<PAGE>

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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K
(Mark One)
             [ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
                                       OR
              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
            For the transition period from             to
                                           -----------    -----------

<TABLE>
<CAPTION>
   COMMISSION                  REGISTRANT, STATE OF INCORPORATION,                   I.R.S. EMPLOYER
   FILE NUMBER                    ADDRESS, AND TELEPHONE NUMBER                     IDENTIFICATION NO.
-----------------         ----------------------------------------------         ----------------------
<S>                       <C>                                                    <C>
    000-49614                             PSEG POWER LLC                                22-3663480
</TABLE>

                     (A Delaware Limited Liability Company)
                               80 Park Plaza -T25
                          Newark, New Jersey 07102-4194
                                  973 430-7000

       SECURITIES REGISTERED PURSUANT TO SECTION 12 (b) OF THE ACT: - NONE

         SECURITIES REGISTERED PURSUANT TO SECTION 12 (g) OF THE ACT: -
                  LIMITED LIABILITY COMPANY MEMBERSHIP INTEREST

                   DOCUMENTS INCORPORATED BY REFERENCE - NONE


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrants were
required to file such reports) and (2) has been subject to such filing
requirements for the past 90 days. Yes [ ] No [X]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Registrant is a wholly owned subsidiary of Public Service Enterprise Group
Incorporated. Registrant meets the conditions set forth in General Instruction I
(1) (a) and (b) of Form 10-K and is filing this Annual Report on Form 10-K with
the reduced disclosure format authorized by General Instruction I.


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<PAGE>


                                 PSEG POWER LLC
                                TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                                         Page
                                                                                                         ----
<S>        <C>                                                                                          <C>
PART I
------
Item 1.    Business...................................................................................      1
           General....................................................................................      1
           Risk Factors...............................................................................      3
           Competitive Environment....................................................................      8
           Regulatory Issues..........................................................................      8
           Customers..................................................................................     11
           Employee Relations.........................................................................     13
           Segment Information .......................................................................     13
           Environmental Matters......................................................................     13
Item 2.    Properties.................................................................................     19
Item 3.    Legal Proceedings..........................................................................     21
Item 4.    Submission of Matters to a Vote of Security Holders........................................     22

PART II
-------
Item 5.    Market for Registrant's Common Equity and Related Stockholder Matters......................     23
Item 6.    Selected Financial Data....................................................................     23
Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations......     24
           Corporate Structure........................................................................     24
           Overview of 2001 and Future Outlook........................................................     24
           Results of Operations......................................................................     25
           Liquidity and Capital Resources............................................................     29
           Capital Requirements.......................................................................     30
           Qualitative and Quantitative Disclosures About Market Risk.................................     31
           Accounting Issues..........................................................................     33
           Forward Looking Statements.................................................................     34
Item 7A.   Qualitative and Quantitative Disclosures About Market Risk.................................     35
Item 8.    Financial Statements and Supplementary Data................................................     35
           Consolidated Financial Statements..........................................................     36
           Notes to Consolidated Financial Statements.................................................     41
           Independent Auditors' Reports..............................................................     62
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.......     63

PART III
--------
Item 10.   Directors and Executive Officers of the Registrant.........................................     63
Item 11.   Executive Compensation.....................................................................     64
Item 12.   Security Ownership of Certain Beneficial Owners and Management.............................     64
Item 13.   Certain Relationships and Related Transactions.............................................     64

PART IV
-------
Item 14.   Exhibits, Financial Statement Schedules and Reports on Form 8-K............................     65
           Schedule II--Valuation and Qualifying Accounts.............................................     66
           Signatures.................................................................................     67
</TABLE>


                                        i


<PAGE>


                                     PART I
                                     ------

ITEM 1. BUSINESS

GENERAL

         We are a Delaware limited liability company with our principal
executive offices at 80 Park Plaza, Newark, New Jersey 07102. We and our three
principal direct wholly-owned subsidiaries, PSEG Fossil LLC (Fossil), PSEG
Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) were
established to acquire, own and operate the electric generation-related business
of our affiliate, Public Service Electric and Gas Company (PSE&G) pursuant to
the Final Order issued by the New Jersey Board of Public Utilities (BPU), under
the Energy Competition Act discussed below. We also have a finance company
subsidiary, PSEG Power Capital Investment Company (Power Capital), which
provides certain financing for our subsidiaries.

         Unless the context otherwise indicates, all references to "Power,"
"we," "us" or "our" herein mean PSEG Power LLC, and its consolidated
subsidiaries. (For periods prior to August 21, 2000, " Power," "we," "us" or
"our" also includes PSE&G). We are a wholly-owned subsidiary of Public Service
Enterprise Group Incorporated (PSEG). PSEG is an exempt public utility holding
company under the Public Utility Holding Company Act (PUHCA). PSEG has three
other direct, wholly-owned subsidiaries: PSE&G, PSEG Energy Holdings Inc.
(Energy Holdings) and PSEG Services Corporation (Services). PSE&G is New
Jersey's largest public utility and is engaged principally in the transmission,
distribution and retail sale of electric energy and gas service in New Jersey.
Energy Holdings participates nationally and internationally in energy-related
lines of business through its subsidiaries. Services provides corporate support
and managerial and administrative services to PSEG and its affiliates.

         We are a multi-regional generating and energy trading company that
integrates our generating asset operations with our wholesale energy, fuel
supply, energy trading and risk management expertise. We currently have two
reportable segments, generation and energy trading. The generation segment of
our business earns revenues by selling energy on a wholesale basis under
contract to our affiliate, PSE&G, and to other power marketers and load serving
entities (LSE), and by bidding energy, capacity and ancillary services into the
wholesale energy market. We have contracted to sell to BGS suppliers beginning
August 1, 2002. The energy trading segment of our business earns revenues by
trading energy, capacity, fixed transmission rights, fuel and emission
allowances in the spot, forward and futures markets. The energy trading segment
also earns revenues through financial transactions, including swaps, options and
futures in the energy markets. Our target market, which is referred to herein as
the Super Region, extends from Maine to the Carolinas and the Atlantic Coast to
Indiana, encompassing 37% of the nation's power consumption. We are the single
largest power supplier in our primary market, the Pennsylvania-New
Jersey-Maryland Power Pool (PJM), which is one of the nation's largest and most
well-developed energy markets.

         Our generation portfolio consists of 11,487 megawatts (MW) of installed
capacity, which is diversified by fuel source and market segment. In addition,
we are currently constructing projects which will increase capacity by over
3,500 MW, net of planned retirements. For additional information, see Item 2 -
Properties.

         We participate primarily in the PJM market, where the pricing of energy
was recently modified. Prior to April 1999, the price of energy was based upon
the requirement that limited the bid prices for electric energy offered for sale
in the PJM market to the variable cost of producing such energy. As of April 1,
1999, the FERC lifted the requirement. However, transmission constraints have
and will continue to affect energy pricing in PJM. All power providers are now
paid the locational marginal price (LMP) set through power providers' bids. The
LMP tends to be higher in congested areas reflecting the bid prices of the
higher cost units that are dispatched to supply demand and alleviate
transmission constraints when coordination is sufficient to satisfy demand
within PJM. These bids are capped at $1,000 per 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.



                                       1
<PAGE>


         ELECTRIC FUEL SUPPLY

         The following table indicates our mWh output by source of energy in
2001 and our estimated output by source of energy for 2002:

                                                  ACTUAL         ESTIMATED
SOURCE                                             2001           2002 (A)
--------------------------------------------    ----------      -----------
Nuclear:
     New Jersey facilities..................        42%             40%
     Pennsylvania facilities................        21%             19%
Fossil:
     Coal:
     New Jersey facilities..................        12%             13%
     Pennsylvania facilities................        13%             13%
     Oil and Natural Gas....................        11%             14%
     Pumped Storage.........................         1%              1%
                                                ----------      -----------
         Total..............................       100%            100%
                                                ==========      ===========


         (A) No assurances can be given that actual output will match estimates.

         FOSSIL
         ------

         Fossil has an ownership interest in 11 fossil generating stations in
New Jersey, one fossil generating station in New York, and two fossil generating
stations in Pennsylvania. Fossil also has an ownership interest in one
hydroelectric pumped storage facility in New Jersey. For additional information,
see Item 2. Properties. Fossil uses coal, natural gas and oil for electric
generation. These fuels are purchased through various contracts and in the spot
market. Fossil does not presently anticipate any difficulties in obtaining
adequate coal, natural gas and oil supplies during the next several years.

         Fossil owns approximately 23% of the Keystone and Conemaugh coal-fired
generating stations located in western Pennsylvania and operated by Reliant
Energy Inc. Fossil has been advised by the plants' operator that there are
presently no anticipated difficulties in obtaining adequate coal supplies for
these facilities during the next several years.

         NUCLEAR
         -------

         Nuclear has an ownership interest in five nuclear generating units and
operates three of them, the Salem Nuclear Generating Station, Units 1 and 2
(Salem 1 and 2) each owned 57.41% by Nuclear and 42.59% by Exelon Generation LLC
(Exelon), and the Hope Creek Nuclear Generating Station (Hope Creek), 100% owned
by Nuclear. Exelon operates the Peach Bottom Atomic Power Station Units 2 and 3
(Peach Bottom 2 and 3), each of which is 50% owned by Nuclear. For additional
information, see Item 2. Properties.




                                       2
<PAGE>


         NUCLEAR FUEL

         We have several long-term contracts with uranium ore operators,
converters, enrichers and fabricators to meet the currently projected fuel
requirements for Salem and Hope Creek. We have been advised by Exelon that it
has similar contracts to satisfy the fuel requirements of Peach Bottom.
Refueling outages which are expected to last for approximately five to six weeks
are scheduled for Salem 1 and 2 and Peach Bottom 2 in 2002.

         ER&T
         ----

         ER&T purchases all of the capacity and energy produced by Fossil and
Nuclear. In conjunction with these purchases ER&T uses commodity and financial
instruments designed to cover estimated commitments for BGS and other bilateral
contract agreements (see Note 4.  Financial Instruments, Energy Trading and Risk
Management). ER&T also markets and trades electricity, capacity, ancillary
services and natural gas products on a wholesale basis throughout the Super
Region. ER&T is a fully integrated energy marketing and trading organization
that is active in the long-term and spot wholesale energy markets.

RISK FACTORS

         The following factors should be considered when reviewing our business,
and are relied upon by us in issuing any forward-looking statements. Such
factors could affect actual results and cause such results to differ materially
from those expressed in any forward-looking statements made by, or on behalf of
us. Some or all of these factors may apply to us and our subsidiaries.

CREDIT, COMMODITY AND FINANCIAL MARKET RISKS MAY HAVE AN ADVERSE IMPACT

         The revenues generated by the operation of our generating stations are
subject to market risks that are beyond our control. Our generation output will
either be used to satisfy our wholesale contracts or be sold into the
competitive power markets or under other bilateral contracts. Participants in
the competitive power markets are not guaranteed any specified rate of return on
their capital investments through recovery of mandated rates payable by
purchasers of electricity. Although a majority of our revenue is generated by
the BGS contract with PSE&G, (which expires on July 31, 2002 and is replaced
with one-year contracts with various direct bidders of the New Jersey BGS
Auction) and from bilateral contracts for the sale of electricity with
third-party LSEs and power marketers, our revenues and results of operations
will be dependent upon prevailing market prices for energy, capacity and
ancillary services in the markets we serve.

Among the factors that will influence the market prices for energy, capacity and
ancillary services are:

o        the extent of additional supplies of capacity, energy and ancillary
         services from current competitors or new market entrants, including the
         development of new generation facilities that may be able to produce
         electricity less expensively;
o        changes in the rules set by regulatory authorities with respect to the
         manner in which electricity sales will be priced;
o        transmission congestion and access in PJM and/or other competitive
         markets;
o        the operation of nuclear generation plants in PJM and other competitive
         markets beyond their presently expected dates of decommissioning;
o        prevailing market prices for enriched uranium, fuel oil, coal and
         natural gas and associated transportation costs;
o        fluctuating weather conditions;
o        reduced growth rate in electricity usage as a result of factors such as
         national and regional economic conditions and the implementation of
         conservation programs; and
o        changes in regulations applicable to PJM and other ISOs.

         As a result of the BGS auction, we have entered into contracts with the
direct suppliers of the New Jersey electric utilities, including PSE&G,
commencing August 1, 2002. These bilateral contracts are subject to credit risk.
This credit risk relates to the ability of counterparties to meet their payment
obligations for the power delivered under each BGS contract. Depending upon the
creditworthiness of the counterparty, this risk may be substantially higher than
the risk associated with potential nonpayment by PSE&G under the BGS contract
expiring July 31, 2002. Any failure to collect these payments under


                                       3
<PAGE>

the new BGS contracts with counterparties could have a material impact on our
results of operations, cash flows, and financial position.

ENERGY OBLIGATIONS, AVAILABLE SUPPLY AND TRADING RISKS MAY HAVE AN ADVERSE
IMPACT

         Our energy trading and marketing business frequently involves the
establishment of energy trading positions in the wholesale energy markets on
long-term and short-term bases. To the extent that we have forward purchase
contracts to provide or purchase energy in excess of demand, a downturn in the
markets is likely to result in a loss from a decline in the value of such long
positions as we attempt to sell energy in a falling market. Conversely, to the
extent that we enter into forward sales contracts to deliver energy we do not
own, or take short positions in the energy markets, an upturn in the energy
markets is likely to expose us to losses as we attempt to cover our short
positions by acquiring energy in a rising market.

         If the strategy we utilize to hedge our exposures to these various
risks is not effective, we could incur significant losses. Our substantial
energy trading positions can also be adversely affected by the level of
volatility in the energy markets that, in turn, depends on various factors,
including weather in various geographical areas and short-term supply and demand
imbalances, which cannot be predicted with any certainty.

         In addition, we are exposed to the risk that counterparties will not
perform their obligations. Although we have devoted significant resources to
develop our risk management policies and procedures and counterparty credit
requirements and will continue to do so in the future, we can give no assurance
that losses from our energy trading activities will not have a material adverse
effect on our business, prospects, results of operations, financial condition or
net cash flows.

         In connection with our energy trading business, we must meet certain
credit quality standards as are required by counterparties. Standard industry
contracts generally require trading counterparties to maintain investment grade
ratings. These same contracts provide reciprocal benefits to us. If we lose our
investment grade credit rating, ER&T would have to provide collateral (letters
of credit or cash), which would significantly impact the energy trading
business. This would increase our costs of doing business and limit our ability
to successfully conduct our energy trading operations.

THE ELECTRIC ENERGY INDUSTRY IS UNDERGOING SUBSTANTIAL CHANGE

         The electric energy industry in the State of New Jersey and across the
country is undergoing major transformations. As a result of deregulation and the
unbundling of energy supplies and services, the gas and electric retail markets
are now open to competition from other suppliers. Increased competition from
these suppliers could reduce the quantity of our retail sales and have a
negative impact on earnings and cash flows. We are affected by many issues that
are common to the electric industry such as:

o        deregulation, the unbundling of energy supplies and services and the
         establishment of a competitive energy marketplace for products and
         services;
o        energy sales retention and growth;
o        revenue stability and growth;
o        nuclear operations and decommissioning;
o        increased capital investments attributable to environmental
         regulations;
o        managing energy trading operations;
o        ability to complete development or acquisition of current and future
         investments;
o        managing electric generation operations in locations outside of our
         traditional utility service territory;
o        exposure to market price fluctuations and volatility;
o        regulatory restrictions on affiliate transactions; and
o        debt and equity market concerns.

GENERATION OPERATING PERFORMANCE MAY FALL BELOW PROJECTED LEVELS

         The risks associated with operating power generation facilities (each
of which could result in performance below expected capacity levels) include:


                                       4
<PAGE>

o        breakdown or failure of equipment or processes;
o        disruptions in the transmission of electricity;
o        labor disputes;
o        fuel supply interruptions;
o        limitations which may be imposed by environmental or other regulatory
         requirements;
o        permit limitations; and
o        operator error or catastrophic events such as fires, earthquakes,
         explosions, floods, acts of terrorism or other similar occurrences.

         Operation below expected capacity levels may result in lost revenues,
increased expenses and penalties. Individual facilities may be unable to meet
operating and financial obligations resulting in reduced cash flow.

WE ARE SUBJECT TO SUBSTANTIAL COMPETITION FROM WELL CAPITALIZED PARTICIPANTS IN
THE WORLDWIDE ENERGY MARKETS

         We and our subsidiaries are subject to substantial competition in the
United States from merchant generators, domestic and multi-national utility
generators, fuel supply companies, engineering companies, equipment
manufacturers and affiliates of other industrial companies. Restructuring of
energy markets, including the sale of utility-owned assets, is creating
opportunities for, and substantial competition from, well-capitalized entities
which may adversely affect our ability to make investments on favorable terms
and achieve our growth objectives. Increased competition could contribute to a
reduction in prices offered for power and could result in lower returns which
may affect our ability to service our outstanding indebtedness.

         Deregulation may continue to accelerate the current trend toward
consolidation among domestic utilities and could also result in the splitting of
vertically-integrated utilities into separate generation, transmission and
distribution businesses. As a result, additional competitors could become active
in the independent power industry.

OUR ABILITY TO SERVICE OUR DEBT COULD BE LIMITED

         We are a holding company with no material assets other than the stock
of our subsidiaries. Accordingly, all of our operations are conducted by our
subsidiaries. We depend on our subsidiaries' cash flow and our access to capital
in order to service our indebtedness. The project-related debt agreements of
subsidiaries generally restrict their ability to pay dividends, make cash
distributions or otherwise transfer funds to us. These restrictions may include
achieving and maintaining financial performance or debt coverage ratios, absence
of events of default, or priority in payment of other current or prospective
obligations.

         Our subsidiaries have financed some investments using non-recourse
project level financing. Each non-recourse project financing is structured to be
repaid out of cash flows provided by the investment. In the event of a default
under a financing agreement which is not cured, the lenders would generally have
rights to the related assets. In the event of foreclosure after a default, our
subsidiary may lose its equity in the asset or may not be entitled to any cash
that the asset may generate.

         We can give no assurances that our current and future capital
structure, operating performance or financial condition will permit us to access
the capital markets or to obtain other financing at the times, in the amounts
and on the terms necessary or advisable for us to successfully carry out our
business strategy or to service our indebtedness.

POWER TRANSMISSION FACILITIES MAY IMPACT OUR ABILITY TO DELIVER OUR OUTPUT TO
CUSTOMERS

         If transmission is disrupted, or if transmission capacity is
inadequate, our ability to sell and deliver our electric energy products may be
adversely impacted. If a region's power transmission infrastructure is
inadequate, our ability to generate revenues may be limited.


                                       5
<PAGE>

REGULATORY ISSUES SIGNIFICANTLY IMPACT OUR OPERATIONS

         The electric power generation business is subject to substantial
regulation and permitting requirements from federal, state and local
authorities. We are required to comply with numerous laws and regulations and to
obtain numerous governmental permits in order to operate our generation
stations.

         We believe that we have obtained all material energy-related federal,
state and local approvals including those required by the Nuclear Regulatory
Commission (NRC), currently required to operate our generation stations.
Although not currently required, additional regulatory approvals may be required
in the future due to a change in laws and regulations or for other reasons. No
assurance can be given that we will be able to obtain any required regulatory
approval that we may require in the future, or that we will be able to obtain
any necessary extension in receiving any required regulatory approvals. If we
fail to obtain or comply with any required regulatory approvals, there could be
a material adverse effect on our ability to operate our generation stations or
to sell electricity to third parties.

         We are subject to pervasive regulation by the NRC with respect to the
operation of our nuclear generation stations. Such regulation involves testing,
evaluation and modification of all aspects of plant operation in light of NRC
safety and environmental requirements. Continuous demonstrations to the NRC that
plant operations meet applicable requirements are also required. The NRC has the
ultimate authority to determine whether any nuclear generation unit may operate.

         We can give no assurance that existing regulations will not be revised
or reinterpreted, that new laws and regulations will not be adopted or become
applicable to us or any of our generation stations or that future changes in
laws and regulations will not have a detrimental effect on our business.

ENVIRONMENTAL REGULATION MAY LIMIT OUR OPERATIONS

         We are required to comply with numerous statutes, regulations and
ordinances relating to the safety and health of employees and the public, the
protection of the environment and land use. These statutes, regulations and
ordinances are constantly changing. While we believe that we have obtained all
material environmental-related approvals required as of the date hereof to own
and operate our facilities or that such approvals have been applied for and will
be issued in a timely manner, we may incur significant additional costs because
of compliance with these requirements. Failure to comply with environmental
statutes, regulations and ordinances could have a material effect on us,
including potential civil or criminal liability and the imposition of clean-up
liens or fines and expenditures of funds to bring our facilities into
compliance.

We can give no assurance that we will be able to:

o        obtain all required environmental approvals that we do not yet have or
         that may be required in the future;
o        obtain any necessary modifications to existing environmental approvals;
o        maintain compliance with all applicable environmental laws, regulations
         and approvals; or
o        recover any resulting costs through future sales.

         Delay in obtaining or failure to obtain and maintain in full force and
effect any such environmental approvals, or delay or failure to satisfy any
applicable environmental regulatory requirements, could prevent construction of
new facilities, operation of our existing facilities or sale of energy there
from or could result in significant additional cost to us.

WE ARE SUBJECT TO MORE STRINGENT ENVIRONMENTAL REGULATION THAN MANY OF OUR
COMPETITORS

         Our facilities are subject to both federal and state pollution control
requirements. Most of our generating facilities are located in the State of New
Jersey. In particular, New Jersey's environmental programs are generally
considered to be particularly stringent in comparison to similar programs in
other states. As such, there may be instances where the facilities located in
New Jersey are subject to more stringent and therefore more costly pollution
control requirements than competitive facilities in other states.

INSURANCE COVERAGE MAY NOT BE SUFFICIENT

         We have insurance for our generation stations, including all-risk
property damage insurance, commercial general public liability insurance, boiler
and machinery coverage, nuclear liability and, for our nuclear units,
replacement power and business interruption insurance in amounts and with
deductibles that we consider appropriate. We can give no assurance that such
insurance coverage will be available in the future on commercially reasonable
terms nor that the insurance proceeds


                                       6
<PAGE>

received for any loss of or any damage to any of the generation stations will be
sufficient to permit us to continue to make payments on our debt. Additionally,
certain properties that we own may not be insured in the event of a terrorist
activity.

ACQUISITION, CONSTRUCTION AND DEVELOPMENT ACTIVITIES MAY NOT BE SUCCESSFUL

         We may seek to acquire, develop and construct new energy projects, the
completion of any of which is subject to substantial risk. Such activity can
require us to expend significant sums for preliminary engineering, permitting,
fuel supply, legal and other expenses in preparation for competitive bids or
before it can be established whether a project is economically feasible.

         The construction, expansion or refurbishment of a power generation
facility may involve equipment and material supply interruptions, labor
disputes, unforeseen engineering, environmental and geological problems and
unanticipated cost overruns. The proceeds of any insurance, vendor warranties or
performance guarantees may not be adequate to cover lost revenues, increased
expenses or payments of liquidated damages. In addition, some power purchase
contracts permit the customer to terminate the related contract, retain security
posted by the developer as liquidated damages or change the payments to be made
to the subsidiary or the project affiliate in the event certain milestones, such
as commencing commercial operation of the project, are not met by specified
dates. If project start-up is delayed and the customer exercises these rights,
the project may be unable to fund principal and interest payments under our
project financing agreements. We can give no assurance that we will obtain
access to the substantial debt and equity capital required to develop and
construct new generation projects or to refinance existing projects to supply
anticipated future demand.

CHANGES IN TECHNOLOGY MAY MAKE OUR POWER GENERATION ASSETS LESS COMPETITIVE

         A key element of our business plan is that generating power at central
power plants produces electricity at relatively low cost. There are other
technologies that produce electricity, most notably fuel cells, microturbines,
windmills and photovoltaic (solar) cells. It is possible that advances in
technology will reduce the cost of alternative methods of producing electricity
to a level that is competitive with that of most central station electric
production. If this were to happen, our market share could be eroded and the
value of our power plants could be significantly impaired. Changes in technology
could also alter the channels through which retail electric customers buy
electricity, thereby affecting our financial results.

WE ARE SUBJECT TO CONTROL BY PSEG

         Our sole limited liability company member, PSEG, controls the election
of our directors and all other matters submitted for member approval and has
control over our management and affairs. In circumstances involving a conflict
of interest between PSEG, as the sole member, on the one hand, and our
creditors, on the other, we can give no assurance that PSEG would not exercise
its power to control us in a manner that would benefit PSEG to the detriment of
our creditors.

         The Indenture imposes no limitations on our ability to pay dividends or
to make other payments to PSEG or on our ability to enter into transactions with
PSEG or our other affiliates.

RECESSION, ACTS OF WAR, TERRORISM COULD HAVE AN ADVERSE IMPACT

         Consequences of the September 11, 2001 terrorist attacks on the United
States are difficult to predict. The consequences of a prolonged recession and
market conditions may include the continued uncertainty of energy prices and the
capital and commodity markets. We cannot predict the impact of any continued
economic slowdown or fluctuating energy prices; however, such impact could have
a material adverse effect on our financial condition, results of operations and
net cash flows.

         Like other operators of major industrial facilities, our generation
plants may be targets of terrorist activities that could result in disruption of
our ability to produce or distribute some portion of our energy products. Any
such disruption could result in a significant decrease in revenues and/or
significant additional costs to repair, which could have a material adverse
impact on our financial condition, results of operation and net cash flows.


                                       7
<PAGE>

COMPETITIVE ENVIRONMENT

         The regulatory structure which has historically governed the electric
and gas utility industries in the United States continues to be in transition.
Deregulation is essentially complete in New Jersey and is complete or under way
in other states in the Super Region and across the United States. States have
acted independently to deregulate and recent experience in California, with
energy shortages, high costs, and financial difficulties of the utilities have
caused states to re-evaluate and in some cases stop the move toward
deregulation. The deregulation and restructuring of the nation's energy markets,
the unbundling of energy and related services, the diverse strategies within the
industry related to holding, buying or selling generation capacity and the
anticipated resulting industry consolidation have a profound effect on us and
our subsidiaries, providing us with new opportunities and exposing us to new
risks (see Risk Factors and Overview of 2001 and Future Outlook of MD&A).

         The National Energy Policy Act of 1992 (Energy Policy Act) laid the
groundwork for competition in the wholesale electricity markets in the United
States. This legislation expanded FERC's authority to order electric utilities
to open their transmission systems to allow third-party suppliers to transmit,
or "wheel," electricity over their lines. In 1996, FERC issued an order that
resulted in expanded open access to transmission lines, providing eligible
third-party wholesale marketers comparable transmission access. These actions
have enabled power marketers, independent power producers, EWGs and utilities to
compete actively in wholesale markets, consumers to have the right to choose
their energy suppliers and competition to set the price of the generation
component of electricity bills in deregulated areas.

         During the last several years, additional legislation has been
introduced to further encourage competition at the retail level (often referred
to as customer choice or retail access). While no legislative proposal has yet
existed at the federal level, it is expected that efforts to restructure the
nation's electricity industry, encourage competition and greater industry
flexibility and allow retail customer choice will continue. At present, the
timing and effect of federal restructuring legislation cannot be predicted with
any degree of certainty. Nevertheless, an increasing number of states have
enacted legislation to open their markets to customer choice and retail
competition. As a result, the highly regulated market structure of the past is
giving way to a market where electricity consumers have the right to choose
their electricity supplier and competition is setting the price of the
generation component of electricity bills.

         In the regions where we are the most active, most states have already
begun the process of restructuring their electricity markets. As competitive
markets continue to evolve, several types of competitors have emerged or will
emerge in the markets in which we participate. These competitors include
merchant generators with or without trading capabilities, other utility
affiliates that have formed generation and/or trading affiliates, aggregators,
wholesale power marketers or some combination thereof. These participants will
compete with one another buying and selling in wholesale power pools, entering
into bilateral contracts and/or selling to aggregated retail customers. We
believe that our asset size and location, regional market knowledge and
integrated functions will allow us to compete effectively in our selected
markets.

REGULATORY ISSUES

         DEREGULATION

         Since the target markets in which we operate are deregulated at the
wholesale level, continued deregulation of the retail markets within the Super
Region is likely to bring new purchasers of electricity into the wholesale
markets, thus increasing the volume of transactions. This should continue to
strengthen the efficient operation and liquidity of those markets. Liquidity is
essential for efficiency as it provides a ready market for our generation output
and marketing and trading activities.

         STATE REGULATION

         Neither we nor PSEG is subject to direct regulation by the BPU.
However, because of PSEG's ownership of PSE&G, the BPU may potentially assert
regulation with respect to certain transfers of control and reporting
requirements. The BPU may also impose certain requirements with respect to
affiliate transactions between PSE&G and PSEG and/or PSEG's non-regulated
subsidiaries, including us. The BPU Order that authorized the transfer of
PSE&G's generation assets to us requires that, should any of those assets be
sold to a third party before August 24, 2004, the gains on any such sale would
have to be shared on a 50/50 basis with PSE&G's retail customers.


                                       8
<PAGE>

         As a participant in the ownership of generation facilities in
Pennsylvania, we are subject to regulation by the Pennsylvania Public Utilities
Commission (PPUC) in limited respects in regard to such facilities.

         NEW JERSEY ENERGY MASTER PLAN PROCEEDINGS, SECURITIZATION AND RELATED
         ORDERS

         Following the enactment of the Energy Competition Act, the BPU rendered
its Final Order relating to PSE&G's rate unbundling, stranded costs and
restructuring proceedings providing, among other things, for the transfer to an
affiliate of all of PSE&G's electric generation facilities, plant and equipment
for $2.443 billion and all other related property, including materials, supplies
and fuel at the net book value thereof, together with associated rights and
liabilities. PSE&G, pursuant to the Final Order, transferred its electric
generating facilities and wholesale power contracts to us and its subsidiaries
on August 21, 2000 in exchange for a promissory note from us in an amount equal
to the purchase price of $2.786 billion. We paid the promissory note on January
31, 2001 at which time the transferred assets were released from the lien of
PSE&G's First and Refunding Mortgage (Mortgage).

         The Energy Competition Act and the related BPU proceedings, including
the Final Order, referred to as the Energy Master Plan Proceedings, opened the
New Jersey energy markets to competition by allowing all New Jersey retail
electric and gas customers to select their suppliers. For further discussion of
the Energy Master Plan Proceedings, see Note 3. Regulatory Issues and Accounting
Impacts of Deregulation.

         In accordance with the Final Order, PSE&G reduced customer rates by 5%
in August 1999, an additional 2% after the securitization transaction in
February of 2001, another 2% in August 2001, and PSE&G is scheduled to reduce
rates 4.9% in August 2002, for a total 13.9% rate reduction since August 1999.
These rate reductions reduce the market transition charge (MTC) revenues that
PSE&G remits to us as part of its BGS contract.

         BGS AUCTION

         The BPU approved an auction to identify energy suppliers for our
obligation beginning on August 1, 2002. On February 15, 2002 the BPU approved
the BGS auction results and PSE&G secured contracts from a number of suppliers
for its expected peak load of 9,600 MW. Under the BPU approved supply contracts,
PSE&G will pay $.0511 per kWh to obtain electricity for customers for the period
from August 1, 2002 to July 31, 2003. Customers will continue to pay
below-market regulated rates (BGS shopping credit) for this one-year period.
Under our current rate structure, the difference will be deferred and is
expected to be recovered with interest in the future. PSE&G will sell the power
it receives from NUG contracts into the wholesale energy market, which should
offset this underrecovery. PSE&G estimates that the underrecovery relating to
the BGS for the period ending July 31, 2003 will amount to approximately $250
million, with a net amount of $125 million after factoring in sales of power
relating to NUG contracts.

         Through July 31, 2002, PSE&G will remain our main customer pursuant to
the BGS contract. Due to retail competition, PSE&G's retail market is expected
to experience minimal migration through July 31, 2002. Beginning August 1, 2002,
we will be a third party supplier to power marketers and LSE's serving New
Jersey's public utilities. Through July 31, 2002, we will continue to meet
PSE&G's demand through our generation and will purchase or sell needed or excess
generation capacity to supply retail aggregators and other LSE's.

         AFFILIATE STANDARDS

         In February 2000, the BPU approved affiliate standards and fair
competition standards which apply to transactions between a public utility and
those of its affiliates that provide competitive services to retail customers in
New Jersey. In March 2000, the BPU issued a written order (Affiliate Standards)
related to these matters. PSE&G filed a compliance plan in June 2000 to describe
the internal policy and procedures necessary to ensure compliance with such
Affiliate Standards. The BPU has conducted an audit of New Jersey utilities'
competitive activities and compliance with such Affiliate Standards and is
expected to issue an order on the audit in 2002. The adoption of Affiliate
Standards did not have a material adverse effect on our financial condition,
results of operations or net cash flows.

         GAS CONTRACT TRANSFER

         On August 11, 2000, PSE&G filed a gas merchant restructuring plan with
the BPU. On January 9, 2002, the BPU approved PSE&G's amended stipulation, which
authorized the transfer of PSE&G's gas supply business, including its


                                       9
<PAGE>

interstate capacity, storage and gas supply contracts to us. We will, under a
requirements contract, provide gas supply to PSE&G to serve its Basic Gas Supply
Service (BGSS) customers. PSE&G will pay us the amount it charges its gas
distribution customers for the commodity.

         FEDERAL REGULATION

         Certain of our subsidiaries' operations are subject to regulation by
FERC with respect to certain matters, including interstate sales and exchanges
of capacity and energy. PSEG has claimed an exemption from regulation by the
Securities and Exchange Commission (SEC) as a registered holding company under
the Public Utility Holding Company Act of 1935 (PUHCA), except for Section
9(a)(2), which relates to the acquisition of 5% or more of the voting securities
of an electric or gas utility company. Fossil and Nuclear are EWGs under PUHCA.
Failure to maintain status of these plants as EWGs could subject PSEG, us and
our subsidiaries to regulation by the SEC under PUHCA.

         If PSEG were no longer exempt from PUHCA, PSEG, we and our subsidiaries
would be subject to additional regulation by the SEC with respect to our
financing and investing activities, including the amount and type of non-utility
investments. We believe, however, that this would not have a material adverse
effect on us and our subsidiaries.

         We are also subject to the rules and regulation of the United States
Environmental Protection Agency (EPA), U.S. Department of Transportation (DOT)
and U.S. Department of Energy (DOE). For information on environmental
regulation, see Environmental Matters.

         FERC RTO ORDERS

         In December 1999, FERC promulgated a Final Rule (Order 2000) in the
Regional Transmission Organization (RTO) rulemaking proceeding. In October 2000,
PJM and nine PJM transmission owners, including us, made a filing with FERC
stating that PJM is an RTO that meets or exceeds the requirements of Order 2000.
Included in this filing was a PJM rate proposal designed to provide for deferral
recovery of reasonable, risk-adjusted returns on new transmission investments in
the PJM region, an accelerated recovery period for such new investments, and a
rate moratorium of current charges through December 31, 2004.

         In July 2001, FERC issued a series of orders that, amongst other
things, rejected the rate design proposal, established generation
interconnection proceedings and called for the creation of four large regional
transmission organizations (RTOs) to facilitate competitive regional markets in
the U.S. FERC rejected several smaller RTO proposals and directed transmission
owners and independent system operators (ISOs) to combine into much larger RTOs,
dramatically altering their proposed geographic size and configuration. In
August 2001, the PJM transmission owners requested a rehearing of the PJM RTO
Order. The matter is still pending.

         In the Southeast region, FERC rejected two separate RTO proposals and
directed parties to engage in mediation under the supervision of an
Administrative Law Judge to pursue the goal of creating a single Southeast RTO
using the proposed "Grid South platform". We participated in this discussion.
Another model for forming a market for the Southeast region continues to evolve.

         In the Northeast region, FERC conditionally approved the PJM RTO
proposal (subject to several modifications and compliance filings) and rejected
the New York ISO and ISO-New England RTO proposals. FERC directed that the three
existing ISOs for PJM, New York and New England, as well as the systems involved
in PJM West, form a single Northeast RTO, based on the "PJM platform" and "best
practices" of all three ISO's. FERC directed that the parties in the region
engage in mediation (with FERC oversight) to prepare a proposal and timetable
for the merger of the ISOs into a single RTO. At the end of the 45-day mediation
period, the Administrative Law Judge assigned to the matter submitted a report
to the Commission with an attached business plan for implementation of the
single northeast RTO possibly as soon as the fourth quarter of 2003.

         In January 2002, PJM and the Midwest ISO announced that they had
entered into negotiations to create a virtual uniform seamless market
encompassing their two RTOs, shortly after the FERC approved the Midwest ISO as
an RTO. In addition, ISO New England and the New York ISO agreed to jointly
develop a common electricity market and evaluate a New England - New York RTO.

         FERC has started a series of conferences to discuss the technical
issues related to its consideration of a standard market design - products and
protocols - for wholesale electric power markets. The goal of these conferences
is to gain a mutual understanding of similarities and differences between
various market designs and to allow participants to provide further detail on
market operations. We have been supportive of the incorporation of both capacity
and spot energy markets


                                       10
<PAGE>

as part of any standardized market design. The information from these
conferences will be used to issue a formal Notice of Proposed Rulemaking (NOPR)
on a standard market design later this year.

         FERC issued an advance notice of proposed rulemaking seeking comments
to help form the basis for a proposed rule to standardize power-plant
interconnection requirements to ease market entry for new generation. FERC also
will, as part of the rulemaking, reconsider its policy addressing how
transmission owners treat the cost of system upgrades necessary to accommodate
new generation, potentially resulting in a new methodology. The ultimate outcome
of this rulemaking and its impact upon us cannot be predicted.

         The impact of these developments on us is uncertain because specific
rules will not be known for some time and are subject to FERC approval, which
cannot be assured.

         NUCLEAR REGULATORY COMMISSION

         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
Nuclear Regulatory Commission has issued Orders dated February 25, 2002 to all
nuclear power plants to implement interim compensatory security measures. Some
of the requirements formalize a series of security measures that licensees had
taken in response to advisories issued by the NRC in the aftermath of the
September 11 terrorist attacks. Power has evaluated the Orders for the Salem and
Hope Creek facilities and considers the implementation of the NRC measures to be
without adverse material consequence to the NRC operating license or business
interests

         In accordance with NRC requirements, nuclear plants utilize various
fire barrier systems to protect equipment necessary for the safe shutdown of the
plant in the event of a fire. The NRC has identified certain issues at Salem and
Power is in the process of making the necessary modifications to comply with
these requirements, the cost of which are not expected to be material. Failure
to resolve fire barrier issues could result in potential NRC violations, fines
and/or plant shutdown which could have a material adverse impact to our
financial condition, results of operations and net cash flows.

         Exelon, co-owner and operator of Peach Bottom, has informed Nuclear
that on July 3, 2001 an application was submitted to the NRC to renew the
operating licenses for Peach Bottom Units 2 and 3. If approved, the current
licenses would be extended by 20 years, to 2033 and 2034 for Units 2 and 3
respectively. NRC review of the application is expected to take approximately
two years.

         For certain litigation relating to Salem, see Item 3. Legal
Proceedings. For discussion of the renewal of New Jersey Pollutant Discharge
Elimination System (NJPDES) permit related to Salem and our operations, see
Water Pollution Control.

CUSTOMERS

         Pursuant to the BGS contract, PSE&G will be the primary customer for
our generation business through July 31, 2002. PSE&G, under the terms of the
Final Order, is required to provide basic generation service to all retail
customers in its service area that either do not choose to buy their power from
alternative suppliers or are not being served by their alternative energy
supplier for any reason. PSE&G will pay us the full amount charged to BGS
customers, or the retail tariff rate on file at the BPU, less any sales and use
taxes. In addition, PSE&G pays us a price stability charge to compensate us for
ensuring the reliability of BGS service and minimizing PSE&G's exposure to price
volatility risk. The charge is equal to the full amount collected by PSE&G for
its unsecuritized generation stranded costs per billing period, known as the
MTC. As of December 31, 2001, PSE&G provided service to approximately 99% of its
traditional load. For the year ended December 31, 2001, our electric operating
revenues associated with this customer base aggregated approximately $1.8
billion. PSE&G's peak load during the summer of 2001 was 10,425 MW.

         We have entered into one-year contracts commencing August 1, 2002 with
various direct bidders in the New Jersey BGS Auction, which was approved by the
BPU on February 15, 2002. We believe that our obligations under these contracts
are reasonably balanced by our available supply.


                                       11
<PAGE>

         We continue to supply certain municipal and electric cooperative
customers and one public utility a total of 489 MW of capacity, including some
other obligations, such as energy, under the terms of existing contracts for the
remaining one to five years of those contracts.

         Wholesale energy and related product trading have been growing business
opportunities throughout the Super Region over the last ten years and we have
been in the forefront as an active participant. Trading relationships have been
developed with most of the larger and more successful power marketers and
existing trading relationships have been strengthened with the region's
utilities. More recently, new relationships have developed with companies that
are focused on aggregating retail customers in states that have deregulated. We
currently have over 100 active trading counterparties, which have passed a
rigorous credit analysis and contracting process. These include investor owned
utilities, retail aggregators and marketers.

         For a discussion of our future strategy and the auction impact, refer
to Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations. Additionally, for risks associated with counterparties,
see Risk Factors discussed above.



                                       12
<PAGE>


EMPLOYEE RELATIONS

         As of December 31, 2001, we had a total of 3,143 employees, of whom 967
were dedicated to Fossil, 1,829 to Nuclear, 73 to ER&T and 274 in corporate
functions. Collective bargaining agreements, which expire on April 30, 2005, are
in place with three union groups, representing 1,597 employees (774 employees,
or approximately 80% of the workforce in Fossil and 823 employees, or
approximately 45% of the workforce in Nuclear). We maintain satisfactory
relationships with our employees.

SEGMENT INFORMATION

         Financial information with respect to our business segments is set
forth in Note 9. Financial Information by Business Segments.

ENVIRONMENTAL MATTERS

         Federal, regional, state and local authorities regulate the
environmental impacts of our operations. Areas of regulation include air
quality, water quality, site remediation, land use, waste disposal, aesthetics
and other matters.

         Compliance with environmental requirements has caused us to modify the
day-to-day operations of our facilities, to participate in the cleanup of
various properties that have been contaminated and to modify, supplement and
replace existing equipment and facilities. During 2001, we expended
approximately $13 million for capital related expenditures to improve the
environment and comply with environmental-related laws and regulations. Our
estimates are that we will expend approximately $52 million, $71 million and $35
million in the years 2002 through 2004, respectively, including such amounts
discussed in the PSD/New Source Review section below. Such amounts are also
included in estimates of construction expenditures (see MD&A -- Liquidity and
Capital Resources).

AIR POLLUTION CONTROL

         Federal air pollution laws (such as the Federal Clean Air Act (CAA) and
the regulations implementing those laws, require controls of emissions from
sources of air pollution, and also impose record keeping, reporting and permit
requirements. Facilities that we operate or in which we hold an ownership
interest are subject to these Federal requirements, as well as requirements
established under state and local air pollution laws applicable where those
facilities are located. Capital Costs of complying with air pollution control
requirements through 2004 are included in our estimate of construction
expenditures in MD&A.

PREVENTION OF SIGNIFICANT DETERIORATION (PSD)/NEW SOURCE REVIEW(NSR)

         In November 1999, the federal government announced the filing of
lawsuits by several states against seven companies operating power plants in the
Midwest and Southeast, charging that 32 coal-fired plants in ten states violated
the PSD/NSR requirements of the CAA. Generally, these regulations require major
sources of certain air pollutants to obtain permits, install pollution control
technology and obtain offsets in some circumstances when those Sources undergo a
"major modification," as defined in the regulations. Various environmental and
public interest organizations have given notice of their intent to file similar
lawsuits. The federal government is seeking to order these companies to install
the best available air pollution control technology at the affected plants and
to pay monetary penalties of up to $27,500 for each day of continued violation.

         The EPA and NJDEP issued a demand in March 2000 under section 114 of
the CAA requiring information to assess whether projects completed since 1978 at
the Hudson and Mercer coal burning units were implemented in accordance with
applicable PSD/NSR regulations. We completed our response to the section 114
information request in November 2000. In January 2002, we reached an agreement
with the state and federal governments to resolve allegations of noncompliance
with federal and State of New Jersey PSD/NSR regulations. Under that agreement,
over the course of 10 years we will install advanced air pollution controls that
are expected to significantly reduce emissions of nitrogen oxides (NOx), sulfur
dioxide (SO2), particulate matter and mercury from these units. The estimated
cost of the program is $337 million to be incurred over the next ten years. We
also will pay a $1.4 million civil penalty and spend up to $6 million on
supplemental environmental projects. Capital costs of complying with these and
other air pollution control requirements through 2004 are included in our


                                       13
<PAGE>

estimate of construction expenditures (see Capital Requirements of Management
Discussion and Analysis (MD&A)). The agreement is still subject to public
comment and judicial approval as to which no assurances can be given.

         As noted below, future environmental initiatives are expected to
require reduced emissions of NOx, SO2, mercury, and possibly CO2 from electric
generating facilities. The emission reductions to be achieved at the Hudson and
Mercer coal units are expected to assist in complying with such future
requirements.

         In 2001, the EPA indicated that it was considering enforcement action
under its PSD rules relating to the construction of Bergen 2, scheduled for
operation in 2002. EPA maintained that PSD requirements were applicable to
Bergen 2, thereby requiring us to obtain a permit before beginning actual
on-site construction. The agreement resolving the NSR allegations concerning the
Hudson and Mercer coal-fired units also resolved the dispute over Bergen 2, and
allowed construction of the unit to be completed and operation to commence.

         SULFUR DIOXIDE/NITROGEN OXIDE

         To reduce emissions of SO2, the CAA sets a cap on total SO2 emissions
from affected units and allocates SO2 "allowances" (each allowance authorizes
the emission of one ton of SO2) to those units. Generation units needing to
cover emissions above their allocations can buy allowances from sources that
have excess allowances. Similarly, to reduce emissions of NOx, which contribute
to the formation of smog, northeastern states and the District of Columbia have
set a cap on total emissions of NOx from affected units, and allocated NOx
allowances (with each allowance authorizing the emission of one ton of NOx) to
those units. The cap applies from May through September, a period commonly
referred to as the "ozone season." The NOx allowances and SO2 allowances can be
bought and sold through regional trading programs. In 2003, the cap will be
reduced to limit NOx emissions further.

         In 1998, EPA issued regulations (commonly known as the SIP Call)
requiring the 22 states in the eastern half of the United States to make
significant NOx emission reductions by 2003 and to subsequently cap these
emissions. In January 2000, the EPA adopted a revised rule granting petitions
filed by certain northeastern states under Section 126 of the CAA. The petitions
sought significant reductions in nitrogen oxide emissions from utility and
industrial sources. The rule imposes emission reduction requirements comparable
to the NOx SIP Call Rule. The EPA has delayed the implementation of the SIP Call
and the Section 126 Rule until May 31, 2004. The NOx reduction requirements of
the SIP Call and the Section 126 rule are consistent with requirements already
in place in New Jersey, New York and Pennsylvania and therefore are not likely
to have an additional impact on or change the capacity available from our
existing facilities. New facilities that we are developing in Ohio and Indiana
will be subject to rules that those states are expected to promulgate to comply
with the SIP Call.

         To comply with the SO2 and NOx requirements, affected units may choose
one or more strategies, including installing air pollution control technologies,
changing or limiting operations, changing fuels or obtaining additional
allowances. At this time, we do not expect to incur material expenditures to
continue complying with the SO2 program. We also do not expect that the
potential costs for purchasing additional NOx allowances will be material
through December 31, 2002. In 2003, when the NOx cap is reduced in New Jersey,
New York, Pennsylvania, and other northeastern states, the cost of complying
with the NOx program in those states may increase significantly. Whether the
cost will increase or decrease will depend upon whether we will be a net
purchaser of NOx allowances. The extent of any increase or decrease will depend
upon a number of factors that may increase or decrease total NOx emissions from
affected units, thus increasing or decreasing demand for a fixed supply of
allowances. We have been implementing measures to reduce NOx emissions at
several of our units, which should reduce the cost of purchasing allowances.

         In December 1999, the EPA proposed to approve plans by several states
(including New Jersey and certain other Northern states) to attain the ozone
National Ambient Air Quality Standards. That approval is contingent on these
states implementing new programs to further reduce emissions of smog-forming
chemicals (including NOx). The affected northeastern states have committed to
make these reductions, and were required to have selected measures by October 1,
2001 to achieve the reductions. Measures selected by the states are currently
under EPA review. Measures under consideration may increase demand for NOx
allowances and, consequently, increase their prices.

         In 1997, EPA adopted a new air quality standard for fine particulate
matter, and a revised air quality standard for ozone. To attain the fine
particulate matter standard, states may require further reductions in NOx and
SO2. However, under


                                       14
<PAGE>

the time schedule announced by EPA when the new standard was adopted,
non-attainment areas will not be designated until 2002 and control measures to
meet this standard will not be identified until 2005. Additionally, similar NOx
and SO2 reductions may be required to satisfy requirements of an EPA rule
protecting visibility in many of the nation's scenic areas, including some areas
near our facilities. States or the federal government may require additional
reductions in NOx emissions from electric generating facilities as part of an
effort to achieve the revised ozone standard.

         OTHER AIR POLLUTANTS

         The CAA directed EPA to study potential public health impacts of
hazardous air pollutants (HAPs) emitted from electric utility steam generating
units. In December 2000, EPA announced its intent to regulate HAP emissions from
coal-fired and oil-fired steam units, concluding that these emissions pose
significant hazards to public health. EPA plans to develop "Maximum Achievable
Control Technology" (MACT) standards for these units. EPA plans to propose the
MACT standards by December 2003 and promulgate a final rule by December 2004,
with compliance to be required by December 2007

         In December 1997, delegates from the U.S. and 166 other nations agreed
to a treaty known as the Kyoto Protocol. If the U.S. were to ratify the treaty,
it would be bound to reduce emissions of CO2 and certain other "greenhouse
gases" by 7% below 1990 levels. However, in March 2001, President Bush announced
that the U.S. would not ratify the treaty. On January 11, 2002, we announced a
voluntary agreement that calls for a goal of reducing by December 31, 2005 the
annual average carbon dioxide emission rate of its fossil fuel fired electric
generating units by 15% below the 1990 average annual carbon dioxide emission
rate of our New Jersey fossil fuel fired electric generating units. We also have
agreed to make a $1.5 million grant to the NJDEP to assist in the development of
landfill gas projects, and to make an additional grant equal to $1 per ton of
SO2 emitted greater than the 15% goal, up to $1.5 million, if that reduction is
not achieved.

WATER POLLUTION CONTROL

         The Federal Water Pollution Control Act (FWPCA) prohibits the discharge
of pollutants to waters of the United States from point sources, except pursuant
to a National Pollutant Discharge Elimination System (NPDES) permit issued by
EPA or by a state under a federally authorized state program. The FWPCA
authorizes the imposition of technology-based and water quality-based effluent
limits to regulate the discharge of pollutants into surface waters and ground
waters. EPA has delegated authority to a number of state agencies, including the
NJDEP, to administer the NPDES program through state acts. The New Jersey Water
Pollution Control Act (NJWPCA) authorizes the NJDEP to implement regulations and
to administer the NPDES program with EPA oversight, and to issue and enforce New
Jersey Pollutant Discharge Elimination System (NJPDES) permits. We also have
ownership interest in facilities in other states that have their own laws and
implementing regulations to regulate discharges to their surface waters and
ground waters through such permits. Such permits directly regulate our
facilities in these jurisdictions.

         The EPA is conducting a rulemaking under FWPCA Section 316(b), which
requires that cooling water intake structures reflect the best technology
available (BTA) for minimizing "adverse environmental impact". Phase I of the
rule became effective on January 17, 2002. None of the projects that we
currently have under construction or in development is subject to the Phase I
rule.

         The EPA is scheduled to propose draft Phase II rules covering large
existing power plants on February 28, 2002, and issue final rules on August 28,
2003. The content of the final Phase II rules cannot be predicted at this time,
although it is reasonable to expect that the rule will apply to all of our steam
electric and combined cycle units that use surface waters for cooling purposes.
If the Phase II rules require retrofitting of cooling water intake structures at
our existing facilities, the cost of complying with the rules would be material
and could require certain of the facilities to be closed.

         On June 29, 2001, the NJDEP issued a renewal permit (the 2001 Permit)
for Salem, with an effective date of August 1, 2001, allowing for the continued
operation of Salem with its existing cooling water system. This 2001 Permit
renews Salem's variance from applicable thermal water quality standards under
Section 316(a) of the FWPCA, determines that the existing intake structure
represents best technology available under Section 316(b) of the FWPCA, requires
that we continue to implement the wetlands restoration and fish ladder programs
established under the 1994 NJPDES Permit issued for Salem, and imposes
requirements for additional analyses of data and studies to determine if other
intake technologies are available for application at Salem that are biologically
effective. The 2001 Permit also requires us to install up to two additional fish
ladders in New Jersey and fund a $500,000 escrow account for the construction of
artificial reefs by NJDEP. The 2001 Permit expires on July 31, 2006.


                                       15
<PAGE>

         We have also reached a settlement with the Delaware Department of
Natural Resources and Environmental Control (DNREC) providing that we will fund
additional habitat restoration and enhancement activities as well as fisheries
monitoring and that we and DNREC will work cooperatively on the finalization of
other regulatory approvals required for implementation of the 2001 Permit. As
part of this agreement, we deposited approximately $5.8 million into an escrow
account to be used for future costs related to this settlement.

         In 1970, the Delaware River Basin Commission (the DRBC) had issued a
Docket for Salem (1970 Docket) that approved the construction and operation of
the station's cooling water system. In 1995, the DRBC had issued a Revised
Docket for Salem (1995 Revised Docket) that amended the Heat Dissipation Area
(HDA) established in the 1970 Docket, and approved the continued operation of
the station's cooling water system. At its meeting on September 13, 2001, the
DRBC unanimously approved our request for revisions to the 1995 Revised Docket.
These revisions provide for an HDA consistent with the hydrothermal modeling
studies conducted in connection with the renewal application for Salem's NJPDES
permit, incorporate by reference the terms and conditions of the 2001 Permit,
rescind the 1995 Revised Docket, and establishes a twenty-five year term for the
Docket. The newly revised Docket again includes a re-opener clause that allows
the DRBC to re-consider the terms and conditions of the Docket, based upon
changed circumstances.

         Capital costs of complying with water pollution control requirements
through 2004 are included in our estimate of construction expenditures in MD&A.

HUDSON AND MERCER GENERATING STATIONS

         The NJDEP is in the process of reviewing the NJPDES permit renewal
application for our Hudson Station. As part of that renewal, the NJDEP has
requested updated information, in part to address issues identified by a
consultant hired by it. The consultant recommended that Hudson Station be
retrofitted to operate with closed cycle cooling to address alleged adverse
impacts associated with the thermal discharge and intake structure. We proposed
certain modifications to the intake structure and submitted these demonstrations
to the NJDEP in the fourth quarter of 1998. While we believe 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.

         NJDEP has advised us that it is reviewing a NJPDES permit renewal
application for Mercer Station, and in connection with that renewal, will be
reexamining the effects of Mercer Station's cooling water system pursuant to
FWPCA. We have submitted updated demonstrations to the NJDEP.

         It is impossible to predict the timing and/or outcome of the review of
these applications in respect of the Hudson and Mercer Generation Stations. An
unfavorable outcome could have a material adverse effect on our financial
position, results of operations and net cash flows. We believe that the current
operations of our stations are in compliance with FWPCA and will vigorously
prosecute our applications to continue operations of our generating stations
with present cooling water intake structures.

HAZARDOUS SUBSTANCES

         Generators of hazardous substances potentially face joint and several
liability, without regard to fault, when they fail to manage these materials
properly and when they are required to clean up property affected by the
production and discharge of such substances. Certain federal and state laws
authorize the EPA and the NJDEP, among other agencies, to issue orders and bring
enforcement actions to compel responsible parties to investigate and take
remedial actions at any site that is determined to present an actual or
potential threat to human health or the environment because of an actual or
threatened release of one or more hazardous substances. Because of the nature of
our business, various by-products and substances are or were produced or handled
which contain constituents classified as hazardous by federal and state
agencies. For a discussion of these hazardous substance issues and a discussion
of potential liability for remedial action regarding the Passaic River,, see
Note 5. - Commitments and Contingent Liabilities. For a discussion of our
remediation/clean-up actions, see Item 3 - Legal Proceedings.

         Other liabilities associated with environmental remediation include
natural resource damages. The 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


                                       16
<PAGE>

have discharged a hazardous substance, which discharge resulted in an "injury"
to natural resources. Until recently, the state trustee in New Jersey, NJDEP,
has not aggressively pursued natural resource damages. In 1997, the NJDEP
adopted changes to the technical requirements for site remediation pursuant to
the Spill Act. Among these changes was a new provision requiring all persons
conducting remediation to characterize "injuries" to natural resources.
Furthermore, these changes required persons to address those injuries through
restoration or damages. The New Jersey program is still developing and we cannot
assess the magnitude of the potential impact of this regulatory change. Although
currently not estimable, costs associated with these requirements could be
material.

         A preliminary review of possible mercury contamination at the Kearny
Station concluded that an additional study and investigations are required. A
Remedial Investigation (RI) was conducted and a report was submitted to the
NJDEP in September 1997 and is currently under its technical review. As
currently issued, the RI Report found that the mercury at the site is stable and
immobile and should be addressed at the time the Kearny Station is retired.

         The EPA has determined that a six mile stretch of the Passaic River in
the area of Newark, New Jersey is a facility within the meaning of that term
under the CERCLA and that, to date, at least thirteen corporations, including
us, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the Passaic River facility. Our
Essex Station is within the Passaic River "facility". We cannot predict what
action, if any, the EPA or any third party may take against it with respect to
these matters, or in such event, what costs we may incur to address any such
claims. However, such costs may be material.

NUCLEAR FUEL DISPOSAL

         After spent fuel is removed from a nuclear reactor, it is placed in
temporary storage for cooling in a spent fuel pool at the nuclear station site.
Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal
government has entered into contracts with the operators of nuclear power plants
for transportation and ultimate disposal of the spent fuel. To pay for this
service, the nuclear plant operators were required to contribute to a Nuclear
Waste Fund at a rate of one mil per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal
government. These costs are being recovered through the BGS contract through
July 2002. In addition, a one-time payment was made to the DOE for permanently
discharged spent fuels irradiated prior to 1983. Payments made to the United
States Department of Energy (DOE) for disposal costs are based on nuclear
generation and are included in Energy Costs in the Consolidated Statements of
Income.

         Under the NWPA, the DOE was required to begin taking possession of all
spent nuclear fuel generated by our nuclear units for disposal by no later than
1998. DOE construction of a permanent disposal facility has not begun and DOE
has announced that it does not expect a facility to be available earlier than
2010. Exelon has advised us that it had signed an agreement with the DOE
applicable to Peach Bottom under which Exelon would be reimbursed for costs
resulting from the DOE's delay in accepting spent nuclear fuel. The agreement
allows Exelon to reduce the charges paid to the Nuclear Waste Fund to reflect
costs reasonably incurred due to the DOE's delay. Past and future expenditures
associated with Peach Bottom's recently completed on-site dry storage facility
would be eligible for this reduction in future DOE fees. In 2000, a group of
eight utilities filed a petition against DOE in the Eleventh Circuit U.S. Court
of Appeals seeking to set aside the receipt of credits out of the Nuclear Waste
Fund, as stipulated in the Peach Bottom agreement. On September 26, 2001 Nuclear
filed a complaint in the U. S. Court of Federal Claims seeking damages caused by
the DOE not taking possession of spent nuclear fuel in 1998. No assurances can
be given as to any damage recovery or the ultimate availability of a disposal
facility. In February 2002, President Bush announced that Yucca Mountain in
Nevada would be the permanent disposal facility for nuclear wastes. The states
have thirty days to object, and, if objections are raised, the issue will be
determined by the U.S. Congress. No assurances can be given regarding the final
outcome of this matter.

         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. We presently expect 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 us 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.
In July 2001 an application was submitted to the NRC to renew the operating
licenses for Peach Bottom Units 2 and 3.


                                       17
<PAGE>

If approved, the current licenses would be extended by 20 years, to 2033 and
2034 for Units 2 and 3 respectively. NRC review of the application is expected
to take approximately two years.

         In October 2001, we filed a complaint in the United States Court of
Federal Claims, along with a number of other plaintiffs, seeking $28.2 million
in relief from past overcharges by the DOE for enrichment services. No
assurances can be given as to any claimed damage recovery.

         LOW LEVEL RADIOACTIVE WASTE (LLRW)

         As a by-product of their operations, nuclear generation units produce
LLRW. Such wastes include paper, plastics, protective clothing, water
purification materials and other materials. LLRW materials are accumulated on
site and disposed of at licensed permanent disposal facilities. In July 2000,
New Jersey, Connecticut and South Carolina formed the Atlantic Compact, an
arrangement that gives New Jersey nuclear generators, including us, continued
access to the Barnwell LLRW disposal facility, which is owned by South Carolina.
We believe 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 we and Exelon have on-site LLRW storage facilities
for Peach Bottom, Salem and Hope Creek, which have the capacity for at least
five years of temporary storage for each facility.

         URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND

         In accordance with the EPAct, domestic entities that own nuclear
generating stations are required to pay into a decontamination and
decommissioning fund, based on their past purchases of U.S. government
enrichment services. As a result of our acquisition of Conectiv's interest in
Salem, Hope Creek and Peach Bottom, we also acquired its decontamination and
decommissioning fund obligation for $7 million (adjusted for inflation). In
2001, $1 million was paid, resulting in a balance due of $6 million. We believe
that we should not be subject to collection of any such fund payments under
EPAct. Along with other nuclear generator owners, we have filed suit in the U.S.
Court of Claims and in the U.S. District Court, Southern District of New York to
recover these costs.




                                       18
<PAGE>


ITEM 2. PROPERTIES

         We own or lease several other properties associated with our business
activities. We sublease approximately 148,000 square feet of office space in an
office tower and other office facilities in Newark, New Jersey. Other leased
properties include an emergency media center (9,300 square feet) near Salem,
which is designed as an information clearinghouse in the event of a nuclear
emergency. We also lease approximately 19,600 square feet of space in the Hadley
Road Training Center in South Plainfield, New Jersey from PSE&G. This space is
used for fossil system maintenance, procurement and materials management staffs.

         Through a subsidiary, we own a 57.41% interest in about 12,000 acres of
restored wetlands and conservation facilities in the Delaware Estuary. This
subsidiary was formed to acquire and own lands and other conservation facilities
required to satisfy the condition of the NJPDES permit issued for the Salem
Generating Station. We also own several other facilities including the on-site
Nuclear Administration and Processing Center buildings.

         We have an ownership interest in the 650-acre Merrill Creek Reservoir
(Merrill Creek) in Warren County, New Jersey. The reservoir was constructed to
store water for release to the Delaware River during periods of low flow.
Merrill Creek is jointly owned by seven entities that have generation facilities
along the Delaware River and use the river water in their operations. We also
own the Maplewood Test Center in Maplewood, New Jersey and the Central
Maintenance Shop at Sewaren, New Jersey.

INSURANCE

         We carry insurance coverage consistent with companies engaged in
similar commercial operation with similar properties. Our insurance coverage
includes risk insurance as well as commercial general public liability
insurance, covering liabilities to third parties for bodily injury and property
damage resulting from our operations; automobile liability insurance, for all
owned, non-owned and hired vehicles, covering liabilities to third parties for
bodily injury and property damage, and all risk property insurance, covering the
replacement value of all real and personal property, including coverage for
boiler and machinery breakdowns and earthquake and flood damage, subject to
certain sublimits. We also maintain substantial excess liability insurance
coverage above the established primary limits for commercial general liability
and automobile liability insurance. Limits and deductibles are comparable to
those carried by other electric generation companies of similar size. For a
discussion of liability and other insurance related to our nuclear generation
facilities, see Risk Factors and Note 5. - Commitments and Contingent
Liabilities.




                                       19
<PAGE>


         The following table provides summary profiles of our fossil and nuclear
generation stations and the units that comprise them:

<TABLE>
<CAPTION>
                                                                 TOTAL            OWNED         PRINCIPAL
                                                                CAPACITY         CAPACITY         FUELS
NAME AND LOCATION                                                 (MW)             (MW)            USED             MISSION
-----------------------------------------------------------    ----------       ----------    ------------     ----------------
<S>                                                            <C>              <C>           <C>              <C>
Steam:
     Hudson, Jersey City, NJ...............................          991             991       Coal/Gas         Load Following
     Mercer, Hamilton, NJ..................................          648             648       Coal/Gas         Load Following
     Sewaren, Woodbridge Twp., NJ..........................          453             453       Gas/Oil          Load Following
     Linden, Linden, NJ (F)................................          430             430       Oil              Load Following
     Keystone, Shelocta, PA--22.84%(A)(B)..................        1,700             388       Coal             Base Load
     Conemaugh, New Florence, PA--22.50%(A)(B).............        1,700             382       Coal             Base Load
     Kearny, Kearny, NJ....................................          300             300       Oil              Load Following
     Albany, Albany, NY (F)................................          380             380       Oil              Load Following
                                                               ----------       ----------
        Total Steam...........................                     6,602           3,972
                                                               ----------       ----------
Nuclear: (Capacity calculated in accordance with industry
         maximum dependable capability standards)
     Hope Creek, Lower Alloways Creek, NJ 100%.............        1,049           1,049       Nuclear          Base Load
     Salem 1 & 2, Lower Alloways Creek, NJ 57.41%(A).......        2,188           1,275       Nuclear          Base Load
     Peach Bottom 2 & 3, Peach Bottom, PA 50%(A)(C)........        2,186           1,094       Nuclear          Base Load
                                                               ----------       ----------
        Total Nuclear......................................        5,423           3,418
                                                               ----------       ----------
Combined Cycle:
     Bergen, Ridgefield, NJ................................          675             675       Gas              Load Following
     Burlington, Burlington, NJ............................          245             245       Gas              Load Following
                                                               ----------       ----------
        Total Combined Cycle...............................          920             920
                                                               ----------       ----------
Combustion Turbine:
     Essex, Newark, NJ.....................................          617             617       Gas/Oil          Peaking
     Edison, Edison Township, NJ...........................          504             504       Gas/Oil          Peaking
     Kearny, Kearny, NJ (F)................................          443             443       Gas/Oil          Peaking
     Burlington, Burlington, NJ............................          561             557       Oil              Peaking
     Linden, Linden, NJ....................................          316             316       Gas/Oil          Peaking
     Hudson, Jersey City, NJ...............................          129             129       Oil              Peaking
     Mercer, Hamilton, NJ..................................          129             129       Oil              Peaking
     Sewaren, Woodbridge Township, NJ......................          129             129       Oil              Peaking
     Bayonne, Bayonne, NJ..................................           42              42       Oil              Peaking
     Bergen, Ridgefield, NJ................................           21              21       Gas              Peaking
     National Park, National Park, NJ......................           21              21       Oil              Peaking
     Kearny, Kearny, NJ....................................           21              21       Gas              Peaking
     Linden, Linden, NJ....................................           21              21       Gas/Oil          Peaking
     Salem, Lower Alloways Creek, NJ 50%(A)................           38              22       Oil              Peaking
                                                               ----------       ----------
        Total Combustion Turbine...........................        2,992           2,972
                                                               ----------       ----------
Internal Combustion:
     Conemaugh, New Florence, PA--22.50%(A)(B).............           11               2       Oil              Peaking
     Keystone, Shelocta, PA--22.84%(A)(B)..................           11               3       Oil              Peaking
                                                               ----------       ----------
        Total Internal Combustion..........................           22               5
                                                               ----------       ----------
Pumped Storage:
     Yards Creek, Blairstown, NJ--50%(A)(D)(E)......                 400             200                       Peaking
                                                               ----------       ----------
        Total Operating Generation Plants..................       16,359          11,487
                                                               ==========       ==========
</TABLE>


(A)      Our share of jointly owned facility.

(B)      Operated by Reliant Energy

(C)      Operated by Exelon

(D)      Operated by Jersey Central Power & Light

(E)      Excludes energy for pumping and synchronous condensers.

(F)      These assets are scheduled for retirement within the next five years,
         partially dependent upon new generation going into service discussed
         below.



                                       20
<PAGE>


         As of December 31, 2001, we had 3,764 MW of generating capacity in
construction, as shown in the following table:

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------
                                      POWER PLANTS IN CONSTRUCTION OR ADVANCED DEVELOPMENT
---------------------------------------------------------------------------------------------------------------------------
                                                    AS OF DECEMBER 31, 2001
                                                             TOTAL         PRINCIPAL                            EXPECTED
                                                            CAPACITY         FUELS                             IN SERVICE
NAME AND LOCATION                                             (MW)            USED           MISSIONS             DATE
----------------------------------------------------      ------------   -------------   ----------------  ----------------
<S>                                                       <C>            <C>             <C>               <C>
Single Cycle:
     Waterford (Phase I), Ohio......................             500          Gas         Load Following       June 2002
Combined Cycle:
     Bergen, Ridgefield, NJ.........................             546          Gas         Load Following       June 2002
     Lawrenceburg, Indiana..........................           1,150          Gas         Load Following        May 2003
     Waterford (Phase II), Ohio.....................             350          Gas         Load Following        May 2003
     Linden, Linden, NJ.............................           1,218          Gas         Load Following       June 2003
                                                          ------------
        Total Construction..........................           3,764
                                                          ============
</TABLE>

     As of December 31, 2001, we had 900 MW of generating capacity in advanced
development, as shown in the following table:

<TABLE>
<CAPTION>
                                                            TOTAL        PRINCIPAL
                                                           CAPACITY        FUELS                              EXPECTED
NAME AND LOCATION                                            (MW)          USED             MISSIONS       IN SERVICE DATE
-----------------------------------------------------     ----------   -------------     --------------    ---------------
<S>                                                       <C>          <C>               <C>               <C>
Combined Cycle:
     Bethlehem, NY...................................          750        Gas/Oil        Load Following       June 2004
Nuclear Uprates......................................          150        Nuclear           Base Load          Various
                                                          ---------
        Total Advanced Development...................          900
                                                          =========
</TABLE>


                                                         TOTAL CAPACITY
PROJECTED CAPACITY                                            (MW)
-------------------------------------------              --------------
Total Owned Operating Generating Plants                        11,487
-------------------------------------------
Under Construction                                              3,764
Advanced Development                                              900
Less: Planned Retirements                                      (1,253)
                                                         --------------
Projected Capacity                                             14,898
                                                         ==============


ITEM 3.  LEGAL PROCEEDINGS

         See information on the following proceedings at the pages indicated:

(1)      Pages 9 and 47. 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)      Pages 15 and 16. Administrative proceedings before the NJDEP under the
         FWPCA for certain electric generating stations.

(3)      Page 18. DOE Overcharges, Docket No. 01-592C.

(4)      Pages 17 and 18. DOE not taking possession of spent nuclear fuel,
         Docket No. 01-551C.

(5)      Pages 17 and 52. Investigation and additional investigation by the EPA
         regarding the Passaic River site, Docket No. EX93060255.



                                       21
<PAGE>

         We are involved in the following environmental related matters
involving governmental authorities. Based on current information, we do not
expect expenditures for any such site, individually or all such current sites in
the aggregate, to have a material effect on their financial condition, results
of operations and net cash flows.

         (1) Claim made in 1985 by U.S. Department of the Interior under CERCLA
             with respect to the Pennsylvania Avenue and Fountain Avenue
             municipal landfills in Brooklyn, New York, for damages to natural
             resources. The U.S. Government alleges damages of approximately
             $200 million. To our 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 us as a PRP and issued its own directive
             dated October 21, 1987. Remediation is currently ongoing.

         (3) Various Spill Act directives were issued by NJDEP to PRPs,
             including us 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) In 1991, the NJDEP issued Directive and Notice to Insurers Number
             Two (Directive Two) to 24 Insurers and 52 Respondents, including
             PSE&G, in connection with an investigation and remediation of the
             Global Landfill Site in Old Bridge Township, Middlesex County, New
             Jersey seeking recovery of past and anticipated future NJDEP
             response costs ($37 million). We and other participating PRPs have
             agreed with NJDEP to a partial settlement of such costs and to
             perform the remedial design and remedial action. In 1996, 13 of the
             Directive Two Respondents, including PSE&G, filed a contribution
             action pursuant to CERCLA and the Spill Act against approximately
             190 parties seeking contribution for an equitable share of all
             liability for response costs incurred and to be incurred in
             connection with the site. In September 1997, the NJDEP issued a
             Superfund record of decision with estimated cost of $3.7 million.
             The Directive Two Respondents' foregoing contribution claims have
             been resolved by settlement.

         (5) 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 our requiring
             performance of various remedial actions. Our nexus to the site is
             based upon the shipment of certain waste oils to the site for
             recycling. We 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.

         (6) The New York State Department of Environmental Conservation
             (NYSDEC) has named PSE&G as one of many potentially responsible
             parties for contamination existing at the former Quanta Resources
             Site in Long Island City, New York. Waste oil storage, processing,
             management and disposal activities were conducted at the site from
             approximately 1960 to 1981. It is believed that waste oil from our
             facilities 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 are negotiating with NYSDEC the terms of an agreement
             that will set forth these requirements, and are negotiating among
             themselves an agreement for the sharing of the associated costs.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         Omitted pursuant to conditions set forth in General Instruction I of
Form 10-K.



                                       22
<PAGE>


                                     PART II
                                     -------

ITEM 5. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND
        RELATED STOCKHOLDER MATTERS

         All of our outstanding limited liability company membership interests
are owned by PSEG.

ITEM 6. SELECTED FINANCIAL DATA

         The following table sets forth our summary selected historical
consolidated financial data. The historical consolidated financial data as of
December 31, 2001 and 2000 and for the three years ended December 31, 2001 have
been derived from our audited financial statements included herein. The
historical consolidated financial data as of December 31, 1999, 1998 and 1997
and for the two years ended December 1998, has been derived from audited
financial statements not included herein. The information set forth below should
be read in conjunction with Management's Discussion and Analysis of Financial
Condition and Results of Operations (MD&A) and the Consolidated Financial
Statements and accompanying Notes to Consolidated Financial Statements. Data
related to periods prior to August 2000 have been derived from PSE&G's financial
statements and are not necessarily indicative of the financial condition,
results of operations or net cash flows that would have existed had PSE&G's
generation-related business been an independent company during those periods.

<TABLE>
<CAPTION>
                                                                  FOR THE YEARS ENDED DECEMBER 31,
                                                -----------------------------------------------------------------
                                                   2001         2000           1999         1998          1997
                                                ----------   -----------    ----------   -----------   ----------
INCOME STATEMENT DATA                                                 (MILLIONS OF DOLLARS)
---------------------
<S>                                             <C>          <C>           <C>           <C>          <C>
Operating Revenues..........................       $4,714       $4,927        $4,494        $4,428       $2,822
Operating Expenses..........................        3,927        4,215         3,563         3,794        2,195
Operating Income ...........................          787          712           931           634          627
Interest Expense............................          143          198           112           216          223
Income Taxes................................          250          208           291           156          101
Income before Extraordinary Item............          394          313           516           237          195
Extraordinary Item (1)......................           --           --       (3,204)            --           --
Net Income (Loss)...........................          394          313       (2,688)           237          195
Earnings (Loss) Available to PSEG...........         $394         $313      $(2,691)          $232         $186
</TABLE>

<TABLE>
<CAPTION>
                                                                         AS OF DECEMBER 31,
                                                -----------------------------------------------------------------
                                                   2001         2000           1999         1998          1997
                                                ----------   -----------    ----------   -----------   ----------
BALANCE SHEET DATA                                                    (MILLIONS OF DOLLARS)
------------------
<S>                                             <C>          <C>           <C>           <C>          <C>
Assets......................................       $5,634       $4,530        $3,301        $8,045       $8,183
Current Liabilities.........................        1,015        1,470         1,038           762          984
Noncurrent Liabilities......................        1,074        1,006           991         2,096        2,075
Capitalization  (2).........................        3,545        2,054         1,272         5,187        5,124
</TABLE>

<TABLE>
<CAPTION>
                                                                        AS OF DECEMBER 31,
                                                -----------------------------------------------------------------
                                                   2001         2000           1999         1998          1997
                                                ----------   -----------    ----------   -----------   ----------
OTHER DATA                                                            (MILLIONS OF DOLLARS)
----------
<S>                                             <C>          <C>           <C>           <C>          <C>
EBITDA (3)..................................         $882         $855        $1,155        $1,015         $905
Capital Expenditures........................        1,462          479            92           265          166
</TABLE>


--------------------------------------------------------------------------------
(1) Primarily consisting of the write-down of our generating stations (see Note
3. Regulatory Issues and Accounting Impacts of Deregulation)
(2) Includes notes payable to an affiliated company in the year 2000.
(3) Earnings before Interest, Taxes, Depreciation and Amortization. Information
concerning EBITDA is presented here not as a measure of operating results,
rather as a measure of ability to service debt. In addition, EBITDA may not be
comparable to similarly titled measures by other companies. EBITDA should not be
construed as an alternative to operating income or cash flow from operating
activities, each as determined according to generally accepted accounting
principles. Although we are not required to meet minimum EBITDA to interest
charges tests as part of our debt covenants, we use these measures in our
financial and business planning process to provide reasonable assurance that our
forecasts will provide adequate interest coverage to maintain or improve our
target credit ratings.



                                       23
<PAGE>



ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

CORPORATE STRUCTURE

         We were formed in June 1999 to acquire, own and operate the electric
generation-related assets of PSE&G pursuant to the Final Order issued by the BPU
under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the
New Jersey Electric Discount and Energy Competition Act (Energy Competition
Act). We have three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC
(Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T)
and currently operate in two reportable segments, generation and trading. The
generation segment of our business earns revenues by selling energy on a
wholesale basis under contract to power marketers and to load serving entities,
and by bidding energy, capacity and ancillary services into the market. The
energy trading segment of our business earns revenues by trading energy,
capacity, fixed transmission rights, fuel and emission allowances in the spot,
forward and futures markets. The trading segment also earns revenues through
financial transactions, including swaps, options and futures in the electricity
and gas markets. We also have a finance company subsidiary, PSEG Power Capital
Investment Co. (Power Capital), which provides certain financing for our other
subsidiaries.

OVERVIEW OF 2001 AND FUTURE OUTLOOK

         We currently operate as an independent power generation and wholesale
marketing and trading company in the eastern United States. As of December 31,
2001, we own 11,487 MW of generation capacity. We are currently constructing
projects which will increase capacity by over 3,500 MW, net of planned
retirements. We derive our revenue and cash flows principally from our electric
generation business, energy trading and related activities.

         The regulatory structure that has historically governed the electric
power industry in the United States and in many of the states is in transition.
Recent federal and state legislative and regulatory initiatives have been
designed to promote competition in the electric power industry. Deregulation is
underway throughout the United States and is at a relatively advanced stage in
the Northeast, where most of the markets in which we compete are located. The
resulting restructuring of energy markets provides us with new opportunities and
exposes us to new risks.

         In August 1999, following the enactment of the New Jersey Electric
Discount and Energy Competition Act, the BPU rendered its Final Order relating
to PSE&G's rate unbundling, stranded costs and restructuring proceedings
providing, among other things, for the transfer to us of all of PSE&G's electric
generation facilities, plant and equipment for $2.443 billion and all other
related property, including materials, supplies and fuel at the net book value
thereof, together with associated rights and liabilities. PSE&G transferred its
electric generating business to us in August 2000 in exchange for a $2.786
billion promissory note, which we repaid on January 31, 2001.

         Prior to the issuance of the Final Order, substantially all of the
output of PSE&G's electric generation assets was sold to PSE&G's retail
customers. To ensure that PSE&G's retail customers who choose not to select or
who are not otherwise served by a different supplier continue to receive energy
services, the Final Order also requires PSE&G to provide Basic Generation
Service (BGS) to its customers through July 31, 2002. PSE&G has entered into a
contract with us to supply the energy, capacity and ancillary services required
to meet this obligation. As a result, since August 1, 1999, we have been selling
substantially all of our output to PSE&G and will continue to do so until July
31, 2002. We currently sell approximately 95% of the output from our generation
facilities under bilateral contracts, primarily the BGS contract with PSE&G, and
the remaining 5% to customers in the competitive wholesale (spot) market. Within
the spot market, we sell into the energy, capacity and ancillary services
markets. Ancillary services include operating reserves and area regulation. We
have entered into one-year contracts commencing August 1, 2002 with various
direct bidders in the New Jersey BGS Auction, which was approved by the BPU on
February 15, 2002. We believe that our obligations under these contracts are
reasonably balanced by our available supply.

         Under the BGS contract, we charge the BGS retail tariff rate on file
with the BPU. In addition, PSE&G pays us a price stability charge to compensate
us for ensuring the reliability of BGS service and assuming the risk of price
volatility. The price stability charge is equal to the full amount collected by
PSE&G for its unsecuritized generation-related stranded costs up to $540 million
after tax on a net present value basis. The Final Order also provides that rate
reductions of up to 13.9% be phased in by PSE&G to its retail customers through
August 1, 2002. To date, 9% of rate reductions have been phased in and
additional 4.9% will be phased in beginning August 10, 2002. These rate
reductions are reflected in the Market Transition Charge (MTC) rate that PSE&G
remits to us as part of the BGS contract as provided for by the Final Order.



                                       24
<PAGE>

         On January 9, 2002, the BPU approved the transfer of PSE&G's gas supply
business, including its transportation and storage contracts to us. As a result,
after April 1, 2002, we will provide gas supply to PSE&G to serve its Basic Gas
Supply Service (BGSS) customers under a Requirements Contract at market prices.

         We are focused on a generation market extending from Maine to the
Carolinas and the Atlantic Coast to Indiana (Super Region). The risks of our
business are that the competitive wholesale power prices that we are able to
obtain are sufficient to provide a profit and sustain the value of its assets.
It is also subject to credit risk of the counterparties to whom we sell energy
products, the successful operation of our generating facilities, fluctuations in
market prices of energy and imbalances between obligations and available supply.
These risks are higher than those for a regulated business. Therefore, they
provide the opportunity for greater returns, but they also present the greater
possibility of business losses and counterparty credit risk.

         In addition, we anticipate that we will continue our strong growth in
our energy trading segment. In 2001, the energy trading business realized a
gross margin of $140 million and forecasts an improvement for 2002, driven in
part by the transfer of PSE&G's gas supply business to us, discussed below. We
marked to market energy trading contracts with gains and losses included in
earnings. The vast majority of these contracts have terms of less than one year
and are valued using market exchange prices and broker quotes. The energy
trading business provides the opportunity for greater returns and can be
adversely impacted by fluctuating energy market prices and by the credit quality
of the counterparties with which it does business. Our trading business utilizes
a conservative risk management strategy to minimize exposure to long-term and
short-term market risk. For further information, see Accounting Issues, Note 1.
Organization and Summary of Significant Accounting Policies and Note 4.
Financial Instruments, Energy Trading and Risk Management.

         Our earnings are exposed to the risks of the competitive wholesale
electricity market to the extent that we have to purchase energy and/or capacity
or generate energy to meet our fixed price obligations at market prices or
costs, respectively, which approach or exceed the stated rates in their
long-term supply contracts, such as the BGS contract. To mitigate this risk, our
policy is to use derivatives, consistent with our business plans and prudent
practices and to build and purchase additional capacity in the PJM and
surrounding regions.

RESULTS OF OPERATIONS

         Our business consists of two reportable segments which are Generation
and Energy Trading. The following is a discussion of the major year-to-year
financial statement variances and follows the financial statement presentation
as it relates to each of our segments. For a discussion of management's
determination of our reportable segments and related disclosures, see Note 9.
Financial Reporting by Business Segments. For a discussion of these assumptions
and the methodologies used to prepare our financial statements prior to August
2001, see Note 1. - Organization, Basis of Presentation and Summary of
Significant Accounting Policies

         Prior to April 1999, the discussion that follows reports on business
conducted under full monopoly regulation of the utility businesses. It must be
understood that such businesses have changed due to the deregulation of the
electric generation and natural gas commodity sales businesses, the subsequent
transfer of the generation business, and the anticipated transfer of the gas
supply business from PSE&G to us. Past results are not an indication of future
business prospects or financial results.

                                       25
<PAGE>

RESULTS OF OPERATIONS -- FOR THE YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE
YEAR ENDED DECEMBER 31, 2000

         Our earnings for the year ended December 31, 2001 increased $81 million
from the comparable 2000 period. This increase primarily resulted from the
effects of increased BGS sales volumes due to customers returning to PSE&G in
2001 from third party suppliers (TPS) and increased trading margins. This was
offset by lower revenues resulting from two 2% rate reductions totaling $100
million as part of PSE&G's deregulation plan and a $52 million increase in
Operation and Maintenance expense.

OPERATING REVENUES

         GENERATION

         Revenues from our generation segment increased $108 million in 2001 as
compared to 2000 primarily due to an increase of $180 million in BGS revenue for
the year ended December 31, 2001 as compared to 2000 which resulted from
customers returning to PSE&G in 2001 from TPS as wholesale market prices
exceeded fixed BGS rates. At December 31, 2001, TPS were serving less than 1% of
the customer load traditionally served by PSE&G as compared to the December 31,
2000 level of 10.5%. Partially offsetting this increase was a net $40 million
decrease in MTC revenues, relating to two 2% rate reductions offset by a pre-tax
charge to income related to MTC recovery in 2000. As of December 31, 2001, as
required by the Final Order, PSE&G has had rate reductions totaling 9% since
August 1, 1999 and will have an additional 4.9% rate reduction effective August
1, 2002, which will be in effect until July 31, 2003.

         ENERGY TRADING

         Revenues from our energy trading segment decreased by $321 million or
12% for the year ended December 31, 2001 from the comparable period in 2000, due
to lower energy trading volumes and lower prices as compared to 2000. For
information regarding valuation, term, credit and other issues related to our
energy trading segment, see Accounting Issues, Note 1. Organization and Summary
of Significant Accounting Policies and Note 4 - Financial Instruments, Energy
Trading and Risk Management.

OPERATING EXPENSES

         ENERGY COSTS

         Energy Costs increased $97 million or 13% for the year ended December
31, 2001 from the comparable period in 2000, primarily due to increased load
served under the BGS contract and higher fuel costs for fossil generation
resulting from higher natural gas prices, partially offset by increased low-cost
nuclear generation compared to 2000.

         TRADING COSTS

         Trading Costs decreased $391 million or 15% year ended December 31,
2001 from the comparable period in 2000, primarily due to lower trading volumes
and lower prices as compared to 2000.

         OPERATION AND MAINTENANCE

         Operation and Maintenance expense increased $52 million or 8% for year
ended December 31, 2001, primarily due to planned generation outage work in the
first quarter of 2001 and higher expenses relating to projects going into
operation during the second quarter of 2000 for our generation segment.

         DEPRECIATION AND AMORTIZATION

         Depreciation and Amortization expense decreased $41 million or 30% for
the year ended December 31, 2001 from the comparable period in 2000. The
decrease was primarily due to a reduction in the accrual for the estimated cost
of removal of our generating stations.

         INTEREST EXPENSE

         Interest Expense decreased $55 million or 28% for the year ended
December 31, 2001 from the comparable period in 2000 primarily due to the
repayment of the $2.786 billion 14.23% promissory note to PSE&G, issued in
August 2000,


                                       26
<PAGE>

used to finance the acquisition of PSE&G's generation business. This loan was
repaid on January 31, 2001 and was replaced on an interim basis by loans of
$1.084 billion at 14.23% and $536 million at 7.11% from PSE&G from January 2001
to April 2001. These loans were repaid with the proceeds of the $1.8 billion
Senior Notes issued in April 2001.

RESULTS OF OPERATIONS -- FOR THE YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE
YEAR ENDED DECEMBER 31, 1999

         Excluding an extraordinary charge of $3.204 billion related to the
deregulation of the energy industry, our earnings for the year ended December
31, 2000 decreased $200 million from the comparable 1999 period. This decrease
primarily resulted from the effects of the 5% rate reduction which commenced on
August 1, 1999 and a $115 million reduction in MTC revenues which resulted from
a cumulative effect of estimated collections in excess of the allowed
unsecuritized stranded costs from August 1, 1999 through December 31, 2000. Also
contributing to this decrease was higher interest expense associated with the
$2.786 billion promissory note to PSE&G.

OPERATING REVENUES

         GENERATION

         Generation revenues decreased $449 million or 17% for the year ended
December 31, 2000 from the comparable period in 1999 primarily due to the 5%
rate reduction, which decreased revenues by approximately $120 million, a $115
million deferral of MTC revenues and reduced retail demand as PSE&G lost retail
customers to TPS which resulted in an approximately $182 million decrease in
generation revenues.

         TRADING

         Trading revenues increased $882 million or 48% for the year ended
December 31, 2000 from the comparable period in 1999 primarily due to increased
trading volumes and higher trading prices. These increased revenues were largely
offset by the related increase in trading costs discussed below.

OPERATING EXPENSES

         ENERGY COSTS

         Energy Costs decreased $85 million or 10% for the year ended December
31, 2000 from the comparable 1999 period due to lower prices for power purchases
beginning in August 1999 and lower generation costs that were a result of high
capacity factors of our nuclear units. Prior to August 1999, Energy Costs
included amounts paid under various non-utility generation (NUG) contracts which
are at or above market prices. Since August 1999, PSE&G has purchased the energy
and capacity under these NUG contracts and sells the energy and capacity to us
at market prices.

         TRADING COSTS

         Trading Costs increased $847 million or 47% for the year ended December
31, 2000 from the comparable 1999 period primarily due to higher trading costs
associated with increased trading volumes and higher prices.

         DEPRECIATION AND AMORTIZATION

         Depreciation and Amortization expense decreased $88 million or 39% for
the year ended December 31, 2000 from the comparable 1999 period. The decrease
was primarily due to lower net book value balances of PSE&G's generation-related
assets that were reduced as of April 1, 1999 as a result of the impairment
recorded pursuant to SFAS 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121). For a discussion
of Depreciation policies and methods, See Note 1. Organization, Basis of
Presentation and Summary of Significant Accounting Policies and Note 2.
Accounting Matters, respectively.

         INTEREST EXPENSE

         Interest Expense increased $86 million or 77% for the year ended
December 31, 2000 from the comparable 1999 period. Prior to the generation
business transfer in August 2000, Our Interest Expense was calculated based upon
an allocation methodology that charged us with financing from PSE&G in
proportion to our share of total net property, plant and


                                       27
<PAGE>

equipment. Following the transfer of the generation business in August 2000, we
paid interest on our $2.786 billion promissory note to PSE&G at an annual rate
of 14.23%. This rate represented PSE&G's weighted average cost of capital.








                                       28
<PAGE>

         LIQUIDITY AND CAPITAL RESOURCES

         Our capital requirements and those of our subsidiaries are met and
liquidity provided by internally generated cash flow and external financings.
From time to time, we make equity contributions to our direct and indirect
subsidiaries to provide for part of their capital and cash requirements,
generally relating to long-term investments. At times, we utilize inter-company
dividends and inter-company loans to satisfy various subsidiary needs and
efficiently manage our and our subsidiaries' short-term cash needs. Any excess
funds are invested in accordance with guidelines adopted by our Board of
Directors.

         External funding to meet the majority of our requirements is comprised
of corporate finance transactions. The debt incurred is our direct obligation.
Some of the proceeds of these debt transactions are used by us to make equity
investments in our subsidiaries. External funding is also provided through PSEG
which may use proceeds of its financing transactions to make equity
contributions or loans to us.

         All of our publicly traded debt has received investment grade ratings
from each of the three major credit rating agencies. The changes in the energy
industry and the recent bankruptcy of Enron Corp. are attracting increased
attention from the rating agencies which regularly assess business and financial
matters. Given the changes in the industry, attention to and scrutiny of our
performance, capital structure and competitive strategies by rating agencies
will likely continue. These changes could affect the bond ratings, cost of
capital and market prices of our securities. We will continue to evaluate our
capital structure, financing requirements, competitive strategies and future
capital expenditures with a goal of maintaining our current credit ratings.

         The current ratings of our securities are shown below and reflect the
respective views of the rating agencies, from whom an explanation of the
significance of their ratings may be obtained. There is no assurance that these
ratings will continue for any given period of time or that they will not be
revised or withdrawn entirely by the rating agencies, if, in their respective
judgments, circumstances so warrant. Any downward revision or withdrawal may
adversely effect the market price of our securities and serve to increase our
cost of capital.

     POWER            MOODY'S            STANDARD & POOR'S           FITCH
--------------------------------------------------------------------------------
Senior Notes           Baa1                    BBB                   BBB+


         The availability and cost of external capital could be affected by our
performance as well as by the performance of PSEG and its subsidiaries and
affiliates. This could include the degree of structural or regulatory separation
between us and our subsidiaries and affiliates and the potential impact of
affiliate ratings on our credit quality. Additionally, compliance with
applicable financial covenants will depend upon future financial position and
levels of earnings and net cash flows, as to which no assurances can be given.

         Financing for two of our projects under construction in Lawrenceburg,
Indiana and Waterford, Ohio has been provided by non-recourse project financing
transactions. These consist of loans from banks and other lenders that are
secured by the project and the special purpose subsidiary assets and/or cash
flows. Non-recourse transactions generally impose no obligation on the
parent-level investor to repay any debt incurred by the project borrower.
However, in some cases, certain obligations relating to the investment being
financed, including additional equity commitments, are supported by us. Further,
the consequences of permitting a project-level default include loss of any
invested equity by the parent.

         Our debt indenture and the credit agreements of our Lawrenceburg and
Waterford subsidiaries contain cross-default provisions under which a default by
us involving specified levels of indebtedness in other agreements would result
in a default and the potential acceleration of payment under such indenture and
credit agreements. For example, a default for a specified amount with respect to
specified indebtedness, as set forth in the credit agreements, including our
obligations in subsidiaries' non-recourse transactions, could cause a
cross-default in our indenture or our subsidiaries' credit agreements.

         Such lenders, or the debt holders under our indenture, could determine
that debt payment obligations may be accelerated as a result of a cross-default.
These occurrences could severely limit our liquidity and restrict our ability to
meet our debt, capital and, in extreme cases, operational cash requirements. Any
inability to satisfy required covenants and/or borrowing conditions would have a
similar impact. This would have a material adverse effect on our financial
condition, results of operations and net cash flows, and those of our
subsidiaries.

         In addition, the credit agreements of PSEG and our Lawrenceburg and
Waterford subsidiaries generally contain provisions under which the lenders
could refuse to advance loans in the event of a material adverse change in the
borrower's, and as may be relevant, our business or financial condition. In the
event that PSEG, we or the lenders in any of these credit agreements determine
that a material adverse change has occurred, loan funds may not be advanced.

         PSEG's credit agreements also contain maximum debt to equity ratios and
other covenants and conditions to borrowing. Compliance with applicable
financial covenants will depend upon PSEG's future financial position and the
level of earnings and cash flow, as to which no assurances can be given. As part
of PSEG's financial planning forecast, it performs stress tests on its financial
covenants. These tests include a consideration of the impacts of potential asset
impairments, and other items. PSEG's current analyses and projections indicate
that PSEG will be able to meet its financial covenants.

         Our debt indenture and such credit agreements do not contain any
material "ratings triggers" that would cause an acceleration of the required
interest and principal payments in the event of a ratings downgrade. However, in
the event of a downgrade, we and PSEG may be subject to increased interest costs
on certain bank debt. Also, in connection with our energy trading business, we
must meet certain credit quality standards as are required by counterparties. If
we lose our investment grade credit rating, ER&T would have to provide credit
support (letters of credit or cash), which would significantly impact our energy
trading business. These same contracts provide reciprocal benefits to us. This
would increase our costs of doing business and limit our ability to successfully
conduct our energy trading operations. In addition, our counterparties may
require us to meet margin or other security requirements which may include cash
payments.

         In addition, if PSEG were no longer to be exempt under the Public
Utility Holding Company Act of 1935 (PUHCA), PSEG and its subsidiaries,
including us, would be subject to additional regulation by the SEC with respect
to financing and investing activities, including the amount and type of
non-utility investments. We believe that this would not have a material adverse
effect on our financial condition, results of operations and net cash flows.

         Over the next several years, we and our Lawrenceburg and Waterford
subsidiaries and PSEG will be required to refinance maturing debt, incur
additional debt and/or provide equity to fund investment activity. Any inability
to obtain required additional external capital or to extend or replace maturing
debt and/or existing agreements at current levels and reasonable interest rates
may affect our financial condition, results of operations and net cash flows.


                                       29
<PAGE>

         Our short-term financing needs will be met using PSEG's commercial
paper program or lines of credit. On September 8, 1999, PSEG entered into an
uncommitted line of credit with a bank with no stated limit. At December 31,
2001, PSEG had $153 million outstanding under this line of credit. PSEG also has
an $850 million commercial paper program to provide funds for general corporate
purposes. On December 31, 2001, $475 million of commercial paper was
outstanding. To provide liquidity for its commercial paper program, PSEG has the
following revolving credit facilities with a group of banks which provide for
borrowings with maturities of up to one year:

<TABLE>
<CAPTION>
                                                         AMOUNT       AMOUNT AVAILABLE   MATURITY DATE OF
COMPANY                           TOTAL FACILITY       OUTSTANDING                           FACILITY
---------------------------------------------------------------------------------------------------------
                                                            (MILLIONS OF DOLLARS)
PSEG
-----------------------------
<S>                               <C>                 <C>              <C>               <C>
Revolving Credit Facility             $ 570               $  -             $ 570            March 2002
Revolving Credit Facility               280                  -               280            March 2005
Revolving Credit Facility               150                125                25          December 2002
</TABLE>

         As of December 31, 2001, letters of credit were issued in the amount of
approximately $100 million.

         In April 2001, we issued $500 million of 6.875% Senior Notes due 2006,
$800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior
Notes due 2031. The net proceeds from the sale of the senior notes were used
primarily for the repayment of loans to PSEG.

         In August 2001, two of our subsidiaries closed on $800 million of
non-recourse project bank financing for projects in Waterford, Ohio and
Lawrenceburg, Indiana. The total combined project cost for Waterford and
Lawrenceburg is estimated at $1.2 billion. Our required estimated equity
investment in these projects is approximately $400 million. In connection with
these projects, ER&T has entered into a five-year tolling agreement pursuant to
which it is obligated to purchase the output of these facilities at stated
prices. As a result, ER&T will bear the price risk related to the output of
these generation facilities, which are scheduled to be completed in 2003.

         In the fourth quarter of 2001, we issued $124 million of Pollution
Control Notes.

CAPITAL REQUIREMENTS

         We have substantial commitments as part of our growth strategy and
ongoing construction programs. We expect that the majority of our capital
requirements over the next five years will come from internally generated funds,
with the balance to be provided by the issuance of debt at the subsidiary or
project level and equity contributions from PSEG.

         For the years ended December 31, 2001 and 2000, we had net plant
additions of $1.5 billion and $479 million, respectively, excluding capitalized
interest. The majority of these additions are related to developing the
Lawrenceburg, Indiana and the Waterford, Ohio sites and adding capacity to the
Bergen, Linden, Burlington and Kearny stations in New Jersey.

FORECASTED EXPENDITURES
-----------------------

         Projected construction and investment expenditures for our subsidiaries
for the next five years are as follows:


                                       30
<PAGE>

      2002             2003            2004           2005            2006
      ----             ----            ----           ----            ----
                             (Millions of Dollars)
      $ 960            $ 700          $ 340           $ 250          $ 230


         The expenditures in 2001 and future projections are primarily for
developing the Lawrenceburg, Indiana site and the Waterford, Ohio site and
increasing capacity to the Bergen, Linden, Burlington and Kearny stations in New
Jersey. Our settlement with federal and state governments for PSD/NSR
regulations required approximately $337 million of capital expenses through 2010
is also included in the forecasts. For a discussion of new generation and
development including our development of the Bethlehem Energy Center, Bergen
Generating Station, Waterford and Lawrenceburg projects and other commitments to
purchase equipment and services, all of which are included in our forecasts
above, see Note 5. Commitments and Contingent Liabilities.

         Our capital needs will be dictated by our strategy to continue to
develop as a profitable, growth-oriented supplier in the wholesale power market.
We will size our fleet of generation assets to take advantage of market
opportunities, while seeking to increase our value and manage commodity price
risk through our wholesale energy trading activity. A significant portion of our
projected investment expenditures in the latter part of this forecast are not
yet committed to specific projects.

         Factors affecting actual expenditures and investments, including
ongoing construction programs, include: availability of capital, suitable
investment opportunities, prices of energy and supply in markets in which we
participate, economic and political trends, revised load forecasts, business
strategies, site changes, cost escalations under construction contracts, and
requirements of regulatory authorities and laws.

<TABLE>
<CAPTION>
                                    Total
                                   Amounts       Less Than 1
Contractual Cash Obligations      Committed         Year           2 - 3 years    4 - 5 years   Over 5 years
------------------------------------------------------------------------------------------------------------
                                                          (Millions of Dollars)
<S>                             <C>               <C>              <C>           <C>           <C>
Long-Term Debt                      $2,694            $-               $-           $1,270        $1,424
Operating Leases                        21             1                4                2            14
                                ----------------------------------------------------------------------------
Total Contractual Cash
Obligations                         $2,715            $1               $4           $1,272        $1,438
                                ===========================================================================
</TABLE>

         We have guaranteed certain obligations of affiliates, including the
successful completion, performance or other obligations and have contract equity
contribution obligations related to certain projects in an aggregate amount of
approximately $500 million, as of December 31, 2001. A substantial portion of
such guarantees is eliminated upon successful completion, performance and/or
refinancing of construction debt with non-recourse project term debt.

<TABLE>
<CAPTION>
                                       Total Amounts    Less Than 1
Other Commercial Commitments             Committed          Year
                                           (Millions of Dollars)
                                      -------------------------------
<S>                                    <C>             <C>
Letters of Credit                           $100            $100
Equity Commitments                           400             400
                                      -------------------------------
Total Commercial Commitments                $500            $500
                                      ===============================
</TABLE>


QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

         The market risk inherent in our market risk sensitive instruments and
positions is the potential loss arising from adverse changes in commodity prices
and interest rates as discussed in the notes to the financial statements. Our
policy is to use derivatives to manage risk consistent with our business plans
and prudent practices. We have a Risk Management Committee comprised of
executive officers which utilizes an independent risk oversight function to
ensure compliance with corporate policies and prudent risk management practices.


                                       31
<PAGE>

         Counterparties expose us to credit losses in the event of
non-performance or non-payment. We have a credit management process which is
used to assess, monitor and mitigate counterparty exposure for us and our
subsidiaries. In the event of non-performance or non-payment by a major
counterparty, there may be a material adverse impact on our and our
subsidiaries' financial condition, results of operations or net cash flows.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

         COMMODITY CONTRACTS

         The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.

         During 2001, we entered into electric physical forward contracts and
gas futures and swaps to hedge our forecasted BGS requirements and gas purchases
requirements for generation. These transactions qualified for hedge accounting
treatment under SFAS 133 and were settled prior to the end of 2001.
Marked-to-market valuations were reclassified from Other Comprehensive Income
(OCI) to earnings during the third quarter ended September 30, 2001. As of
December 31, 2001, we did not have any outstanding derivatives accounted for
under this methodology. However, there was substantial activity during the year
ended December 31, 2001. In 2001, the values of these forward contracts, gas
futures and swaps as of June 30 and September 30 were $(34.2) million and $(0.4)
million.

         We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.

         The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.

         The measured VAR using a variance/co-variance model with a 95%
confidence level and assuming a one-week time horizon as of December 31, 2001
was approximately $14 million, compared to the December 31, 2000 level of $19
million. This estimate was driven by A conservative assumption that we would
enter into contracts for approximately 50% of its generating capacity during the
BGS auction. Since we obtained contracts in excess of this amount, the VAR at
December 31, 2001 would have been even lower. This estimate, however, is not
necessarily indicative of actual results, which may differ due to the fact that
actual market rate fluctuations may differ from forecasted fluctuations and due
to the fact that the portfolio of hedging instruments may change over the
holding period and due to certain assumptions embedded in the calculation.

         Given the absence of a PJM price cap in situations involving emergency
purchases and the potential for plant outages, extreme price movements, which
have occurred, could have a material adverse impact on our financial condition,
results of operations and net cash flows.

         INTEREST RATE SWAPS

         In October 2001, we entered into three interest rate swaps with an
aggregate notional amount of $177.5 million to hedge the variability of interest
payments related to the construction on our Waterford, Ohio facility. The swaps
qualify for hedge accounting treatment under SFAS 133. As of December 31, 2001,
the related fair value of $2.3 million was recorded on the balance sheet and the
effective portion of the swaps was recorded in OCI. Management expects to
amortize approximately $1.9 million (net of tax of $1.3) from OCI to earnings
during the next 12 months. As of December 31, 2001, there was $1.3 million
remaining in the OCI account.


                                       32
<PAGE>

         In February 2001, we entered into various forward-interest rate swaps,
with an aggregate notional amount of $400 million, to hedge the interest rate
risk related to the anticipated issuance of debt. These fixed swaps paid a fixed
rate of 6%, received 3-month LIBOR, with a maturity date of August 14, 2011. The
original effective date of the swaps was August 14, 2001. On April 11, 2001, we
issued $1.8 billion in fixed-rate Senior Notes and closed out the forward
starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million
was classified as Accumulated Other Comprehensive Loss and is being amortized
and charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects to amortize approximately $0.8 million (net of tax
of $0.3) from OCI to earnings during the next twelve months. As of December 31,
2001, there was $2.8 million remaining in the OCI account.

         CREDIT RISK

         Credit risk relates to the risk of loss that we would incur as a result
of non-performance by counterparties, pursuant to the terms of their contractual
obligations. PSEG has established credit policies that it believes significantly
minimize our exposure to credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit rating),
collateral requirements under certain circumstances and the use of standardized
agreements, which may allow for the netting of positive and negative exposures
associated with a single counterparty. We also established credit reserves for
our energy trading contracts based on various factors, including individual
counterparty's position, credit rating, default possibility and recovery rates.

         As a result of the BGS auction, we have contracted to provide
generating capacity to the direct suppliers of the four New Jersey electric
utilities, including PSE&G, commencing August 1, 2002. These bilateral contracts
are subject to credit risk. This credit risk relates to the ability of
counterparties to meet their payment obligations for the power delivered under
each BGS contract. This risk is substantially higher than the risk associated
with potential nonpayment by PSE&G under the BGS contract expiring July 31,
2002. Any failure to collect these payments under the new BGS contracts could
have a material impact on our results of operations, cash flows, and financial
position.

         In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. We entered into a variety of energy
trading contracts with Enron in the PJM area as part of our energy trading
activities. With the first signs of Enron's financial problems, we took steps to
mitigate our exposure to both Enron and other counterparties who had significant
exposures with Enron. As of December 31, 2001, we owed Enron approximately $23
million, net, and Enron held a letter of credit from us for approximately $40
million.

         Two major California utilities, including Pacific Gas & Electric
Company (PG&E), have significantly underrecovered from customers costs paid for
power. As a consequence, these utilities have defaulted under a variety of
contractual obligations and on April 6, 2001, PG&E filed for reorganization
under Chapter 11 of the U.S. Bankruptcy Code. Affiliates of these California
utilities have entered into physical forward and swap contracts with us for
delivery in PJM. These counterparties have met their obligations to date and are
still investment grade entities. We have entered into a limited number of
additional contracts since May 2001 with one of these counterparties, but no
additional contracts have been entered into with the other counterparty since
December 2000. Our exposure to these entities under these contracts is not
material and management does not believe that a specific reserve related to
receivables for these counterparties is presently necessary.

ACCOUNTING ISSUES

CRITICAL ACCOUNTING POLICIES AND OTHER ACCOUNTING MATTERS

         Our most critical accounting policies include the application of:
Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" (EITF 98-10) and EITF 99-19,
"Reporting Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19),
for our Energy Trading business; and SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended (SFAS 133), to account for our
various hedging transactions.


                                       33
<PAGE>

ACCOUNTING, VALUATION AND PRESENTATION OF OUR ENERGY TRADING BUSINESS

         ACCOUNTING - We account for our energy trading business in accordance
with the provisions of EITF 98-10, which requires that energy trading contracts
be marked to market with gains and losses included in current earnings.

         VALUATION - Since the vast majority of our energy trading contracts
have terms of less than one year, valuations for these contracts are readily
obtainable from the market exchanges, such as PJM, and over the counter
quotations. The valuations also include a credit reserve and a liquidity
reserve, which is determined using financial quotation systems, monthly bid-ask
prices and spread percentages. We have consistently applied this valuation
methodology for each reporting period presented. The fair values of these
contracts and a more detailed discussion of credit risk are reflected in Note 4
- Financial Instruments, Energy Trading and Risk Management.

         PRESENTATION - EITF 99-19 provided guidance on the issue of whether a
company should report revenue based on the gross amount billed to the customer
or the net amount retained. The guidance states that whether a company should
recognize revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We report swaps,
futures, option premiums, firm transmission rights, transmission congestion
credits, and purchases and sales of emission allowances on a net basis. The
prior year financial statements have been reclassified accordingly. One of the
primary drivers of our determination that these contracts should be presented on
a gross basis was that we retain counterparty risk.

SFAS 133 - ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

         SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in OCI, net of tax, or as a Regulatory Asset (Liability). Amounts in
accumulated OCI are ultimately recognized in earnings when the related hedged
forecasted transaction occurs. The change in the fair value of the ineffective
portion of the derivative instrument designated as a cash flow hedge is recorded
in earnings. Derivative instruments that have not been designated as hedges are
adjusted to fair value through earnings. We have entered into several derivative
instruments, including hedges of anticipated electric and gas purchases and
interest rate swaps which have been designated as cash flow hedges. The fair
value of the derivative instruments is determined by reference to quoted market
prices, listed contracts, published quotations or quotations from
counterparties.

         For additional information regarding Derivative Financial Instruments,
See Note 4 - Financial Instruments, Energy Trading and Risk Management -
Derivative Instruments and Hedging Activities.

OTHER ACCOUNTING POLICIES AND ISSUES

         For additional information on our accounting policies and the
implementation of recently issued accounting standards, see Note 1. -
Organization, Basis of Presentation and Summary of Significant Accounting
Policies and Note 2 -Accounting Matters, respectively.

FORWARD LOOKING STATEMENTS

         Except for the historical information contained herein, certain of the
matters discussed in this report constitute "forward-looking statements" within
the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements are subject to risks and uncertainties which could
cause actual results to differ materially from those anticipated. Such
statements are based on management's beliefs as well as assumptions made by and
information currently available to management. When used herein, the words
"will", "anticipate", "intend", "estimate", "believe", "expect", "plan",
"hypothetical", "potential", variations of such words and similar expressions
are intended to identify forward-looking statements. We undertake no obligation
to publicly update or revise any forward-looking statements, whether as a result
of



                                       34
<PAGE>

new information, future events or otherwise. The following review of factors
should not be construed as exhaustive or as any admission regarding the adequacy
of our disclosures prior to the effective date of the Private Securities
Litigation Reform Act of 1995.

         In addition to any assumptions and other factors referred to
specifically in connection with such forward-looking statements, factors that
could cause actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:

    o    Credit, Commodity, and Financial Market Risks May Have an Adverse
         Impact
    o    Energy Obligations, Available Supply and Trading Risks May Have an
         Adverse Impact
    o    The Electric Utility Industry is Undergoing Substantial Change o
         Generation Operating Performance May Fall Below Projected Levels
    o    We are subject to Substantial Competition From Well Capitalized
         Participants in the Worldwide Energy Markets
    o    Our Ability to Service Our Debt Could Be Limited
    o    Power Transmission Facilities May Impact Our Ability to Deliver Our
         Output to Customers
    o    Regulatory Issues Significantly Impact Our Operations
    o    Environmental Regulation May Limit Our Operations
    o    We Are Subject to More Stringent Environmental Regulation than Many of
         Our Competitors
    o    Insurance Coverage May Not Be Sufficient
    o    Acquisition, Construction and Development Activities May Not Be
         Successful
    o    Changes in Technology May Make our Power Generation Assets Less
         Competitive
    o    We are subject to control by PSEG
    o    Recession, Acts of War, Terrorism Could Have an Adverse Impact

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

         Information relating to quantitative and qualitative disclosures about
market risk is set forth under the caption "Qualitative and Quantitative
Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations. Such information is
incorporated herein by reference.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


                                       35

<PAGE>


                                 PSEG POWER LLC
                        CONSOLIDATED STATEMENTS OF INCOME
                              (Millions of Dollars)


<TABLE>
<CAPTION>
                                                            For the Years Ended December 31,
                                                           ----------------------------------
                                                            2001          2000         1999
                                                           -------      -------       -------
<S>                                                        <C>          <C>           <C>
OPERATING REVENUES
      Generation                                           $ 2,311      $ 2,203       $ 2,652
      Trading                                                2,403        2,724         1,842
                                                           -------      -------       -------
              Total Operating Revenues                       4,714        4,927         4,494
                                                           -------      -------       -------

OPERATING EXPENSES
      Energy Costs                                             843          746           831
      Trading Costs                                          2,256        2,647         1,800
      Operation and Maintenance                                711          659           689
      Depreciation and Amortization                             95          136           224
      Taxes Other Than Income Taxes                             22           27            19
                                                           -------      -------       -------
              Total Operating Expenses                       3,927        4,215         3,563
                                                           -------      -------       -------
OPERATING INCOME                                               787          712           931
Other Income and Deductions                                     --            7            --
Interest Expense                                              (143)        (198)         (112)
Preferred Securities Dividend Requirements of Subsidiaries      --           --           (12)
                                                           -------      -------       -------
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM              644          521           807
Income Taxes                                                  (250)        (208)         (291)
                                                           -------      -------       -------
INCOME BEFORE EXTRAORDINARY ITEM                               394          313           516
      Extraordinary Item (Net of Tax of $2,002)                 --           --        (3,204)
                                                           -------      -------       -------
NET INCOME (LOSS)                                              394          313        (2,688)
      Preferred Stock Dividend Requirements                     --           --            (3)
                                                           -------      -------       -------
EARNINGS (LOSS) AVAILABLE TO PUBLIC
      SERVICE ENTERPRISE GROUP INCORPORATED                $   394      $   313       $(2,691)
                                                           =======      =======       =======
</TABLE>

See Notes to Consolidated Financial Statements.



                                       36
<PAGE>

                                 PSEG POWER LLC
                           CONSOLIDATED BALANCE SHEETS
                                     ASSETS
                              (Millions of Dollars)




<TABLE>
<CAPTION>
                                                            December 31, December 31,
                                                               2001         2000
                                                            -----------  ------------
<S>                                                         <C>           <C>
ASSETS
CURRENT ASSETS:
     Cash and Cash Equivalents                              $     9       $    20
     Accounts Receivable                                        270           272
     Accounts Receivable-Affiliated Companies                   159           159
     Materials and Supplies,
       net of valuation reserves (2001, $2 and 2000, $11)       124           107
     Fuel                                                        76            58
     Energy Trading Contracts                                   422           799
     Other                                                       15            12
                                                            -------       -------
          Total Current Assets                                1,075         1,427
                                                            -------       -------

PROPERTY, PLANT AND EQUIPMENT:                                4,238         2,684
     Less: Accumulated depreciation and amortization         (1,253)       (1,070)
                                                            -------       -------
          Net Property, Plant & Equipment                     2,985         1,614
                                                            -------       -------

NONCURRENT ASSETS:
     Nuclear Decommissioning Fund                               817           716
     Deferred Income Taxes                                      579           676
     Other                                                      178            97
                                                            -------       -------
          Total Noncurrent Assets                             1,574         1,489
                                                            -------       -------

TOTAL ASSETS                                                $ 5,634       $ 4,530
                                                            =======       =======
</TABLE>

See Notes to Consolidated Financial Statements.



                                       37
<PAGE>

                                 PSEG POWER LLC
                           CONSOLIDATED BALANCE SHEETS
                         LIABILITIES AND MEMBER'S EQUITY
                              (Millions of Dollars)

<TABLE>
<CAPTION>
                                                      December 31,  December 31,
                                                          2001          2000
                                                      ------------  ------------
<S>                                                         <C>            <C>
LIABILITIES AND MEMBER'S EQUITY
CURRENT LIABILITIES:
     Accounts Payable                                       333           336
     Accounts Payable-Affiliated Companies                  137           317
     Energy Trading Contracts                               434           730
     Other                                                  111            87
                                                        -------       -------
        Total Current Liabilities                         1,015         1,470
                                                        -------       -------

NONCURRENT LIABILITIES:
     Nuclear Decommissioning                                817           716
     Cost of Removal Liability                              146           157
     Environmental                                           53            53
     Other                                                   58            80
                                                        -------       -------
        Total Noncurrent Liabilities                      1,074         1,006
                                                        -------       -------

COMMITMENTS AND CONTINGENT LIABILITIES:                      --            --

LONG-TERM DEBT:
     Note Payable-Affiliated Company                         --         2,786
     Long-Term Debt                                       2,685            --
                                                        -------       -------
Total Long-Term Debt                                      2,685         2,786
                                                        -------       -------

MEMBER'S EQUITY
     Contributed Capital                                  1,350           150
     Basis Adjustment                                      (986)         (986)
     Retained Earnings                                      498           104
     Accumulated Other Comprehensive Income (Loss)           (2)           --
                                                        -------       -------
        Total Member's Equity                               860          (732)
                                                        -------       -------
TOTAL LIABILITIES AND MEMBER'S EQUITY                   $ 5,634       $ 4,530
                                                        =======       =======
</TABLE>


See Notes to Consolidated Financial Statements.




                                       38
<PAGE>

                                 PSEG POWER LLC
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (Millions of Dollars)

<TABLE>
<CAPTION>
                                                                       For the Years Ended December 31,
                                                                     -----------------------------------
                                                                       2001          2000          1999
                                                                     -------       -------       -------
CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                  <C>           <C>           <C>
  Net Income/(Loss)                                                  $   394       $   313       $(2,688)
  Adjustments to reconcile net income/(loss) to net cash flows
   from operating activities:
     Depreciation and Amortization                                        95           136           224
     Amortization of Nuclear Fuel                                         99            96            92
     Provision for Deferred Income Taxes                                  97           (69)          (70)
     Net changes in certain current assets and liabilities:
        Materials and Supplies and Fuel                                  (35)          (30)           51
        Accounts Receivable                                                2           161            10
        Accounts Payable                                                (183)          195            44
        Other Current Assets and Liabilities                             102           (89)          (22)
     Extraordinary Item - net of tax                                      --            --         3,204
     Recovery of Electric Energy Costs                                    --            --            20
     Demand Side Management                                               --            --           (64)
     Other                                                              (172)          (12)          (31)
                                                                     -------       -------       -------
       Net Cash Provided By Operating Activities                         399           701           770
                                                                     -------       -------       -------
CASH FLOWS FROM INVESTING ACTIVITIES
  Additions to Property, Plant and Equipment                          (1,462)         (405)          (92)
  Acquisition of Generation Businesses                                    --           (74)           --
  Contribution to Decommissioning Funds and Other Special Funds          (47)          (29)         (115)
  Other                                                                   --           (34)          (24)
                                                                     -------       -------       -------
       Net Cash Used In Investing Activities                          (1,509)         (542)         (231)
                                                                     -------       -------       -------
CASH FLOWS FROM FINANCING ACTIVITIES
  Net Change in Commercial Paper and Loans                                --          (685)          262
  Issuance of Long-Term Debt                                           2,685            --            --
  Repayment of Note Payable - Affiliated Company                      (2,786)           --            --
  Net Change in Capitalization Activity                                   --           319          (746)
  Proceeds from Contributed Capital                                    1,200           150            --
                                                                     -------       -------       -------
       Net Cash Provided By/(Used In) Financing Activities             1,099          (216)         (484)
                                                                     -------       -------       -------
Net Change In Cash And Cash Equivalents                                  (11)          (57)           55
Cash And Cash Equivalents At Beginning Of Year                            20            77            22
                                                                     -------       -------       -------
Cash And Cash Equivalents At End Of Year                             $     9       $    20       $    77
                                                                     =======       =======       =======

Income Taxes Paid                                                    $   166       $   242       $   306
Interest Paid                                                        $   191       $   159       $   104
</TABLE>



See Notes to Consolidated Financial Statements.



                                       39
<PAGE>


                                 PSEG POWER LLC
          CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER'S EQUITY
                              (Millions of Dollars)



<TABLE>
<CAPTION>
                                                                                         Accumulated
                                                                                            Other
                                            Contributed       Basis          Retained    Comprehensive
                                              Capital       Adjustment       Earnings        Loss
                                           -------------   -------------   ------------  -------------
<S>                                          <C>             <C>              <C>             <C>
Balance as of December 31, 1998                  --              --               --              --
                                             ------          ------           ------          ------
    Net Loss (1)                                 --              --               --              --
    Net Transfers to PSEG                        --              --               --              --
    Cash Dividends Paid                          --              --               --              --
                                             ------          ------           ------          ------
Balance as of December 31, 1999                  --              --               --              --
                                             ------          ------           ------          ------
    Net Income (1)                               --              --              104
    Contributed Capital                         150              --               --              --
    Net Transfers to PSEG                        --              --               --              --
    Transfer of Generation Business              --            (986)              --              --
                                             ------          ------           ------          ------
Balance as of December 31, 2000              $  150          $ (986)          $  104          $   --
                                             ------          ------           ------          ------
    Net Income (1)                               --              --              394
    Change in Fair Value of Financial
       Instruments (net of tax $(16))                                                            (23)
    Reclassification Adjustments for Net
       Amount included in Net Income
       (Net of tax of $14)                                                                        21
    Other Comprehensive Income/Loss              --              --               --

    Comprehensive Income
    Contributed Capital                       1,200              --               --              --
                                             ------          ------           ------          ------
Balance as of December 31, 2001              $1,350          $ (986)          $  498          $   (2)
                                             ======          ======           ======          ======
</TABLE>

<TABLE>
<CAPTION>

                                                                                 Total
                                               Total                         Capitalization
                                             Member's                        and Member's
                                              Equity        Capitalization       Equity
                                             ---------      --------------   --------------

<S>                                          <C>               <C>               <C>
Balance as of December 31, 1998                   --             5,187             5,187
                                             -------           -------           -------
    Net Loss (1)                                  --            (2,688)           (2,688)
    Net Transfers to PSEG                         --            (1,224)           (1,224)
    Cash Dividends Paid                           --                (3)               (3)
                                             -------           -------           -------
Balance as of December 31, 1999                   --             1,272             1,272
                                             -------           -------           -------
    Net Income (1)                               104               209               313
    Contributed Capital                          150                --               150
    Net Transfers to PSEG                         --            (1,481)           (1,481)
    Transfer of Generation Business             (986)                               (986)
                                             -------           -------           -------
Balance as of December 31, 2000              $  (732)               --           $  (732)
                                             -------           -------           -------
    Net Income (1)                               394                --               394
    Change in Fair Value of Financial
       Instruments (net of tax $(16))            (23)                                (23)
    Reclassification Adjustments for Net
       Amount included in Net Income
       (Net of tax of $14)                        21                                  21
                                             -------                             -------
    Other Comprehensive Income/Loss (2)           (2)               --                (2)
                                             -------                             -------

    Comprehensive Income                         392                                 392
    Contributed Capital                        1,200                --             1,200
                                             -------           -------           -------
Balance as of December 31, 2001              $   860           $    --           $   860
                                             =======           =======           =======
</TABLE>





(1)  Net Income included in retained earnings reflects earnings from the legal
     operations of PSEG Power LLC during 2000. Net Income/Loss included in
     Capitalization for 2000 and 1999 reflects the Net Income/Loss allocated
     from Public Service Electric and Gas Company's generation business.


See Notes to Consolidated Financial Statements.


                                       40
<PAGE>



                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. ORGANIZATION, BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT
        ACCOUNTING POLICIES

ORGANIZATION

         We have three principal direct wholly-owned subsidiaries: PSEG Nuclear
LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC
(ER&T) and currently operate in two reportable segments, generation and energy
trading. The generation segment of our business earns revenues by selling energy
on a wholesale basis under contract to our affiliate, Public Service Electric
and Gas Company (PSE&G) and other power marketers and to load serving entities,
and by bidding energy, capacity and ancillary services into the market. The
energy trading segment of our business earns revenues by trading energy,
capacity, fixed transmission rights, fuel and emission allowances in the spot,
forward and futures markets. The energy trading segment also earns revenues
through financial transactions, including swaps, options and futures in the
electricity markets. We and our subsidiaries were established to acquire, own
and operate the electric generation-related business of PSE&G pursuant to the
Final Decision and Order (Final Order) issued by the New Jersey Board of Public
Utilities (BPU) under the New Jersey Electric Discount and Energy Competition
Act (Energy Competition Act) discussed below. We also have a finance company
subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides
certain financing for our subsidiaries.

PURCHASE OF GENERATION-RELATED BUSINESS FROM PSE&G

         In August 2000, pursuant to the Final Order, we purchased PSE&G's
generation-related property, plant and equipment for $2.443 billion, as
specified in the Final Order, plus $343 million for other generation-related
assets and liabilities (Transaction) in exchange for a $2.786 billion promissory
note with an interest rate of 14.23%, representing PSE&G's weighted average cost
of capital. We repaid the promissory note on January 31, 2001, with funds
provided from PSEG in the form of equity and loans.

         Because the assets were purchased from an affiliate, we recorded the
assets at PSE&G's carrying value. The difference between the total purchase
price and the net book value of the generation-related assets and liabilities
was recorded as a Basis Adjustment reducing our equity.

BASIS OF PRESENTATION

         Our consolidated financial statements present the historical financial
position, results of operations and net cash flows of the generation-related
business of PSE&G prior to the Transaction in August 2000, and are not
necessarily indicative of the financial position, results of operations or net
cash flows that would have existed had the generation-related business been an
independent company during the periods presented. For periods prior to the
Transaction, any references to us contained herein refer to our business and the
generation-related business of PSE&G prior to the purchase of the
generation-related business from PSE&G.

         Certain information in these consolidated financial statements relating
to the results of operations and financial condition prior to the Transaction
was derived from the historical financial statements of PSE&G which have been
prepared in accordance with generally accepted accounting principles (GAAP).
Various allocation methodologies were employed to separate the results of
operations and financial condition of the generation-related portion of PSE&G's
business from PSE&G's historical financial statements prior to the Transaction.
Prior to the Transaction, revenues included the generation segment of revenue
from PSE&G's operations and any generation-related revenues, such as ancillary
services and wholesale energy activity. Expenses, such as energy costs,
operations and maintenance and depreciation and amortization, and assets, such
as property, plant and equipment, materials and supplies and fuel, were
specifically identified by function and reported accordingly for our operations.
Various allocations were used to disaggregate other common expenses, assets and
liabilities between us and PSE&G's regulated transmission and distribution
operations. Interest and preferred stock dividends were calculated based upon an
allocation methodology that charged us with financing and equity costs from
PSE&G in proportion to our share of total net property, plant and equipment
prior to the effects of deregulation discussed below. These methodologies use
the assumption that we had operated as a separate, regulated company prior to
April 1, 1999, the date we


                                       41
<PAGE>


              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

discontinued the application of Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS
71). On the date of the Transaction, certain of the assets and liabilities which
were allocated in the historical consolidated financial statements, such as
other postretirement employee benefits (OPEB) and working capital, remained with
PSE&G. For additional information, see - Accounting for the Effects of
Regulation, below.

         Management believes that these allocation methodologies are reasonable.
Had we existed as a separate company, our results could have significantly
differed from those presented herein. In addition, future results of operations,
financial position and net cash flows could materially differ from the
historical results presented.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

      CONSOLIDATION

         The consolidated statements include our accounts and those of our
subsidiaries. We consolidate those entities in which we have a controlling
interest, with the exception of the Salem Peach Bottom, Keystone, Conemaugh and
Yards Creek Generation facilities, which are accounted for on a pro-rata
consolidated basis. All significant intercompany accounts and transactions are
eliminated in consolidation.

      ACCOUNTING FOR THE EFFECTS OF REGULATION

         Prior to April 1999, our financial statements were prepared in
accordance with the provisions of SFAS 71. In general, SFAS 71 recognizes that
accounting for rate-regulated enterprises should reflect the relationship of
costs and revenues as determined by regulators. Under SFAS 71, a regulated
entity must defer recognition of costs (a regulatory asset) or recognize
obligations (a regulatory liability) if it is probable that, through the
rate-making process, there will be a corresponding increase or decrease in
future revenues.

         Effective April 1, 1999, we discontinued the application of SFAS 71 and
recorded an extraordinary charge consistent with the requirements of Emerging
Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of
Electricity - Issues Related to the Application of FASB Statements No. 71 and
No. 101" (EITF 97-4) and SFAS 101, "Regulated Enterprises--Accounting for the
Discontinuation of Application of FASB Statement No. 71" (SFAS 101). The
extraordinary charge consisted primarily of the write-down of our nuclear and
fossil generating stations in accordance with SFAS 121. A discounted cash flow
analysis was performed on a unit-by-unit basis to determine the amount of the
impairment. As a result of this impairment analysis, the net book value of the
generating stations was reduced by approximately $5.0 billion (pre-tax) or
approximately $3.1 billion (after-tax).

         In addition to the impairment of our generating stations, the
extraordinary charge consisted of various accounting adjustments to reflect the
absence of cost of service regulation for electric generation in the future. The
adjustments related primarily to materials and supplies, general plant items and
liabilities for certain contractual and environmental obligations.

         Other accounting impacts of the discontinuation of SFAS 71 included
reclassifying the Accrued Nuclear Decommissioning Reserve and the Accrued Cost
of Removal for generation-related assets from Accumulated Depreciation to
Long-Term Liabilities.

      DERIVATIVE FINANCIAL INSTRUMENTS

         We use derivative financial instruments to manage risk from changes in
interest rates and commodity prices, pursuant to business plans and prudent
practices.

         On January 1, 2001, we adopted SFAS 133, as amended (SFAS 133). SFAS
133 established accounting and reporting standards for derivative instruments,
including certain derivative instruments included in other contracts, and for
hedging activities. It requires an entity to recognize the fair value of
derivative instruments held as assets or liabilities on the balance sheet. For
cash flow hedging purposes, changes in the fair value of the effective portion
of the gain or loss on the derivative are reported in Other Comprehensive Income
(OCI), net of tax. Amounts in accumulated OCI are ultimately recognized in
earnings when the related hedged forecasted transaction occurs. The change in
the fair value of the ineffective portion of the gain or loss on a derivative
instrument designated as a cash


                                       42
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

flow hedge is recorded in earnings. Derivative instruments that have not been
designated as hedges are adjusted to fair value through earnings.

         We did not have a transition adjustment upon adoption. Subsequent to
December 31, 2000, we entered into certain derivative instruments, which have
been designated as cash flow hedges. We have not utilized any derivative
instruments for fair value hedging purposes.

         The fair value of the derivative instruments is determined by reference
to quoted market prices, listed contracts, published quotations or quotations
from counterparties. In the absence thereof, we utilize mathematical models
based on current and historical data.

         Prior to the adoption of SFAS 133, we accounted for the results of our
derivative activities for hedging purposes utilizing the settlement method. The
settlement method provided for recognizing the gains or losses from derivatives
when the related underlying transaction was completed. Derivatives that were not
entered into for hedging purposes were recorded at fair value and changes in the
fair value were recorded in earnings.

         For additional information regarding Derivative Financial Instruments,
See Note 4 - Financial Instruments, Energy Trading and Risk Management -
Derivative Instruments and Hedging Activities.

      COMMODITY CONTRACTS

         We enter into electricity forward purchases and natural gas commodity
futures and swaps with counterparties to manage exposure to electricity and
natural gas price risk. These contracts, in conjunction with owned electric
generating capacity, are designed to manage price risk exposure for electric
customer commitments. In accordance with SFAS 133, such energy contracts are
recognized at fair value as derivative assets or liabilities on the balance
sheet and the effective portion of the gain or loss on the contracts is reported
in OCI, net of tax. Amounts in accumulated other comprehensive income are
ultimately recognized in earnings when the related hedged forecasted transaction
occurs.

         We also enter into forwards, futures, swaps and options as part of our
energy trading operations. Effective January 1, 1999, we adopted Emerging Issues
Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires that
energy trading contracts be marked to market with gains and losses included in
current earnings.

         The vast majority of these commodity-related contracts have terms of
less than one year. Valuations for these contracts are readily obtainable from
the market exchanges, such as the PJM ISO, and over the counter quotations. The
fair value of the financial instruments that are marked to market are based on
management's best estimates. The valuations also take into account a liquidity
reserve, which is determined by using financial quotation systems, monthly
bid-ask prices and spread percentages. The valuations also take into account
credit reserves, discussed in Note 4. - Financial Instruments, Energy Trading
and Risk Management - Credit Risk. We have consistently applied this valuation
methodology for each reporting period presented.

         In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent" (EITF 99-19), provided guidance on the issue of whether
a company should report revenue based on the gross amount billed to the customer
or the net amount retained. The guidance states that whether a company should
recognize revenue based on the gross amount billed or the net retained requires
significant judgement, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all trading
revenues and trading-related costs on a gross basis for physical bilateral
energy and capacity sales and purchases. We report swaps, futures, option
premiums, firm transmission rights, transmission congestion credits, and
purchases and sales of emission allowances on a net basis. The prior year
financial statements have been reclassified accordingly.

      For additional information regarding commodity-related contracts, See Note
4 - Financial Instruments, Energy Trading and Risk Management

         GENERATION REVENUES AND ENERGY COSTS

                                       43
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

         Revenues are recorded based on energy and capacity sold and services
rendered to customers during each accounting period. Prior to August 1, 1999,
revenue was calculated by unbundling the generation component of revenue from
PSE&G's bundled rate for the generation, transmission and distribution of energy
and adding any other generation-related revenues, such as ancillary services and
wholesale energy trading activity. Also, prior to August 1, 1999, we recorded
unbilled revenues representing the estimated amount customers would be billed
for services rendered from the time meters were last read to the end of the
respective accounting period. Beginning on August 1, 1999, electric rates
charged to customers were unbundled and the generation, transmission,
distribution and other components of the total rate became separate charges.
Effective with that date, revenue represents the amount recorded for the energy
and capacity provided to meet the BGS requirements to PSE&G combined with other
generation-related revenues, such as ancillary services, wholesale trading
activity and amounts recorded for the market transition charge (MTC) (see Note
3. - Regulatory Issues and Accounting Impacts of Deregulation). Following the
Transaction, we bill, and periodically settle with, PSE&G for BGS requirements
and MTC.

         Prior to August 1, 1999, fuel revenues and expenses and purchased power
costs flowed through the Electric Levelized Energy Adjustment Clause (LEAC)
mechanism and variances in fuel revenues and expenses and purchased power costs
were subject to deferral accounting and thus had no direct effect on earnings.
Any LEAC underrecoveries or overrecoveries, together with interest (in the case
of net overrecoveries), were deferred and included in the results of operations
in the period in which they were reflected in rates. Effective January 1, 1998,
the amount included for LEAC under/overrecovery represented the difference
between fuel-related revenues and fuel-related expenses which included
electricity purchases at the PJM market clearing price. Effective April 1, 1998,
PJM, as an independent system operator (ISO), replaced the PJM uniform market
clearing price with LMP for determining the market clearing price to energy
providers. Due to the effects of congestion and constraints in the PJM market,
LMP may be different for the various delivery points in PJM. Due to the
discontinuation of the LEAC mechanism on August 1, 1999, earnings volatility
increased since the unregulated electric generation business ceased to follow
deferral accounting. We now bear the full risk and reward of managing the fixed
price BGS contract and the changes in nuclear and fossil generating fuel costs
and purchased power costs.

         DEPRECIATION AND AMORTIZATION

         We calculate depreciation on generation-related assets based on the
assets' estimated useful lives determined based on planned operations, rather
than using depreciation rates prescribed by the BPU in rate proceedings. Prior
to April 1999, depreciation rates were reviewed periodically and adjustments
were made as approved by the BPU. Depreciation rates stated in percentages of
original cost of depreciable property in 1999 (prior to April 1, 1999) were
3.52%. Prior to April 1999, we had certain regulatory assets embedded in
property, plant and equipment as a result of the use of a level of depreciation
expense in the rate-making process that differed from the amount that would have
been recorded under GAAP for non-regulated companies.

         The estimated useful lives are from 3 years to 20 years for general
plant. The estimated useful lives for buildings and generating stations are as
follows:

      Class of Property                 Estimated Useful Life (In Years)
      ---------------                   --------------------------------
      Fossil Production                              25-55
      Nuclear Generation                                30
      Pumped Storage                                    45

         Nuclear fuel burnup costs are charged to fuel expense on a
units-of-production basis over the estimated life of the fuel. Rates for the
recovery of fuel used at all nuclear units include a provision of one mill per
kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs.

         ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFDC) AND INTEREST
CAPITALIZED DURING CONSTRUCTION (IDC)


                                       44
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

         AFDC represented the cost of debt and equity funds used to finance the
construction of new facilities. The amount of AFDC capitalized was reported in
the Consolidated Statements of Income as a reduction of interest charges. The
rates used for calculating AFDC in 1999 (prior to April 1, 1999) was 5.29%.
Effective April 1, 1999, we no longer calculate AFDC. Interest related to
capital projects is now capitalized in accordance with SFAS No. 34,
"Capitalization of Interest Cost." In 1999, AFDC amounted to $1 million.

         IDC represents the cost of debt used to finance the construction of
non-utility facilities. The amount of IDC capitalized is reported in the
Consolidated Statements of Income as a reduction of interest expense. The
weighted average rates used for calculating IDC in 2001 and 2000 were 7.98% and
9.98%, respectively. In 2001, 2000 and 1999, IDC amounted to $63 million, $14
million and $3 million, respectively.

         INCOME TAXES

         We file a consolidated federal income tax return through PSEG. We
record our tax liabilities as though we were filing separate returns and will
record tax benefits to the extent that PSEG is able to receive those benefits.
Deferred income taxes are provided for the temporary differences between book
and taxable income, resulting primarily from the use of accelerated depreciation
for tax purposes and the recognition of unrealized gains for book purposes.
We defer and amortize investment and energy tax credits over the lives of the
related properties.

         CASH AND CASH EQUIVALENTS

         The December 31, 2001 and 2000 cash balances consist primarily of
working funds and highly liquid marketable securities (commercial paper and
money market funds) with an original maturity of three months or less.

         MATERIALS AND SUPPLIES AND FUEL

         The carrying value of the materials and supplies and fuel is recorded
at lower of cost or market.

         PROPERTY, PLANT AND EQUIPMENT

         We capitalize costs to acquire new assets or costs which increase
either the capacity or the useful life of an asset or costs which represent the
replacement of a retired asset. All other costs are expensed as incurred. Also,
under our revised policy, the remaining net carrying amount of a retired asset
is charged to earnings.

         Environmental costs are capitalized if the costs mitigate or prevent
future environmental contamination or if the costs improve existing assets'
environmental safety or efficiency. All other environmental expenditures are
expensed.

         IMPAIRMENT OF LONG-LIVED ASSETS

         We review long-lived assets for possible impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. In the event that facts and circumstances indicate that the
carrying amount of long-lived assets may be impaired, an evaluation of
recoverability would be performed. If an evaluation is required, the estimated
future undiscounted cash flows associated with the asset would be compared to
the asset's carrying amount to determine if a writedown is required. If this
review indicates that the assets will not be recoverable, the carrying value of
our assets would be reduced to their estimated market value. For the impact of
the application of SFAS 121, see Note 1. - Organization, Basis of Presentation
and Summary of Significant Accounting Policies - Accounting for the Effects of
Regulation.



                                       45
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

         USE OF ESTIMATES

         The process of preparing financial statements in conformity with GAAP
requires the use of estimates and assumptions regarding certain types of assets,
liabilities, revenues and expenses. Also, such estimates relate to unsettled
transactions and events as of the date of the financial statements. Accordingly,
upon settlement, actual results may differ from estimated amounts. In addition
to these estimates, see Basis of Presentation for a discussion of the estimates
used and methodologies employed to prepare our historical financial statements
for the periods prior to August 2000.

         RECLASSIFICATIONS

         Certain reclassifications of amounts reported in prior periods have
been made to conform with the current presentation.

         CURRENT ASSETS AND CURRENT LIABILITIES

         The fair value of current assets and current liabilities approximate
their carrying amounts.

NOTE 2. ACCOUNTING MATTERS

         In July 2001, the FASB issued SFAS No. 141, "Business Combinations"
(SFAS 141). SFAS 141 was effective July 1, 2001 and requires that all business
combinations on or after that date be accounted for under the purchase method.
Upon implementation of this standard, there was no impact on our financial
position or results of operations and we do not believe it will have a
substantial effect on our growth strategy.

         Also in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a
nonamortizable asset and will be subject to an annual review for impairment and
an interim review when events or circumstances occur. SFAS 142 is effective for
all fiscal years beginning after December 15, 2001. At December 31, 2001, we had
recorded goodwill of approximately $22 million as a result of our acquisition of
the Albany Steam Station from Niagara Mohawk Power Corporation (Niagara Mohawk)
in May 2000. This amount was being amortized over 40 years in accordance with
current accounting guidance yielding approximately $0.5 million of amortization
per year. The impact of adopting SFAS 142 is not likely to be material to our
financial position and statement of operations. For additional information
relating to potential asset impairments, see Note 5. Commitments and Contingent
Liabilities.

         Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). Upon adoption of SFAS 143, the fair value of
a liability for an asset retirement obligation is required to be recorded. Upon
settlement of the liability, an entity either settles the obligation for our
recorded amount or incurs a gain or loss upon settlement. SFAS 143 is effective
for fiscal years beginning after June 15, 2002. We are currently evaluating the
effect of this guidance and cannot predict the impact on our financial position
or results of operations, however, such impact could be material.


                                       46
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

         In August 2001, FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144 long-lived assets to
be disposed of should be measured at the lower of the carrying amount or fair
value less cost to sell, whether reported in continued operations or in
discontinued operations. Discontinued operations will no longer be measured at
net realizable value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the reporting of discontinued operations. SFAS
144 is effective for fiscal years beginning after December 15, 2001. We are
currently evaluating this guidance and do not believe that it will have a
material impact on our financial position or results of operations.

NOTE 3. REGULATORY ISSUES AND ACCOUNTING IMPACTS OF DEREGULATION

NEW JERSEY ENERGY MASTER PLAN PROCEEDINGS AND RELATED ORDERS

         Following the enactment of the Energy Competition Act, the BPU rendered
a Final Order relating to PSE&G's rate unbundling, stranded costs and
restructuring proceedings (Final Order). PSE&G, pursuant to the Final Order,
transferred our electric generating facilities and wholesale power contracts to
us and our subsidiaries on August 21, 2000 in exchange for a promissory note in
an amount equal to the purchase price.

         The generation assets were transferred at the price specified in the
BPU order - $2.443 billion plus the net book value of $343 million for other
generation related assets and liabilities. Because the transfer was between
affiliates, PSE&G and us, we recorded the sale at the net book value of the
assets and liabilities rather than the transfer price. The difference between
the total transfer price and the net book value of the generation-related assets
and liabilities was recorded as an equity adjustment on PSE&G's and our
Consolidated Balance Sheets. These amounts are eliminated on our consolidated
financial statements. We settled the promissory note on January 31, 2001, with
equity contributions and loans provided by PSEG.

         Also in the Final Order, the BPU concluded that PSE&G should recover up
to $2.94 billion (net of tax) of its generation-related stranded costs, through
securitization of $2.4 billion, plus an estimated $125 million of transaction
costs, and an opportunity to recover up to $540 million (net of tax) of its
unsecuritized generation-related stranded costs on a net present value basis.
The $540 million is subject to recovery through the MTC, which is to be
collected over a four year period ending on July 31, 2003 and is remitted to us
along with BGS revenues as part of PSE&G's BGS contract with us. Upon expiration
of the BGS contract on July 31, 2002, PSE&G will continue to remit the MTC
revenues to us through July 31, 2003.

NOTE 4. FINANCIAL INSTRUMENTS, ENERGY TRADING AND RISK MANAGEMENT

         Our operations are exposed to market risks from changes in commodity
prices and interest rates that could affect our results of operations and
financial conditions. We manage our exposure to these market risks through our
regular operating and financing activities and, when deemed appropriate, hedge
these risks through the use of derivative financial instruments. We use the term
hedge to mean a strategy designed to manage risks of volatility in prices or
rate movements on certain assets, liabilities or anticipated transactions and by
creating a relationship in which gains or losses on derivative instruments are
expected to counterbalance the losses or gains on the assets, liabilities or
anticipated transactions exposed to such market risks. We use derivative
instruments as risk management tools consistent with our business plans and
prudent business practices and for energy trading purposes.

ENERGY TRADING

         Effective January 1, 1999, we adopted EITF 98-10, which requires that
energy trading contracts be recognized on the balance sheet at fair value with
resulting realized and unrealized gains and losses included in current earnings.
In 2001, we recorded $147 million of gains from our Energy Trading segment,
including realized gains of $169 million and unrealized losses of $22 million.
In 2000, we recorded gains of $77 million, including $22 million of realized
gains and $55 million of unrealized gains and in 1999 recorded gains of $42
million,


                                       47
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

including $37 million of realized gains and $5 million of unrealized gains. Net
of broker fees and other trading related expenses, our energy trading business
earned margins of $140 million, $72 million and $39 million for the years ended
December 31, 2001, 2000 and 1999, respectively. As of December 31, 2001, we had
a total of $9 million of net unrealized gains on our balance sheet, over 90% of
which related to contracts with terms of less than two years.

                                                        (MILLIONS OF DOLLARS)
      Fair Value December 31, 2000.................                   $ 72
      Realized Gains...............................                   (169)
      Unrealized Losses............................                    (22)
      Fair Value of New Contracts..................                    128
                                                        ---------------------
      Fair Value December 31, 2001.................                    $ 9
                                                        =====================

         We engage in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights and emissions
allowances in the spot, forward and futures markets primarily in PJM, but also
throughout the Super Region. We are also involved in the financial transactions
that include swaps, options and futures in the electricity markets.

         The fair values as of December 31, 2001 and December 31, 2000 and the
average fair values for the periods then ended of our financial instruments
related to the energy commodities in the energy trading segment are summarized
in the following table:

<TABLE>
<CAPTION>
                                       DECEMBER 31, 2001                           DECEMBER 31, 2000
                            ----------------------------------------- ---------------------------------------------
                            NOTIONAL   NOTIONAL    FAIR     AVERAGE    NOTIONAL   NOTIONAL      FAIR     AVERAGE
                              (MWH)    (MMBTU)    VALUE    FAIR VALUE   (MWH)      (MMBTU)      VALUE   FAIR VALUE
                            --------  ---------- -------   ---------- ----------  ---------    ------- ------------
                                           (MILLIONS)                                  (MILLIONS)
<S>                         <C>       <C>        <C>       <C>        <C>        <C>          <C>      <C>
Futures and Options NYMEX.      --        16.0     $(1.2)    $(2.0)      17.0       167.0        $5.7     $(1.4)
Physical forwards.........    41.0         9.0     $(2.6)    $12.1       50.0        10.0       $13.5     $13.6
Options-- OTC.............     8.0       803.0    $(19.4)    $18.5       12.0       437.0      $184.2     $68.0
Swaps.....................      --     1,131.0     $23.9      $2.3         --       218.0     $(137.8)   $(42.5)
Emission Allowances.......      --          --      $8.3     $23.8         --          --        $6.0      $9.5
</TABLE>

         We routinely enter into exchange traded futures and options
transactions for electricity and natural gas as part of our energy trading
operations. Generally, exchange-traded futures contracts require deposit of
margin cash, the amount of which is subject to change based on market movement
and in accordance with exchange rules. The amount of the margin deposits as of
December 31, 2001 and 2000 were approximately $2.7 million and $5.8 million,
respectively. For further information regarding our energy trading contracts,
see Note 9. - Financial Information by Business Segments.



DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

         COMMODITY CONTRACTS

         During 2001, we entered into electric physical forward contracts and
gas futures and swaps to hedge our forecasted BGS requirements and gas purchases
requirements for generation. These transactions qualified for hedge accounting
treatment under SFAS 133 and were settled prior to the end of 2001.
Marked-to-market valuations were reclassified from OCI to earnings during the
third quarter ended September 30, 2001. As of December 31, 2001, we


                                       48
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

did not have any outstanding derivatives accounted for under this methodology.
However, there was substantial activity during the year ended December 31, 2001.
In 2001, the values of these forward contracts, gas futures and swaps as of June
30 and September 30 were $(34.2) million and $(0.4) million.

         The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.

         We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.

         The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.

         The measured VAR using a variance/co-variance model with a 95%
confidence level and assuming a one-week time horizon as of December 31, 2001
was approximately $14 million, compared to the December 31, 2000 level of $19
million. This estimate was driven by a conservative assumption that we would
enter into contracts for approximately 50% of its generating capacity during the
BGS auction. Since we obtained contracts in excess of this amount, the VAR at
December 31, 2001 would have been even lower. This estimate, however, is not
necessarily indicative of actual results, which may differ due to the fact that
actual market rate fluctuations may differ from forecasted fluctuations and due
to the fact that the portfolio of hedging instruments may change over the
holding period and due to certain assumptions embedded in the calculation.

         Given the absence of a PJM price cap in situations involving emergency
purchases and the potential for plant outages, extreme price movements, which
have occurred, could have a material adverse impact on our financial condition,
results of operations and net cash flows.

         INTEREST RATE SWAPS

         In October 2001, we entered into three interest rate swaps with an
aggregate notional amount of $177.5 million to hedge the variability of interest
payments related to the construction on our Waterford, Ohio facility. The swaps
qualify for hedge accounting treatment under SFAS 133. As of December 31, 2001,
the related fair value of $2.3 million was recorded on the balance sheet and the
effective portion of the swaps was recorded in OCI. Management expects to
amortize approximately $1.9 million (net of tax of $1.3) from OCI to earnings
during the next 12 months. As of December 31, 2001, there was $1.3 million
remaining in the OCI account.

         In February 2001, we entered into various forward-interest rate swaps,
with an aggregate notional amount of $400 million, to hedge the interest rate
risk related to the anticipated issuance of debt. These fixed swaps paid a fixed
rate of 6%, received 3-month LIBOR, with a maturity date of August 14, 2011. The
original effective date of the swaps was August 14, 2001. On April 11, 2001, we
issued $1.8 billion in fixed-rate Senior Notes and closed out the forward
starting interest rate swaps. The aggregate loss, net of tax, of $3.2 million
was classified as Accumulated Other Comprehensive Loss and is being amortized
and charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects to amortize approximately $0.8 million (net of tax
of $0.3) from OCI to earnings during the next twelve months.

         CREDIT RISK

         Credit risk relates to the risk of loss that we would incur as a result
of non-performance by counterparties, pursuant to the terms of their contractual
obligations. PSEG has established credit policies that it believes significantly
minimize our exposure to credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit rating),
collateral requirements under certain circumstances and the use of standardized
agreements, which may allow for the netting of positive and negative exposures
associated with a single


                                       49
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

counterparty. We also established credit reserves for our energy trading
contracts based on various factors, including individual counterparty's
position, credit rating, default possibility and recovery rates.

         As a result of the BGS auction, we have contracted to provide
generating capacity to the direct suppliers of New Jersey electric utilities,
including PSE&G, commencing August 1, 2002. These bilateral contracts are
subject to credit risk. This credit risk relates to the ability of
counterparties to meet their payment obligations for the power delivered under
each BGS contract. This risk is substantially higher than the risk associated
with potential nonpayment by PSE&G under the BGS contract expiring July 31,
2002. Any failure to collect these payments under the new BGS contracts could
have a material impact on our results of operations, cash flows, and financial
position.

         In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. We entered into a variety of energy
trading contracts with Enron in the PJM area as part of our energy trading
activities. With the first signs of Enron's financial problems, we took steps to
mitigate our exposure to both Enron and other counterparties who had significant
exposures with Enron. As of December 31, 2001, we owed Enron approximately $23
million, net, and Enron held a letter of credit from us for approximately $40
million.

         Two major California utilities, including Pacific Gas & Electric
Company (PG&E), have significantly underrecovered from customers costs paid for
power. As a consequence, these utilities have defaulted under a variety of
contractual obligations and on April 6, 2001, PG&E filed for reorganization
under Chapter 11 of the U.S. Bankruptcy Code. Affiliates of these California
utilities have entered into physical forward and swap contracts with us for
delivery in PJM. These counterparties have met their obligations to date and are
still investment grade entities. We have entered into a limited number of
additional contracts since May 2001 with one of these counterparties, but no
additional contracts have been entered into with the other counterparty since
December 2000. Our exposure to these entities under these contracts is not
material and management does not believe that a specific reserve related to
receivables for these counterparties is presently necessary.

NOTE 5. COMMITMENTS AND CONTINGENT LIABILITIES

NUCLEAR INSURANCE COVERAGES AND ASSESSMENTS

         At December 31, 2001, our insurance coverages and maximum retrospective
assessments for our nuclear operations are as follows:

<TABLE>
<CAPTION>
                                                                        TOTAL SITE               POWER
TYPE AND SOURCE OF COVERAGES                                             COVERAGE             ASSESSMENTS
---------------------------------------------------------------     ------------------    ------------------
<S>                                                                 <C>                   <C>
(Millions of Dollars)
Public and Nuclear Worker Liability (Primary Layer):
       American Nuclear Insurers..............................             $200.0(A)              $10.7
Nuclear Liability (Excess Layer):
       Price-Anderson Act.....................................            9,338.1(B)              277.3
                                                                    ------------------    ------------------
             Nuclear Liability Total..........................           $9,538.1(C)             $288.0
                                                                    ==================    ==================
Property Damage (Primary Layer):
       Nuclear Electric Insurance Limited (NEIL) Primary
(Salem/Hope Creek/Peach Bottom)...............................             $500.0                 $19.3

Property Damage (Excess Layers):
       NEIL II (Salem/Hope Creek/Peach Bottom)................            1,250.0                  13.2
       NEIL Blanket Excess
         (Salem/Hope Creek/Peach Bottom).....................             1,000.0(D)                2.1
                                                                    ------------------    ------------------
       Property Damage Total (Per Site).......................           $2,750.0(E)              $34.6
                                                                    ==================    ==================
Accidental Outage:
       NEIL I (Peach Bottom)..................................             $245.0(F)               $6.0
       NEIL I (Salem).........................................              281.3                   7.7
       NEIL I (Hope Creek)....................................              490.0                   4.9
                                                                    ------------------    ------------------
             Replacement Power Total .........................           $1,016.3(F)              $18.6
                                                                    ==================    ==================
</TABLE>


                                       50
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

(A)  The primary limit for Public Liability is a per site aggregate limit with
     no potential for assessment. The Nuclear Worker Liability represents the
     potential liability from workers claiming exposure to the hazard of nuclear
     radiation. This coverage is subject to an industry aggregate limit,
     includes annual automatic reinstatement if the Industry Credit Rating Plan
     (ICRP) Reserve Fund exceeds $400 million, and has an assessment potential
     under former canceled policies.
(B)  Retrospective premium program under the Price-Anderson liability provisions
     of the Atomic Energy Act of 1954, as amended. Nuclear is subject to
     retrospective assessment with respect to loss from an incident at any
     licensed nuclear reactor in the United States. This retrospective
     assessment can be adjusted for inflation every five years. The last
     adjustment was effective as of August 20, 1998. This retrospective program
     is in excess of the Public and Nuclear Worker Liability primary layers.
(C)  Limit of liability under the Price-Anderson Act for each nuclear incident.
(D)  For property limits excess of $1.75 billion, we participate in a Blanket
     Limit policy where the $1 billion limit is shared by Amergen, Exelon, and
     us among the Clinton, Oyster Creek, TMI-1, Peach Bottom, Salem and Hope
     Creek sites. This limit is not subject to reinstatement in the event of a
     loss. Participation in this program significantly reduces our premium and
     the associated potential assessment.
(E)  Effective January 1, 2002, NEIL II coverage was reduced to $600 million.
(F)  Peach Bottom has an aggregate indemnity limit based on a weekly indemnity
     of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68
     weeks. Salem has an aggregate indemnity limit based on a weekly indemnity
     of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75
     weeks. Hope Creek has an aggregate indemnity limit based on a weekly
     indemnity of $3.5 million for 52 weeks followed by 80% of the weekly
     indemnity for 110 weeks.

         The Price-Anderson Act sets the "limit of liability" for claims that
could arise from an incident involving any licensed nuclear facility in the
nation. The "limit of liability" is based on the number of licensed nuclear
reactors and is adjusted at least every five years based on the Consumer Price
Index. The current "limit of liability" is $9.5 billion. All utilities owning a
nuclear reactor, including us, have provided for this exposure through a
combination of private insurance and mandatory participation in a financial
protection pool as established by the Price-Anderson Act. Under the
Price-Anderson Act, each party with an ownership interest in a nuclear reactor
can be assessed its share of $88.1 million per reactor per incident, payable at
$10 million per reactor per incident per year. If the damages exceed the "limit
of liability," the President is to submit to Congress a plan for providing
additional compensation to the injured parties. Congress could impose further
revenue raising measures on the nuclear industry to pay claims. Our maximum
aggregate assessment per incident is $277.3 million (based on our ownership
interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate
annual assessment per incident is $31.5 million. This does not include the $10.7
million that could be assessed under the nuclear worker policies.

         Additionally, a decision by the U.S. Supreme Court, not involving
Nuclear, has held that the Price-Anderson Act did not preclude awards based on
state law claims for punitive damages.

         We are a member of an industry mutual insurance company, Nuclear
Electric Insurance Limited (NEIL). NEIL provides the primary property and
decontamination liability insurance at Salem/Hope Creek and Peach Bottom. NEIL
also provides excess property insurance through its decontamination liability,
decommissioning liability, and excess property policy and replacement power
coverage through its accidental outage policy. NEIL policies may make
retrospective premium assessments in case of adverse loss experience. Our
maximum potential liabilities under these assessments are included in the table
and notes above. Certain provisions in the NEIL policies provide that the
insurer may suspend coverage with respect to all nuclear units on a site without
notice if the NRC suspends or revokes the operating license for any unit on a
site, issues a shutdown order with respect to such unit or issues a confirmatory
order keeping such unit down.

GUARANTEED OBLIGATIONS

         We have guaranteed certain energy trading contracts of our wholly-owned
subsidiary ER&T. As of December 31, 2001 we have issued or primarily executed
$506 million of guarantees on behalf of ER&T, of which our exposure is $153
million.

HAZARDOUS WASTE

         The NJDEP regulations concerning site investigation and remediation
require an ecological evaluation of potential injuries to natural resources in
connection with a remedial investigation of contaminated sites. The NJDEP


                                       51
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

is presently working with industry to develop procedures for implementing these
regulations. These regulations may substantially increase the costs of remedial
investigations and remediations, where necessary, particularly at sites situated
on surface water bodies. We and our predecessor companies owned and/or operated
certain facilities situated on surface water bodies, certain of which are
currently the subject of remedial activities. We do not anticipate that the
compliance with these regulations will have a material adverse effect on our
financial position, results of operations or net cash flows.

PASSAIC RIVER SITE

         The EPA has determined that a six mile stretch of the Passaic River in
Newark, New Jersey is a "facility" within the meaning of that term under the
Federal Comprehensive Environmental Response, Compensation and Liability Act of
1980 (CERCLA) and that, to date, at least thirteen corporations, including us,
may be potentially liable for performing required remedial actions to address
potential environmental pollution at the Passaic River "facility". In a separate
matter, we and certain of our predecessors operated industrial facilities at
properties within the Passaic River "facility", including the Essex Generating
Station. We cannot predict what action, if any, the EPA or any third party may
take against us with respect to these matters, or in such event, what costs we
may incur to address any such claims. However, such costs may be material.

PREVENTION OF SIGNIFICANT DETERIORATION (PSD)/NEW SOURCE REVIEW(NSR)

         In a response to a demand by the EPA and NJDEP under Section 114 of the
Federal Clean Air Act (CAA) requiring information to assess whether projects
completed since 1978 at the Hudson and Mercer coal burning units were
implemented in accordance with applicable NSR regulations, we provided certain
data in November 2000. In January 2002, we reached an agreement with the state
and federal governments to resolve allegations of noncompliance with federal and
State of New Jersey NSR regulations. Under that agreement, we will install
advanced air pollution controls over 10 years that are expected to dramatically
reduce emissions of NOx, SO2, particulate matter, and mercury from these units.
The estimated cost of the program is $337 million. We also will pay a $1.4
million civil penalty and spend up to $6 million on supplemental environmental
projects.

         The EPA had also asserted that PSD requirements are applicable to
Bergen 2, such that we were required to have obtained a permit before beginning
actual on-site construction. We disputed that PSD requirements were applicable
to Bergen 2. The agreement resolving the NSR allegations concerning Hudson and
Mercer also resolved the dispute over Bergen 2, and allowed construction of the
unit to be completed and operation to commence.

NEW GENERATION AND DEVELOPMENT

         PSEG Power New York Inc., an indirect subsidiary of ours, is in the
process developing the Bethlehem Energy Center, a 750 MW combined-cycle power
plant that will replace the 400 MW Albany Steam Station, which was acquired from
Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000. Pending a final
project certification decision that is expected within 12 months, we will be
obligated to pay Niagara Mohawk up to $9 million. However, we expect this
payment will be reduced based on conditions related to the service date and
regulatory requirements.

         We are constructing a 546 MW natural gas-fired, combined cycle electric
generation plant at Bergen Generation Station at a cost of approximately $290
million with completion expected in June 2002. We are also constructing a 1,218
MW combined cycle generation plant at Linden for approximately $590 million
expected to be completed in May 2003.

         In August 2001, our subsidiaries closed with a group of banks on
$800 million of non-recourse project financing for projects in Waterford, Ohio
and Lawrenceburg, Indiana. The total combined project cost for Waterford and
Lawrenceburg is estimated at $1.2 billion. Our required estimated equity
investments for these projects is approximately $400 million. In connection with
these projects, ER&T has entered into a five-year tolling agreement pursuant to
which it is obligated to purchase the output of these facilities at stated
prices. As a result, ER&T will bear the price risk related to the output of
these generation facilities, which are scheduled to be completed in 2003.


                                       52
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

         We filed an application with the New York State Public Service
Commission for permission to construct and operate a direct generator lead
(dedicated transmission line) that would deliver up to 1,200 MW of electricity
to the West Side of Manhattan from the Bergen Generating Station. Applications
for New Jersey and Federal approvals are expected to be filed in the near
future. Estimated costs are not expected to exceed $100 million for one 500 MW
line.

         In addition, we have other commitments to purchase equipment and
services to meet our current plans to develop additional generating capacity.
The aggregate amount due under these commitments is approximately $500 million.

MINIMUM LEASE PAYMENTS

     We lease administrative office space under various operating leases. As of
December 31, 2001, our rental expense under these leases was approximately $1
million. Total future minimum lease payments as of December 31, 2001 are:

                                   (Millions of Dollars)

2002                                           $1
2003                                            1
2004                                            3
2005                                            1
2006                                            1
Thereafter                                     14
                                       -----------
Total minimum lease payments                  $21
                                       ===========

NOTE 6. NUCLEAR DECOMMISSIONING TRUST

         In accordance with Federal regulations, entities owning an interest in
nuclear generating facilities are required to determine the costs and funding
methods necessary to decommission such facilities upon termination of operation.
As a general practice, each nuclear owner places funds in independent external
trust accounts it maintains to provide for decommissioning. PSE&G currently
recovers from its customers the amounts paid into the trust fund each year and
remits the amounts collected to us for deposit in our Nuclear Decommissioning
Trust (NDT) Fund.

         We have an ownership interest in five nuclear units. In accordance with
rate orders received from the BPU, PSE&G had established an external master
nuclear decommissioning trust for all our nuclear units that were transferred to
us. This trust contains two separate funds: a qualified fund and a non-qualified
fund. Section 468A of the Internal Revenue Code limits the amount of money that
can be contributed into a "qualified" fund. Contributions made into a qualified
fund are tax deductible. In the most recent study, the total cost of
decommissioning its share of these five nuclear units was estimated at $986
million in year end 1995, excluding contingencies.

         Pursuant to the Final Order, PSE&G will collect $29.6 million annually
through the SBC and will remit to us an equivalent amount solely to fund the
trust. The fair market value of these funds as of December 31, 2001 and 2000 was
$817 million and $716 million, respectively.

         Contributions made into the Nuclear Decommissioning Trust Funds are
invested in debt and equity securities. These marketable debt and equity
securities are recorded at amounts that approximate their fair market value.
Those securities have exposure to market price risk. The potential change in
fair value, resulting from a hypothetical 10% change in quoted market prices of
these securities amounts to $82 million. The ownership of the Nuclear
Decommissioning Trust Funds was transferred to us with the transfer of the
generation-related assets from PSE&G.

         With the purchase of Atlantic City Electric Company (ACE)'s interests
in Salem, Peach Bottom and Hope Creek and Delmarva Power and Light Company
(DP&L)'s interest in Salem and Peach Bottom, we received a transfer of $86
million and $50 million representing those companies respective NDT's related to
the stations in 2001 and 2000, respectively.



                                       53
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

NOTE 7. INCOME TAXES

         The following are the components of income tax expense:

                                                        2001     2000    1999
                                                        ----     ----    ----
                                                        (Millions of Dollars)
         Income Taxes:
         -------------
         Current provision--Federal and State           $167     $209     $311
         Provision for deferred income taxes              94       (1)       5
         Purchased State Tax Benefits.......             (11)      --      (21)
         Investment tax credits--net.........             --       --       (4)
                                                        -----    -----    -----
         Total income tax provision.........            $250     $208      $291
                                                        =====    =====    =====

         Reconciliation between total income tax provision and tax computed at
the statutory tax rate on pretax income follows:

<TABLE>
<CAPTION>
                                                                2001     2000    1999
                                                                ----     ----    ----
                                                                (Millions of Dollars)
         <S>                                                   <C>      <C>     <C>
         Tax computed at Federal statutory rate of 35%          $225     $182    $282
         Increase (decrease)attributable to flow-through
              of certain tax adjustments:
           Depreciation--plant related                            --       --      16
           Amortization of investment tax credits                 --       --      (4)
           New Jersey Corporate Business Tax                      24       30      33
           Other                                                   1       (4)    (36)
                                                                ----     ----    ----
             Subtotal                                             25       26       9
                                                                ----     ----    ----
             Total income tax provision                         $250     $208    $291
                                                                ----     ----    ----

         Effective income tax rate                             38.82%   39.92%  36.06%
</TABLE>

         DEFERRED INCOME TAXES

         We provide deferred taxes at the enacted statutory tax rate for all
temporary differences between the financial statement carrying amounts and the
tax bases of existing assets and liabilities.

                                                             2001     2000
                                                         (Millions of Dollars)
         Assets:
           Nuclear Decommissioning                            $25      $ 26
           New Jersey Corporate Business Tax                  137       149
           Plant Related Items                                341       407
           Cost of Removal                                     54        55
           Contractual & Environmental Liabilities             35        35
           Other                                                9         9
                                                             -----    ------
             Total Assets                                    $601      $681

         Liabilities:
           Pension Costs                                      $15      $ --
           Other                                                7         5
                                                             -----    ------
             Total Liabilities                                 22         5
                                                             -----    ------
              Total Deferred Income Tax Asset                $579      $676
                                                             ====     ======


                                       54
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

NOTE 8. PENSION, OTHER POSTRETIREMENT BENEFIT AND SAVINGS PLANS

         Our employees participate in non-contributory pension and other
postretirement benefit plans (OPEB) sponsored by PSEG and administered by PSEG
Services Corporation. In addition, PSEG sponsors two defined contribution plans.
Our represented employees are eligible for participation in the PSEG Employee
Savings Plan (Savings Plan), while our non-represented employees are eligible
for participation in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift
Plan). These plans are 401(k) plans to which eligible employees may contribute
up to 25% of their compensation. Employee contributions up to 7% for Savings
Plan participants and up to 8% for Thrift Plan participants are matched with
employer contributions of cash equal to 50% of such employee contributions
related to employee contributions. Thrift and Savings Plan matching costs
amounted to approximately $8 million for each of the three years ended December
31, 2001. Also, Pension costs amounted to $16 million, $9 million and $24
million for the years ended December 31, 2001, 2000 and 1999, respectively.

         SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other
Than Pensions" (SFAS 106), requires that the expected cost of employees'
postretirement health care and life insurance benefits be charged to income
during the years in which employees render service. Such costs were deferred
through December 31, 1997, pursuant to an order from the BPU. In concert with
the discontinuance of SFAS 71, the portion of the resulting regulatory asset
allocated to us prior to the Transaction remained with PSE&G as recovery of
these previously incurred costs will be through PSE&G's regulated transmission
and distribution operations. OPEB costs amounted to $4 million, $2 million and
$30 million for the years ended December 31, 2001, 2000 and 1999, respectively.

NOTE 9. FINANCIAL INFORMATION BY BUSINESS SEGMENTS

BASIS OF ORGANIZATION

         The reportable segments were determined by Management in accordance
with SFAS 131, "Disclosures About Segments of an Enterprise and Related
Information" (SFAS 131). These segments were determined based on how Management
measures the performance based on segment net income, as illustrated in the
following table, and how it allocates resources to our businesses. Our
organizational structure supports these segments.

GENERATION

         The generation segment of our business earns revenues by selling energy
on a wholesale basis under contract to power marketers and to load serving
entities (LSEs) and by bidding our energy, capacity and ancillary services into
the market.

         Electrical energy is produced by generation plants and is ultimately
delivered to customers for use in lighting, heating and air conditioning and
operation of other electrical equipment. Energy is our principal product and is
priced on a usage basis, typically in cents per thousand Watt-hours (kWh) or
dollars per million Watt-hours (mWh). Capacity, as a product that is distinct
from energy, is a commitment to the ISO that a given unit will be available for
dispatch if it is needed to meet system demand. Capacity is typically priced in
dollars per MW for a given sale period (e.g., mW-day or mW-year). Capacity
generally refers to the power output rating of a generation plant, measured on
an instantaneous basis. Ancillary services constitutes another category of
energy-related activities supplied by generation unit owners to the ISO.

ENERGY TRADING

         The energy trading segment of our business earns revenues by trading
energy, capacity, fixed transmission rights, fuel and emission allowances in the
spot, forward and futures markets. Our energy trading segment also earns
revenues through financial transactions, including swaps, options and futures in
the electricity markets.

         We engage in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights, fuel and emission
allowances in the spot, forward and


                                       55
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

futures markets primarily within PJM, but also throughout the Super Region. We
are also involved in financial transactions that include swaps, options and
futures in the electricity markets. In addition to participating in each of the
major electricity supply and capacity markets in the Super Region, we also
market and trade a broad spectrum of other energy and energy-related products.
These products include coal, oil, natural gas, sulfur dioxide and nitrous oxide
emissions allowances and financial instruments including fixed transmission
rights. Our marketing and energy trading activity for these products extends
throughout the United States and involves physical and financially settled
transactions, futures, options, swaps and basis contracts. None of our trading
revenue with any individual counterparty exceeds 10%.

         We have developed a hedging and overall risk management strategy to
limit our risk exposure and to track our positions in the wholesale markets.
Hedging is used as the primary method for protecting against adverse price
fluctuations and involves taking a position in a related financial instrument
that is designed to offset the risk associated with the original position. We
only use hedging instruments that correspond to the generation, purchase or sale
of electricity and the purchase or sale of fuel.

Information related to the segments of our business is detailed below:

<TABLE>
<CAPTION>
                                                                                             Consolidated
                                                          Generation        Trading              Total
                                                          ----------        -------              -----
                                                                    (Millions of Dollars)
<S>                                                      <C>               <C>              <C>
For the Year Ended December 31, 2001:
------------------------------------
  Total Revenues                                             $2,311          $2,403             $4,714
  Energy Costs                                                  843              --                843
  Trading Costs                                                  --           2,256              2,256
  Depreciation and Amortization                                  95              --                 95
  Interest Income                                                 1              --                  1
  Interest Expense                                              143              --                143
  Operating Income Before Income Taxes                          504             140                644
  Income Taxes                                                  193              57                250
  Net Income                                                    311              83                394

Gross Additions to Property, Plant and Equipment             $1,456              $6             $1,462
                                                             ======              ==             ======
As of December 31, 2001:
------------------------
  Total Assets                                               $4,844            $790             $5,634
                                                             ======            ====             ======
For the Year Ended December 31, 2000:
-------------------------------------
  Total Revenues                                             $2,203          $2,724             $4,927
  Energy Costs                                                  746              --                746

  Trading Costs                                                  --           2,647              2,647
  Depreciation and Amortization                                 136              --                136
  Interest Income                                                 1              --                  1
  Interest Expense                                              198              --                198
  Operating Income Before Income Taxes                          449              72                521
  Income Taxes                                                  179              29                208
  Net Income                                                    270              43                313

  Gross Additions to Property, Plant and Equipment             $479           $  --               $479
                                                               ====           =====               ====
As of December 31, 2000:
------------------------
  Total Assets                                               $3,439          $1,091             $4,530
                                                             ======          ======             ======
</TABLE>



                                       56
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED

<TABLE>
<CAPTION>
For the Year Ended December 31, 1999:
-------------------------------------
<S>                                                           <C>               <C>              <C>
 Total Revenues                                               $2,652            $1,842           $4,494
 Energy Costs                                                    831                --              831
 Trading Costs                                                    --             1,800            1,800
 Depreciation and Amortization                                   224                --              224
 Interest Expense                                                112                --              112
 Operating Income Before Income Taxes                            768                39              807
 Income Taxes                                                    275                16              291
 Income before Extraordinary Item                                493                23              516
 Extraordinary Item  (Net of Tax)                             (3,204)               --           (3,204)
 Net Income (Loss)                                            (2,711)               23           (2,688)
 Gross Additions to Property, Plant and Equipment                $92            $   --              $92
                                                                 ===            ======              ===
</TABLE>

NOTE 10. PROPERTY, PLANT AND EQUIPMENT

Information related to Property, Plant and Equipment is detailed below:

<TABLE>
<CAPTION>
                                                                    December 31,
                                                                    ------------
                                                                 2001          2000
                                                             -----------   -----------
                                                               (Millions of Dollars)
                                                             -------------------------
<S>                                                         <C>              <C>
Property, Plant and Equipment
Plant in Service:
   Fossil Production                                              $1,898        $1,819
   Nuclear Production                                                154           130
                                                             -----------   -----------
Total Plant in Service                                             2,052         1,949
                                                             -----------   -----------

Nuclear Fuel in Service                                              486           417
Construction Work in Progress Including Nuclear Fuel               1,693           311
Other                                                                  7             7
                                                             -----------   -----------
Total                                                             $4,238        $2,684
                                                             ===========   ===========
</TABLE>

         We have ownership interests in and are responsible for providing our
share of the necessary financing for the following jointly owned facilities. All
amounts reflect the share of our jointly owned projects and the corresponding
direct expenses are included in Consolidated Statements of Income as operating
expenses.

<TABLE>
<CAPTION>
                                                   PLANT - DECEMBER 31, 2001      PLANT - DECEMBER 31, 2000
                                                   -------------------------      -------------------------
                                   OWNERSHIP                    ACCUMULATED                    ACCUMULATED
                                   INTEREST         PLANT      DEPRECIATOIN        PLANT      DEPRECIATOIN
                                   ---------       ------      -------------      -------     -------------
<S>                                <C>            <C>         <C>                 <C>         <C>
COAL GENERATING
---------------
   Conemaugh                         22.50%        $199            $70             $199            $63
   Keystone                          22.84%         128             51              122             47

NUCLEAR GENERATING
------------------
   Peach Bottom                      50.00%         249            156               88             10
   Hope Creek                        95.00%(A)       --             --              606            508
   Salem                             57.41%(B)      671            582              645            544
   Nuclear Support Facilities       Various           5              1                5              1

PUMPED STORAGE FACILITY
-----------------------
   Yards Creek                       50.00%          28             12               28             11
   Merrill Creek Reservoir           13.91%           2             --                2             --
</TABLE>

(A) The remaining 5% interest in Hope Creek was acquired in 2001.
(B) An additional 7.41% interest in Salem was acquired in 2001.




                                       57
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED


NOTE 11. SCHEDULE OF LONG-TERM DEBT

<TABLE>
<CAPTION>
                                                                                     December 31,
                                                                       ---------------------------------   Fair Value
Fair Value Interest Rates                           Maturity                2001              2000            2001
-------------------------------------------     ----------------       --------------    --------------- --------------
                                                                              (Millions of Dollars)
<S>                                             <C>                   <C>                <C>             <C>
Senior Notes
6.88%                                                 2006                 $500                $--           $540
7.75%                                                 2011                  800                 --            840
8.63%                                                 2031                  500                 --            562

Pollution Control Notes (A)
5.00%                                                 2012                   66                 --             66
5.50%                                                 2020                   14                 --             14
5.85%                                                 2027                   19                 --             19
5.75%                                                 2031                   25                 --             25

Non-Recourse Debt (B)
Variable                                              2005                  770                 --            770

Note Payable-Affiliated Company                                              --              2,786

                                                                       --------------    --------------- --------------
Principal Amount Outstanding                                              2,694              2,786          2,836
Net Unamortized Discount                                                     (9)                --             --
                                                                       --------------    --------------- --------------
Total Long-Term Debt                                                     $2,685             $2,786          $2,836
                                                                       ==============    =============== ==============
</TABLE>

(A)  On November 20, 2001 and December 5, 2001, we issued a total of $124
     million of Pollution Control Notes in four series with maturities ranging
     from 11 years to 30 years.

(B)  In August 2001, certain of our subsidiaries closed with a group of banks on
     $800 million of non-recourse project financing for projects in Waterford,
     Ohio and Lawrenceburg, Indiana. The total combined project cost for
     Waterford and Lawrenceburg is estimated at $1.2 billion. Our required
     estimated equity investment in these projects is approximately $400
     million. In connection with these projects, ER&T has entered into a
     five-year tolling agreement pursuant to which it is obligated to purchase
     the output of these facilities at stated prices. As a result, ER&T will
     bear the price risk related to the output of these generation facilities
     which are scheduled to be completed in 2003.

NOTE 12. SELECTED QUARTERLY DATA (UNAUDITED)

         The information shown below, in the opinion of management, includes all
adjustments, consisting only of normal recurring accruals, necessary to a fair
presentation of such amounts. Due to the seasonal nature of the generation
business, quarterly amounts can vary significantly during the year.

<TABLE>
<CAPTION>
                                                                  CALENDAR QUARTER ENDED
                                 -----------------------------------------------------------------------------------------
                                     DECEMBER 31,         SEPTEMBER 30,             JUNE 30,              MARCH 31,
                                 --------------------- --------------------- ----------------------- ---------------------
                                   2001       2000       2001       2000       2001        2000        2001       2000
                                 ---------- ---------- ---------- ---------- ---------- ------------ ---------- ----------
                                                               (MILLIONS WHERE APPLICABLE)
<S>                              <C>        <C>        <C>        <C>        <C>        <C>          <C>        <C>
Operating Revenues.........        $1,073     $1,265     $1,321     $1,289     $1,172       $1,229     $1,148     $1,144
Operating Income...........           177        199        173        143        201          134        236        236
Net Income.................           101         64         87         51        104           72        102        126
</TABLE>



                                       58
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED

NOTE 13. RELATED PARTY TRANSACTIONS

PSEG & PSE&G

         In August 2000, PSE&G transferred its electric generating assets to us
in exchange for a $2.786 billion promissory note. Interest on the promissory
note was payable at an annual rate of 14.23%, which represented PSE&G's weighted
average cost of capital. For the period from January 1, 2001 to January 31,
2001, we recorded interest expense of approximately $34 million relating to the
promissory note. We repaid the promissory note on January 31, 2001, with funds
provided from PSEG in the form of equity and loans, including loans of $1.620
billion at various rates for which we recorded interest expense of approximately
$40 million for the period from February 2001 to April 2001, when the loan was
repaid.

         As of December 31, 2001, we also had a payable to PSEG of approximately
$164 million for short term funding needs. Our interest expense related to these
borrowings was $23 million for the year ended December 31, 2001.

         Effective with the asset transfer, we charge PSE&G for a MTC and the
energy and capacity provided to meet PSE&G's BGS requirements. These rates were
established by the BPU. For the years ended December 31, 2001 and 2000, we have
charged PSE&G approximately $2.0 and $0.8 billion, respectively for MTC and BGS.
As of December 31, 2001 and 2000, our receivable from PSE&G relating to these
costs was approximately $159 million and $159 million, respectively. For the
year ended December 31, 2001 and 2000, we purchased energy and capacity from
PSE&G at the market price of approximately $158 million and $78 million,
respectively, which PSE&G purchased under various non-utility generation (NUG)
contracts. As of December 31, 2001 and 2000, our payable to PSE&G relating to
these purchases was approximately $7 million and $17 million, respectively.

PSEG SERVICES CORPORATION

         PSEG Services Corporation provides and bills administrative services to
us on a monthly basis. Our costs related to such services amounted to
approximately $191 million for the year ended December 31, 2001. As of December
31, 2001, our payable related to these costs was approximately $21 million.

TAX SHARING AGREEMENT

         We are a single member limited liability company, wholly owned by PSEG.
PSEG files a consolidated Federal income tax return with its affiliated
companies. A tax allocation agreement exists between PSEG and us and between
PSEG and each of our subsidiaries. The general operation of these agreements is
that the subsidiary company will compute its taxable income on a stand-alone
basis. If the result is a net tax liability, such amount shall be paid to PSEG.
If there are net operating losses and/or tax credits, the subsidiary shall
receive payment for the tax savings from PSEG to the extent that PSEG is able to
utilize those benefits.

THIRD PARTY CONTRACTS

         We enter into a number of contracts with various suppliers, customers
and other counterparties in the ordinary course of business. Certain contracts
were entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, our
Chairman of the Board and Chief Executive Officer, serves on the Board of
Directors of Foster Wheeler. Richard J. Swift, who serves on the Board of
Directors of our parent, PSEG, was President and Chief Executive Officer of
Foster Wheeler Ltd. at the time the contracts were entered into. The aggregate
open commitment under the contracts is for approximately $100 million of
engineering, procurement and construction services related to the development of
certain generating facilities for us. We believe that the contracts were entered
into on commercial terms no more favorable than those available in an
arms-length transaction from other parties and the pricing is consistent with
that available from other third parties.



                                       59
<PAGE>

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED

NOTE 14.  GUARANTEES OF DEBT

         In April 2001, we issued $500 million of 6.875% Senior Notes due 2006,
$800 million of 7.75% Senior Notes due 2011 and $500 million of 8.625% Senior
Notes due 2031. The net proceeds from the sale of the Senior Notes were used
primarily for the repayment of the loans from PSEG. Each series of the Senior
Notes is fully and unconditionally and jointly and severally guaranteed by
Fossil, Nuclear and ER&T. The following table presents condensed financial
information for the the guarantor subsidiaries as well as our non-guarantor
subsidiaries as of December 31, 2001 and 2000 and for the two years then ended.
Prior to the transfer of the generation-related assets in August 2000, all of
our operations were included with PSE&G. Due to the nature of this transfer, all
financial information as of and for the year ended December 31, 1999, and cash
flow information for the year ended December 31, 2000, is not meaningful
disclosure and therefore has been omitted.

<TABLE>
<CAPTION>
                                            -----------------------------------------------------------------------
                                            POWER       GUARANTOR        OTHER       CONSOLIDATING    TOTAL
                                                      SUBSIDIARIES    SUBSIDIARIES    ADJUSTMENTS
-------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 2001
(Millions of Dollars)
-------------------------------------------------------------------------------------------------------------------
<S>                                         <C>         <C>              <C>             <C>        <C>
Revenues                                     $  2        $4,688           $ 24            $  -       $4,714
Operating Expenses                             91         3,797             39               -        3,927
                                            ------       ------          -----          -------      ------
Operating Income (Loss)                       (89)          891            (15)              -          787
Other Income (Loss)                           584            (7)             -            (577)           -
Interest Expense                              192            59           (108)              -          143
Income Taxes                                  (91)          310             31               -          250
                                            -----        ------           ----              --         ----
NET INCOME (LOSS)                            $394         $ 515           $ 62           $(577)        $394
                                             ====         =====           ====           ======        ====
-------------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2001
-------------------------------------------------------------------------------------------------------------------
Current Assets                               $  9         $ 892           $ 64           $ 110       $1,075
Property, Plant and Equipment, net             40         1,992            953               -        2,985
Noncurrent Assets                           2,836           776          1,230          (3,268)       1,574
                                            -----         -----          -----         -------        -----
TOTAL ASSETS                              $ 2,885        $3,660         $2,247         $(3,158)      $5,634
                                          =======        ======         ======         =======       ======
Current Liabilities                          $ 59         $ 631           $216           $ 109      $ 1,015
Noncurrent Liabilities                         30         1,028             16               -        1,074
Note Payable - Affiliated Company              21         1,150              -          (1,171)           -
Long-Term Debt                              1,915             -            770               -        2,685
Member's Equity                               860           851          1,245          (2,006)         860
                                            -----         -----         ------         -------          ---
TOTAL LIABILITIES AND MEMBER'S EQUITY      $2,885        $3,660         $2,247         $(3,160)      $5,634
                                           ======        ======         ======         =======       ======
-------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 2001
-------------------------------------------------------------------------------------------------------------------
Net Cash Provided By (Used In)
  Operating Activities                      $ 313        $1,582          $(989)        $  (507)       $ 399
Net Cash Provided By (Used In)
  Investing Activities                         41          (613)          (947)             10       (1,509)
Net Cash Provided By (Used In)
   Financing Activities                       329        (1,054)         1,936            (112)       1,099
-------------------------------------------------------------------------------------------------------------------
FOR THE YEAR ENDED DECEMBER 31, 2000
-------------------------------------------------------------------------------------------------------------------
Revenues                                       $2        $4,897            $28              $-       $4,927
Operating Expenses                             35         4,144             36               -        4,215
                                           ------        ------         ------         -------       ------
</TABLE>


                                       60
<PAGE>


              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONCLUDED

<TABLE>
<CAPTION>
<S>                                             <C>             <C>          <C>              <C>          <C>
Operating Income (Loss)                             (33)          753             (8)              -          712
Other Income                                        565            (3)             -            (555)           7
Interest Expense                                    153            44              1               -          198
Income Taxes                                         66           142              -               -          208
                                                   ----          ----           ----            ----          ---
NET INCOME (LOSS)                                  $313          $564           $(9)           $(555)       $ 313
                                                   ====          ====           ====           =====        =====
-------------------------------------------------------------------------------------------------------------------
AS OF DECEMBER 31, 2000
-------------------------------------------------------------------------------------------------------------------
Current Assets                                      $11        $1,389            $27              $-       $1,427
Property, Plant and Equipment, net                   43         1,564              7               -        1,614
Noncurrent Assets                                 2,186           714             61          (1,472)       1,489
                                                 ------        ------            ---         -------         ----
TOTAL ASSETS                                     $2,240        $3,667            $95         $(1,472)      $4,530
                                                 ======        ======            ===         =======       ======
Current Liabilities                                $155        $1,249            $60              $6       $1,470
Noncurrent Liabilities                               31           957             18               -        1,006
Note Payable - Affiliated Company                 2,786             -             -              -          2,786
Long-Term Debt                                        -             -              -               -            -
Member's Equity                                    (732)        1,461             17          (1,478)      $(732)
                                                 ------        ------            ---         -------        -----
TOTAL LIABILITIES AND MEMBER'S EQUITY            $2,240        $3,667            $95         $(1,472)      $4,530
                                                 ======        ======            ===         =======       ======
</TABLE>



         There are no restrictions on the ability of our subsidiaries to
transfer funds in the form of dividends, loans or advances to us for the periods
noted above.






                                       61
<PAGE>


                          INDEPENDENT AUDITORS' REPORT

To the Board of Directors
of PSEG Power LLC:

         We have audited the consolidated balance sheets of PSEG Power LLC and
subsidiaries (the "Company") as of December 31, 2001 and 2000, and the related
consolidated statements of income, capitalization and member's equity and cash
flows for each of the three years in the period ended December 31, 2001. Our
audits also included the consolidated financial statement schedule listed in the
Index in Item 14(B)(a). These consolidated financial statements and the
consolidated financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements and consolidated financial statement schedule
based on our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

         In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company as of December
31, 2001 and 2000, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such consolidated financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects, the information set forth therein.

         We have also previously audited, in accordance with auditing standards
generally accepted in the United States of America, the consolidated balance
sheets of the Company as of December 31, 1999, 1998, and 1997, and the related
consolidated statements of income, capitalization and member's equity and cash
flows for the years ended December 31, 1998 and 1997 (none of which are
presented herein) and we expressed unqualified opinions on those consolidated
financial statements.

         In our opinion, the information set forth in the Selected Financial
Data under the caption "Income Statement Data", "Balance Sheet Data", and
Capital Expenditures under the caption "Other Data", for each of the five years
in the period ended December 31, 2001, presented in Item 6, is fairly stated in
all material respects, in relation to the consolidated financial statements from
which it has been derived.


Deloitte & Touche LLP
Parsippany, New Jersey
February 15, 2002




                                       62
<PAGE>



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURES

         None

                                    PART III
                                    --------

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

         PSEG is the sole member of Power's limited liability company and, as
such, has the power to control the election of Power's board of directors and
all other matters submitted for member approval and has control over Power's
management and affairs. Currently, all of Power's directors are officers and
employees of or consultants to PSEG or one of its subsidiaries.

         Power's executive officers and members of Power's board of directors
and their ages as of December 31, 2001 are as follows:

EXECUTIVE OFFICERS

         E. JAMES FERLAND has been Chairman of the Board and Chief Executive
Officer of Power since its formation. Age 59. Mr. Ferland has been Chairman of
the Board, President and Chief Executive Officer of Public Service Enterprise
Group Incorporated since July 1986, Chairman of the Board and Chief Executive
Officer of PSEG Energy Holdings Inc. since June 1989 and Chairman of the Board
and Chief Executive Officer of Public Service Electric and Gas Company since
September 1991.

         FRANK CASSIDY has been President, Chief Operating Officer and a
director of Power since its formation. Age 55. Mr. Cassidy is also a member of
the board of directors of Fossil, Nuclear and ER&T. He served as President and
Chief Operating Officer of PSEG Energy Technologies Inc. from November 1996 to
July 1999. Mr. Cassidy was Senior Vice President -- Fossil Generation of Public
Service Electric and Gas Company from February 1995 to November 1996 and Vice
President -- Transmission Systems of Public Service Electric and Gas Company
from November 1989 to February 1995.

         THOMAS R. SMITH has been Executive Vice President-- Operations and
Development of Power since October 2000. Age 41. Mr. Smith also serves as
President of Fossil and is a member of the board of directors of Fossil, Nuclear
and ER&T. He had been Executive Vice President and Chief Operating Officer of
PSEG Global Inc. from January 2000. Prior to that, he was President of PSEG
Americas, a subsidiary of Global, from November 1996. Before that, he was Senior
Vice President and Regional Executive for Latin America for the International
Generating Company.

         THOMAS M. O'FLYNN has been Executive Vice President and Chief Financial
Officer of Power since March 2002. Age 41. Mr. O'Flynn is also a member of the
board of directors of Power. Mr. O'Flynn has been Executive Vice President
Finance and Chief Financial Officer of Public Service Enterprise Group
Incorporated since July 1, 2001. From December 1997 to May 2001, Mr. O'Flynn was
a Managing Director of Morgan Stanley's Global Power and Utility Investment
Banking Division Group. From January 1994 through December 1997, he was a
Principal of Morgan Stanley's Global Power and Utility Investment Banking
Division Group.

         HAROLD W. BORDEN, JR. has been Vice President and General Counsel of
Power since its formation. Age 57. Mr. Borden is also General Counsel of Fossil,
Nuclear and ER&T. Mr. Borden had been Vice President-- Law of Public Service
Electric and Gas Company from April 1995 to July 1999.

         PATRICIA A. RADO has been Vice President and Controller of Power since
its formation. Age 59. Ms Rado is also Controller of Fossil, Nuclear and ER&T.
Ms. Rado has been Vice President and Controller of Public Service Enterprise
Group and Public Service Electric and Gas Company since April 1993.

         MORTON A. PLAWNER has been Vice President and Treasurer of Power since
its formation. Age 54. Mr. Plawner is also Treasurer of Fossil, Nuclear and
ER&T. Mr. Plawner has been Treasurer of Public Service Enterprise Group and Vice
President and Treasurer of Public Service Electric and Gas Company since January
1,


                                       63
<PAGE>

1998. Prior to that, Mr. Plawner had been General Manager-- Property and Risk
Management of Public Service Electric and Gas Company since 1994 and Risk
Manager since 1989.

DIRECTORS

         ROBERT E. BUSCH has been a director of Power since December 2000. Age
55. Mr. Busch has been President of PSEG Services Corporation since April 2001
and Senior Vice President and Chief Financial Officer of Public Service Electric
and Gas Company since March 1998. From 1997, he was the National Director of the
Hay Group Utility Consulting Practice. From 1996 to 1997, he was a Senior
Consultant for Cambridge Energy Research Associates. Prior to that time, he was
President of the Energy Resources Group of Northeast Utilities.

         ROBERT J. DOUGHERTY, JR. has been a director of Power since its
formation. Age 50. Mr. Dougherty has been President and Chief Operating Officer
of PSEG Energy Holdings Inc. since January 1997. Prior to that, Mr. Dougherty
was president of Enterprise Ventures and Services Corporation.

         ROBERT C. MURRAY has been a director of Power since its formation. Age
55. Mr. Murray is a consultant to Public Service Enterprise Group Incorporated
and was Vice President and Chief Financial Officer of Public Service Enterprise
Group Incorporated from January 1992 through June 2001. Mr. Murray was Executive
Vice President-- Finance of Public Service Electric and Gas Company from June
1997 to June 2000. Mr. Murray was Senior Vice President and Chief Financial
Officer of Public Service Electric and Gas Company from January 1992 to June
1997.

         R. EDWIN SELOVER has been a director of Power since its formation. Age
56. Mr. Selover has been Vice President and General Counsel of Public Service
Enterprise Group since April 1988. Mr. Selover has also been Senior Vice
President and General Counsel of Public Service Electric and Gas Company since
January 1988.

         MICHAEL J. THOMSON has been a director of Power since January 2000. Age
42. Mr. Thomson has been President and Chief Executive Officer of PSEG Global
Inc. since January 1997. Prior to that time he was Senior Vice President, from
July 1993, and Chief Operating Officer, from February 1994, of PSEG Global Inc.

ITEM 11. EXECUTIVE COMPENSATION

         Omitted pursuant to conditions set forth in General Instruction I of
Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

         Omitted pursuant to conditions set forth in General Instruction I of
Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

         Omitted pursuant to conditions set forth in General Instruction I of
Form 10-K.




                                       64
<PAGE>


                                     PART IV
                                     -------

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(A)  Financial Statements:

     a.  Consolidated Statements of Income for the years ended December 31,
         2001, 2000 and 1999 on page 36.

         Consolidated Balance Sheets for the years ended December 31, 2001
         and 2000 on pages 37 and 38.

         Consolidated Statements of Cash Flows for the years ended December
         31, 2001, 2000 and 1999 on page 39.

         Statements of Common Stockholders' Equity for the years ended
         December 31, 2001, 2000 and 1999 on page 40.

         Notes to Consolidated Financial Statements on pages 41 to 61.

(B)  The following documents are filed as a part of this report:

     a.  Financial Statement Schedules:

         Schedule II--Valuation and Qualifying Accounts for each of the three
         years in the period ended December 31, 2001 (page 66)

     Schedules other than those listed above are omitted for the reason that
     they are not required or are not applicable, or the required information
     is shown in the consolidated financial statements or notes thereto.

The following exhibits are filed herewith:

       Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
       Exhibit 21: Subsidiaries of Registrant

         (See Exhibit Index on page 68)

(C)  There were no reports on Form 8-K filed during the last quarter of 2001
     and the 2002 period covered by this report under Item 5:



                                       65

<PAGE>

                                   SCHEDULE II


                                 PSEG POWER LLC
                SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
               YEARS ENDED DECEMBER 31, 2000 -- DECEMBER 31, 1998

<TABLE>
<CAPTION>
                                              COLUMN B               COLUMN C               COLUMN D        COLUMN E
                                            -------------  -----------------------------  -------------   -------------
                                                                    ADDITIONS
                                                           -----------------------------
                                                             CHARGED      CHARGED TO
                                             BALANCE AT    TO COST AND  OTHER ACCOUNTS                     BALANCE AT
                                             BEGINNING                                     DEDUCTIONS        END OF
DESCRIPTION                                  OF PERIOD      EXPENSES       DESCRIBE         DESCRIBE         PERIOD
---------------------------------------------------------  -----------------------------  -------------   -------------
                                                                      (MILLIONS OF DOLLARS)
<S>                                          <C>           <C>            <C>             <C>             <C>
2001:
-----
Materials and Supplies Valuation Reserve            $11             $--             $--         $9(A)               $2

2000:
-----
Materials and Supplies Valuation Reserve            $11             $--             $--        $--                 $11

1999:
-----
Allowance for Doubtful Accounts                     $16             $--             $--        $16(B)              $--
Materials and Supplies Valuation Reserve             12              --              --          1(A)               11
</TABLE>

(A)      Reduced reserve to appropriate level and remove obsolete inventory.
(B)      Accounts Receivable write off.



                                       66
<PAGE>


                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

                                                           PSEG Power LLC

                                               By         E. JAMES FERLAND
                                                  -----------------------------
                                                          E. James Ferland
                                                     Chairman of the Board and
                                                       Chief Executive Officer

Date: March 7, 2002

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

<TABLE>
<CAPTION>
                 Signature                                 Title                                 Date
<S>                                           <C>                                         <C>
              E. JAMES FERLAND                 Chairman of the Board and                     March 7, 2002
--------------------------------------------   Chief Executive Officer and Director
             E. James Ferland                  (Principal Executive Officer)


               FRANK CASSIDY                   President, Chief Operating                    March 7, 2002
--------------------------------------------   Officer and Director
               Frank Cassidy


             THOMAS M. O'FLYNN                 Executive Vice President and Chief            March 7, 2002
--------------------------------------------   Financial Officer and Director
            Thomas M. O'Flynn                  (Principal Financial Officer)


             PATRICIA A. RADO                  Vice President and Controller                 March 7, 2002
--------------------------------------------   (Principal Accounting Officer)
             Patricia A. Rado


              ROBERT E. BUSCH                  Director                                      March 7, 2002
--------------------------------------------
              Robert E. Busch


         ROBERT J. DOUGHERTY, JR.              Director                                      March 7, 2002
--------------------------------------------
         Robert J. Dougherty, Jr.


             ROBERT C. MURRAY                  Director                                      March 7, 2002
--------------------------------------------
             Robert C. Murray


             R. EDWIN SELOVER                  Director                                      March 7, 2002
--------------------------------------------
             R. Edwin Selover


            MICHAEL J. THOMSON                 Director                                      March 7, 2002
--------------------------------------------
            Michael J. Thomson
</TABLE>



                                       67



<PAGE>




EXHIBIT INDEX

     Certain Exhibits previously filed with the Commission and the appropriate
securities exchanges are indicated as set forth below. Such Exhibits are not
being refiled, but are included because inclusion is desirable for convenient
reference.


     3.1*      Certificate of Formation of PSEG Power LLC

     3.2*      PSEG Power LLC Limited Liability Company Agreement

     4.1*      Indenture dated April 16, 2001 between Registrants and The Bank
               of New York and form of Subsidiary Guaranty included therein

      10*      Basic Generation Service Contract with PSE&G


      12       Computation of Ratio of Earnings to Fixed Charges

      21       Subsidiaries of the Registrants

* Filed by Power with Registration Statement No. 333-69228 on Form S-4.