 10-year power purchase agreement
with the California Department of Water Resources (DWR) to provide 340 MW of
electric capacity to California from three new natural gas-fired peaking plants.
As of December 31, 2002, Global’s ownership interest in this project was
76%. Energy and capacity not scheduled by the DWR is available for sale by GWF
Energy. Two of the plants, the Hanford and Henrietta Peaking plants, have commenced
commercial operation, and had approximately $25 million and $22 million in gross
revenue, respectively, during 2002.
For further information,
see Note 13. Commitments and Contingent Liabilities of the Notes.
International Generation in Operation
Global owns interests
in operating generation facilities in China, India, Italy, Peru, Poland, Tunisia
and Venezuela. In October 2002, a settlement was reached between AES Corporation
(AES) and Global under which Global will transfer its minority ownership interests
in certain Argentine assets to AES. For more details, see Note 4. Asset Impairments
of the Notes.
China
Meiya Power Company
Limited (MPC)
Global’s activities
in China and surrounding countries are conducted through MPC, a joint venture
with the Asian Infrastructure Fund (AIF) and Hydro Quebec International (HQI).
MPC is focused on developing,
acquiring, owning and operating electric and thermal heat generation facilities
in China, South Korea and Taiwan. MPC seeks to structure long-term power purchase
contracts with its customers and to incorporate take-or-pay and minimum take
provisions to support debt service and a specified equity return. Pricing terms
for energy from its facilities generally include a base price and indexed adjustments
to compensate for changes in inflation, foreign currency exchange rates up to
the minimum equity return and laws affecting taxes, fees and required reserves.
For cogeneration facilities, instead of selling the electricity through long-term
power purchase contracts, MPC sells its output through an annually determined
quota fixed in accordance with a predetermined formula which essentially determines
the amount of electricity to be sold by reference to the amount of steam generated
by the cogeneration facilities. The two cogeneration plants in Tongzhou and
Nantong operate under this system. MPC’s projects, either under construction
or in operation, have obtained all the required approvals to enable issuance
of a business license in their respective localities.
Minority investments
held by Global in nine generation facilities located in China generated 2% of
Global’s total gross revenues in 2002.
32
India
PPN Power Generating
Company Limited (PPN)
Global owns a 20%
interest in PPN located in Tamil Nadu, India. Global’s partners include
Marubeni Corporation, with a 26% interest, El Paso Energy Corporation, with
a 26% interest and the Reddy Group, with a 28% interest. PPN has entered into
a power purchase contract for the sale of 100% of the output to the State Electricity
Board of Tamil Nadu (TNEB) for 30 years, with an agreement to take-or-pay to
a plant load factor (PLF) of 85%.
Peru
Empresa de Electricidad
de los Andes S.A. (Electroandes)
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 a temporary
concession to develop two greenfield hydroelectric facilities totaling 180 MW
and expansion projects on existing stations totaling 100 MW. These concessions
expire in March 2003, but are renewable for two additional years. In 2002, 91%
of Electroandes revenues were obtained through power purchase agreements with
mining companies in the region. Electroandes generated approximately $45 million
of gross revenue in 2002.
Venezuela
Turbogeneradores
de Maracay (TGM)
Global, with a 9%
interest, is in partnership with Corporacion Industrial de Energia (CIE), to
own TGM. TGM sells all of the energy produced under contract to Manufacturas
del Papel (MANPA), a paper manufacturing concern located in Maracay. MANPA and
CIE have common controlling shareholders.
Turboven
The facilities in
Cagua and Maracay are owned and operated by Turboven, an entity which is jointly
owned by Global and CIE. To date, power purchase contracts have been entered
into for the sale of approximately 70% of the output of Maracay and Cagua, to
various industrial customers. The power purchase contracts are structured to
provide energy only with minimum take provisions. Fuel costs are passed through
directly to customers and the energy tariffs are calculated in US Dollars and
paid in local currency. In 2002, the plants in Maracay and Cagua generated $20
million of gross revenue.
Poland
Elcho
In October 2000, Global
acquired a 55% economic interest in a combined thermal energy and power generation plant in Chorzow,
in the Upper Silesia region of Poland, with Elektrownia Chorzow holding the
remaining interest. As a part of the acquisition of the existing plant, Global
obtained the rights to construct, and is constructing, a 220 MW electrical and
500 MW thermal combined thermal energy and power plant in Chorzow. Global currently holds
a 55% economic interest in Elektrocieplownia Chorzow Sp. z.o.o. (ELCHO), including
both the old plant and the plant under construction, with the anticipation of
expanding such interest to approximately 90% by 2003. Global intends to operate
the existing plant until the new plant comes on line in late 2003. Polskie Sieci
Elektroenergetyczne SA (PSE), the Polish power grid company, has signed a long-term
power purchase agreement with ELCHO and it is planned for all of the power to
be delivered into the local distribution system. During 2002, the existing plant
generated approximately $21 million of gross revenue. As of December 31, 2002, Energy
Holdings’ investment exposure, including contingencies, was $80 million.
33
Skawina
CHP Plant (Skawina)
During 2002, Global
acquired a 50% interest in Skawina, a combined thermal energy and power generation, for $31
million and will purchase additional shares in 2003 that will bring Global’s
aggregate interest in Skawina to approximately 65%. In addition, Global has
an obligation to offer to purchase an additional 10% ownership from Skawina’s
employees in 2004 for a total potential ownership in Skawina of 75%. Skawina
supplies electricity to three local distribution companies and heat mainly to
the city of Krakow, under one-year contracts consistent with current practice
in Poland. The sale is part of the Polish Government’s energy privatization
program. During 2002, the plant generated approximately $49 million of gross
revenue. As of December 31, 2002, Energy Holdings, investment exposure, including contingencies, was $90 million.
Tunisia
Rades
Global and its partner
Marubeni Corporation own 60% and 40%, respectively, of the Carthage Power facility
in Rades, Tunisia for which Global is the operator. A 20-year power purchase
contract has been entered into for the sale of 100% of the output to Societe
Tunisienne d’Electricite et du Gaz, the national utility. The tariff in
the power purchase contract consists of a fixed capacity charge to cover debt
and equity return as well as fixed and variable charges to cover fuel, operations
and maintenance costs. Each tariff component will be paid in local currency
(Dinars). Rades commenced operation in May 2002 and generated approximately $57 million
of gross revenue in 2002.
Power Plants Under Construction
Global has eight projects
in construction located in the United States, China, Italy, Oman, Poland, South
Korea and Taiwan. All of these plants have obtained power purchase contracts
for their output. The two projects under construction in Italy are currently
held for sale.
United States
Tracy
Peaker Plant
The Tracy Peaker
Plant is under construction with a commercial operation date deadline of July
1, 2003. Total project cost is expected to be $146 million. For additional information,
see Note 13. Commitments and Contingent Liabilities of the Notes.
Oman
Salalah
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. A consortium led by Global
(81% ownership) and several major Omani investment groups owns DPCO. The project
is expected to achieve commercial operation by April 2003. Total project cost
is estimated at $256 million. Global’s equity investment, including contingencies
and equity guarantees, is expected to be approximately $97 million. As of December 31, 2002, Energy Holdings’
investment exposure, including contingencies, was $39 million.
Poland
Elcho
Global’s 220
MW (electrical) and 500 MW (thermal) facility will replace an existing 100 MW
thermal energy and power generation facility. Global’s economic interest in the project
is currently 55%, with the anticipation of expanding such interest to approximately
90% by the end of 2003, with the balance held by a local Polish company. Total
project cost is estimated at $324 million. Global’s equity investment,
including contingencies, is not expected to exceed $105 million. The plant has
a targeted commercial operation date in late 2003. PSE, the Polish power grid
company, has entered into a 20-year power purchase agreement with ELCHO for
100% of the electrical output. All
34
of the thermal energy will be sold to Przedsiebiorstwo
Energetyki Cieplnej, the district heating company for a term of 20 years.
Taiwan
Kuo
Kuang
Through MPC, Global
owns a 17.5% indirect interest in a gas-fired combined-cycle electric generation
facility under construction in Kuo Kuang, Taiwan. MPC has a 35% interest in
Kuo Kuang and partners with two local Taiwanese companies, Chinese Petroleum
Corporation and CTCI Corporation. Kuo Kuang has entered into a 25-year power
purchase contract for the sale of 100% of its electric output to Taiwan Power
Company, the national utility. The power purchase contract payments consist
of a fixed capacity charge to cover debt and equity return as well as fixed
and variable charges to cover fuel, operations and maintenance costs. The tariff
will be paid in local currency. Kuo Kuang is expected to be in operation in
2003, with a total cost of approximately $320 million. Global’s equity
investment, including contingencies, is expected to be approximately $20 million.
South Korea
Yulchon
Through MPC, Global
owns a 50% indirect interest in Yulchon Generation Company, a gas-fired combined-cycle
plant under construction in South Korea. Open cycle operation of the plant is
scheduled for mid-2004, with conversion to combined-cycle operation scheduled
for mid-2005. The power will be purchased by state-owned Korea Electric Power
Company under a long-term power purchase contract. The total cost of the project
is expected to be $301 million, and will be provided by debt funds from project
finance sources and equity funds from MPC.
Electric Distribution Facilities
Global has
invested in the following distribution facilities:
Name
Location
Number
of
Customers
Global’s
Ownership
Interest
Rio Grande Energia
Brazil
1,020,000
32%
Chilquinta Energia
Chile
480,000
50%
SAESA
Chile
660,000
100%
Luz del Sur
Peru
720,000
44%
Total
2,880,000
Brazil
Rio
Grande Energia (RGE)
Together with VBC
Energia, a consortium of Brazilian companies formed to invest in electric privatization,
and Previ, the largest pension fund in Brazil, Global acquired RGE in 1997.
Global is the named operator for the system. A shareholders’ agreement
establishes corporate governance, voting rights and key financial provisions.
Global has veto rights over certain actions, including approval of the annual
budget and financing plan, executive officers, significant investments or acquisitions,
sale or encumbrance of assets, establishment of guarantees, amendment of the
concession agreement and dividend policies. Day-to-day operations are the responsibility
of RGE, subject to partnership oversight. During 2001, VBC Energia and Previ
transferred their shares to Companhia Paulista de Forcae Luz (CPFL), an electric
distribution company in which each of VBC Energia and Previ have an interest.
35
RGE operates under
a non-exclusive territorial concession agreement ending in 2027. The concession
is non-exclusive in that the distribution system must provide large consumers
the right to choose another provider of energy or to self-generate. Global does
not believe this represents a substantial threat to the profitability of the
distribution system in Brazil since the tariff structure provides the distribution
system the opportunity to recover all costs associated with distribution service
plus a return. RGE secures its energy supply through contractual agreements
expiring between 2007 and 2020. RGE will also purchase 20% of its energy requirements
through 2013 under the terms of contracts, which are denominated in US Dollars.
During 2002, RGE generated $430 million in gross revenue.
See Note 4. Asset
Impairments of the Notes for a discussion of the goodwill impairment recorded
for RGE. For a discussion of the Brazilian regulatory environment, see Item
1. Business — Regulatory Issues and Item 7. MD&A — Future Outlook.
Chile
Chilquinta
Energia S.A. (Chilquinta) and Luz del Sur (LDS)
Global together with
its partner, Sempra, jointly own 99.99% of the shares of Chilquinta, an energy
distribution company with numerous energy holdings, based in Valparaiso, Chile.
In addition, Global and Sempra jointly own 87.9% of LDS, which owns electric
distribution facilities in Peru.
As equal partners,
Global and Sempra share in the management of Chilquinta, however, Sempra has
assumed lead operational responsibilities at Chilquinta, while Global has assumed
lead operational responsibilities at LDS. The shareholders’ agreement gives
Global important veto rights over major partnership decisions including dividend
policy, budget approvals, management appointments and indebtedness.
In 2002, Chilquinta
generated approximately $132 million in gross revenues. Chilquinta operates
under a non-exclusive perpetual franchise within Chile’s Region V which
is located just north and west of Santiago. Global believes that direct competition
for distribution customers would be uneconomical for potential competitors.
LDS operates under an exclusive, perpetual franchise in the southern portion
of the city of Lima and in an area just south of the city along the coast serving
a population of approximately 3.2 million. In 2002, LDS generated gross revenues
of approximately $312 million. Both Chilquinta and LDS purchase energy for distribution
from generators in their respective markets on a contract basis.
For a discussion
of the regulatory environment in Chile and Peru, see Item 1. Business — Regulatory
Issues.
Sociedad
Austral de Electricidad S.A. (SAESA)
In 2001, Global purchased
a 99.9% equity in SAESA and its subsidiaries from Compañia de Petróleos
de Chile S.A. (COPEC). The SAESA group of companies consists of four distribution
companies and one transmission company that provide electric service to 390
cities and towns over 900 miles between Bulnes in the VIII Region and Cochrane
in the XI Region of southern Chile. Additionally, Global purchased from COPEC
approximately 14% of Empresa Eléctrica de la Frontera S.A. (Frontel),
not already owned by SAESA, to bring Global’s total interest in Frontel
to 95.5%.
Through its affiliated
company Sistema de Transmission del Sur S.A. (STS), SAESA provides transmission
services to electrical generation facilities that have power purchase arrangements
with distributors in Regions VIII, IX and X and has current capacity of 673
MVA.
SAESA also owns a
50% interest in an Argentine distribution company, Empresa de Energia Rio Negro
S.A. (EDERSA) which provides generation, transmission and distribution services
to 66 communities in the Province of Rio Negro, which is located close to Argentina’s
principal oil and gas reserves and has more than 600,000 residents.
SAESA and its Chilean
affiliates are organized and administered according to a centralized administrative
structure designed to maximize operational synergies. In Argentina, EDERSA has
its own independent administrative structure.
36
During 2002,
SAESA’s generated revenues of approximately $146 million, serving 660,000
customers.
Argentina
EDEN,
EDES and EDELAP
In October 2002, a
settlement was reached under which Global will transfer its minority interest
in the assets of Empresa Distribuidora de Energia Norte S.A. (EDEN), Empresa
Distribuidora de Energia Norte S.A. (EDES) Empresa Distribuidora La Plata S.A.
(EDELAP) and other investments to Global’s partner, AES. For more details,
see Note 4. Asset Impairments of the Notes.
EDEERSA
Global has an ownership
interest in Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA).
As of June 30, 2002, Global determined that its investment in EDEERSA was completely
impaired under Statement of Financial Accounting Standards (SFAS) No. 144. For
a detailed discussion, see Note 4. Asset Impairments and Note 13. Commitments
and Contingent Liabilities of the Notes.
37
ITEM 3. LEGAL
PROCEEDINGS
PSE&G
On November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint against PSE&G with the Federal Energy Regulatory Commission (FERC) pursuant to
Section 206 of the Federal Power Act asserting that PSE&G had breached agreements covering 1,000 MW of transmission by curtailing service and failing to maintain sufficient system capacity to satisfy all of its service obligations. PSE&G
denied the allegations set forth in the complaint. While finding that Con Edison’s presentation of evidence failed to demonstrate several of the allegations, on April 26, 2002, FERC found sufficient reason to set the complaint for hearing. An
initial decision issued by an administrative law judge in April 2002 upheld PSE&G’s claim that the contracts do not require the provision of “firm” transmission service to Con Edison but also accepted Con Edison’s contentions
that PSE&G was obligated to provide service to Con Edison utilizing all the facilities comprising its electrical system including generation facilities and that PSE&G was financially responsible for “out-of-merit,” i.e.,
above-market, generation costs needed to effectuate the desired power flows. Following the Initial Decision, PSE&G and Con Edison engaged in extensive settlement discussions in an attempt to settle their differences. This attempt was
unsuccessful. On December 9, 2002, FERC issued a decision modifying the Initial Decision by finding that only 600 MW of the total 1,000 MW power transfers is required to be supported by out-of-merit generation. FERC also made a number of other
findings, on a preliminary basis, including favorable findings to PSE&G that power transfers should be measured on a “net” basis that considers the impacts of third party transactions and that PSE&G’s obligations should be
reduced to the extent that Con Edison has impaired PSE&G’s ability to perform under the contracts. FERC remanded a number of issues to the administrative law judge for additional hearings, mainly related to the development of protocols to
implement the findings of the December 9, 2002 order. In addition, issues related to Phase 2 of the complaint involving the past administration of the contracts and a claim that PSE&G improperly benefited from the purchase of hedging contracts
in New York, is also pending before the administrative law judge. Hearings are scheduled to commence on March 5, 2003 and an initial decision by the administrative law judge is required by April 29, 2003. The nature and cost of any remedy, which is
expected to be prospective only, cannot be predicted, but is not expected to be material. Docket No. EL02-23-000.
Energy Holdings
The
Brazilian Consumer Association of Water and Energy has filed a lawsuit against
RGE, the 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. The plaintiff is seeking damages of approximately
$505 million. In August 2002 the Public Treasury Court in Porto Alegre dismissed
the case. The plaintiff filed a Notice of Appeal with the State
Court of Appeals in November 2002. 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 and Energy Holdings’ 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 for PSEG and each of PSE&G, Power and Energy Holdings as noted:
(1)
Pages 2 and 136. (PSE&G and Power) 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 3. (PSE&G and Power) Gas Contract transfer filing with the BPU.
(3)
Page 12. (PSE&G) PSE&G electric rate case filed with the BPU.
(4)
Page 13. Affiliate standards audit at the BPU.
(5)
Page 14. (PSE&G) Deferal Proceeding and Deferral Audit at the BPU.
(6)
Page 14. (PSE&G) PSE&G’s Gas Base Rate Filings, Docket Nos. GR01050328 and GR01050297.
(7)
Page 14. (PSE&G) BGSS filing with the BPU.
(8)
Page 14. (PSE&G) BGSS Design filing with BPU.
(9)
Page 15. (PSEG, PSE&G, Power and Energy Holdings) FERC proceeding related to PJM Restructuring.
38
(10)
Pages 15. (PSE&G) FERC proceeding related to MISO and PJM
(11)
Pages 17, 36 and 50. (Energy Holdings) Global’s rate case in Brazil.
(12)
Pages 22 and 23. (Power and Energy Holdings) Administrative proceedings before the NJDEP under the FWPCA for certain electric generating stations.
(13)
Pages 25, 26 and 163. (Power) DOE not taking possession of spent nuclear fuel, Docket No. 01-551C.
(14)
Pages 48 and 133. (Energy Holdings) AES termination of the Stock Purchase Agreement, relating to the sale of certain Argentine assets. New York State Supreme Court for New York County (Docket
No. 60155/2002) PSEG Global, et al vs. The AES Corporation, et al.
Page 161. (PSE&G) Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255.
(17)
Page 164. (Energy Holdings) Complaint filed with the FERC 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.
PSE&G and Power
In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSE&G and Power do not expect
expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their respective financial condition, results of operations and net cash flows.
(1)
Claim made in 1985 by US 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 US Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988.
(2)
Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. The EPA had named PSE&G as one of several potentially responsible parties (PRPs) through a series of
administrative orders between December 1984 and March 1985. Following work performed by the PRPs, the EPA declared on May 20, 1987 that all of its administrative orders had been satisfied. The NJDEP, however, named PSE&G as a PRP and issued its
own directive dated October 21, 1987. Remediation is currently ongoing.
(3)
Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with
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 Final Remedial Design
39
Report was submitted
to the EPA in September of 2002. 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. The remedy itself and responsibility for the costs of its
implementation are the subject of litigation currently venued in the United
States District Court for the Eastern District of Pennsylvania entitled
United States of America, et. al., v. Union Corporation, et. al., Civil
Action No. 80-1589.
(5)
The Klockner Road site
is located in Hamilton Township, Mercer County, New Jersey, and occupies
approximately two acres on PSE&G’s Trenton Switching Station property.
PSE&G 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)
The NJDEP issued Directives
to various entities, including PSE&G, seeking payment 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) and directing the respondents to
arrange for the operation, maintenance and monitoring of the implemented
remedial action or pay the NJDEP’s future costs of these activities,
estimated to be $39 million and prepare a work plan for the development
and implementation of a Natural Resource Damage Restoration Plan. The NJDEP
and The United States of America filed separate cost recovery actions pursuant
to CERCLA and/or the Spill Act seeking recovery of site investigation and
remediation response and administrative oversight costs. PSE&G was named
defendant in the NJDEP cost recovery action and a named third party defendant
in the contribution action filed in the United States’ lawsuit. All
of the foregoing claims against PSE&G were resolved by settlement in
2002.
(7)
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.
(8)
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 PSE&G’s facilities were 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 have executed an Order on Consent with NYSDEC for the investigation
of the site and have entered an agreement among the PRPs for the sharing
of the associated costs.
ITEM 4.
SUBMISSION OF MATTERS
TO A VOTE OF SECURITY HOLDERS
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