NRG ENERGY INC, S-1/A, 2000-05-08

NRG ENERGY INC
S-1/A, 2000-05-08
ELECTRIC SERVICES

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON MAY 8, 2000

REGISTRATION NO. 333-35096

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

Amendment No. 1

Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------------------
NRG ENERGY, INC.
(Exact name of registrant as specified in its charter)

<TABLE>
<S> <C> <C>
DELAWARE 4911 41-1724239
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer Identification
incorporation or organization) Classification Code Number) No.)
</TABLE>

------------------------------------

1221 NICOLLET MALL, SUITE 700
MINNEAPOLIS, MINNESOTA 55403
(612) 373-5300
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive offices)

JAMES J. BENDER, ESQ.
VICE PRESIDENT, GENERAL COUNSEL AND CORPORATE SECRETARY
NRG ENERGY, INC.
1221 NICOLLET MALL, SUITE 700
MINNEAPOLIS, MINNESOTA 55403
(612) 373-5300
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
------------------------------------
WITH COPIES TO:

<TABLE>
<S> <C>
RICHARD M. RUSSO, ESQ. STACY J. KANTER, ESQ.
GIBSON, DUNN & CRUTCHER LLP SKADDEN, ARPS, SLATE, MEAGHER & FLOM, LLP
1801 CALIFORNIA STREET, SUITE 4100 FOUR TIMES SQUARE
DENVER, COLORADO 80202 NEW YORK, NEW YORK 10036
303-298-5715 212-735-3000
</TABLE>

------------------------------------

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act, check
the following box. [ ]

If this form is filed to register additional securities for an offering pursuant
to Rule 462(b) under the Securities Act, check the following box and list the
Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If this form is a post-effective amendment filed pursuant to Rule 462(d) under
the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434, check
the following box. [ ]

<TABLE>
<CAPTION>
PROPOSED MAXIMUM AMOUNT OF
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE PROPOSED MAXIMUM REGISTRATION
SECURITIES TO BE REGISTERED REGISTERED PER UNIT(1) OFFERING PRICE FEE(2)
--------------------------- ------------ ---------------- ---------------- ------------
<S> <C> <C> <C> <C>
Common stock............................. 32,397,000 $18.52 $600,000,000 $158,400
</TABLE>

(1) Estimated solely for the purpose of computing the registration fee pursuant
to Rule 457(a) under the Securities Act.

(2) Previously paid.

------------------------------------

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES
AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE
A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT
SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE
SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL
BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION (THE
"COMMISSION"), ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 2

THE INFORMATION IN THIS PRELIMINARY PROSPECTUS IS NOT COMPLETE AND MAY BE
CHANGED. THESE SECURITIES MAY NOT BE SOLD UNTIL THE REGISTRATION STATEMENT
FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS
PRELIMINARY PROSPECTUS IS NOT AN OFFER TO SELL NOR DOES IT SEEK AN OFFER TO
BUY THESE SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR SALE IS NOT
PERMITTED.

SUBJECT TO COMPLETION, DATED MAY 8, 2000.

PROSPECTUS

28,170,000 SHARES

NRG ENERGY, INC.
COMMON STOCK

[NRG LOGO] $ PER SHARE
------------------

NRG Energy, Inc. is selling 28,170,000 shares of its common stock. The
underwriters named in this prospectus may purchase up to 4,225,500 additional
shares of common stock from us under certain circumstances.

This is an initial public offering of common stock. We currently expect the
initial public offering price to be between $16.00 and $18.00 per share. We have
applied to have the common stock listed on the New York Stock Exchange under the
symbol "NRG."

The shares of common stock being sold will have one vote per share. The
shares of class A common stock held by our parent company, Northern States Power
Company, are identical to shares of common stock except that they have 10 votes
per share. Upon completion of this offering, Northern States Power will control
approximately 98% of the combined voting power of our common stock and class A
common stock.

------------------

INVESTING IN THE COMMON STOCK INVOLVES CERTAIN RISKS. SEE "RISK FACTORS"
BEGINNING ON PAGE 7.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.

------------------

<TABLE>
<CAPTION>
PER SHARE TOTAL
----------- -----------
<S> <C> <C>
Public Offering Price $ $
Underwriting Discount $ $
Proceeds to NRG Energy, Inc. (before expenses) $ $
</TABLE>

The underwriters are offering the shares subject to various conditions. The
underwriters expect to deliver the shares to purchasers on or about ,
2000.

------------------

SALOMON SMITH BARNEY

------------------

CREDIT SUISSE FIRST BOSTON

ABN AMRO ROTHSCHILD
A DIVISION OF ABN AMRO
INCORPORATED
BANC OF AMERICA SECURITIES LLC

GOLDMAN, SACHS & CO.

LEHMAN BROTHERS

MERRILL LYNCH & CO.

MORGAN STANLEY DEAN WITTER
, 2000
<PAGE> 3

INSIDE FRONT COVER PAGE -- DESCRIPTION OF ARTWORK

NRG logo appears at the top center of the page.

Underneath the NRG logo, text in the center of the page reads: "We are a
leading global energy company engaged in the acquisition, development,
ownership and operation of power generation facilities."

At the bottom center of the page is a bar chart depicting megawatt growth
between the years 1996 and 2000.

INSIDE COVER GATEFOLD -- DESCRIPTION OF ARTWORK

In the center of the page appears a map of the United States with the location
of our facilities noted on the map.

To the left of the United States map appears the following list of project names
and locations: "El Segundo Power", "Encina", "Long Beach Generating", "Crockett
Cogeneration", "San Diego Turbines", Artesia (California Cogen)", "Mt. Poso", "
"San Joaquin Valley Energy" and "Jackson Valley Energy."

Underneath the United States Map appears the following list of project names and
locations: "South Central Region", "Louisiana Generating", "Rocky Road", "Morris
Cogen", "Cogen America Pryor" and "Power Smith Cogeneration."

To the right of the United States map appears the following list of project
names and locations: "Oswego", "Middletown", "Arthur Kill", "Huntley", "Astoria
Gas Turbines", "Dunkirk", "Montville", "Devon", "Norwalk", "Somerset Power",
"Connecticut Remote Jets", "Kingston Cogeneration", "Parlin Cogen", "Cadillac",
"Grays Ferry Cogen", "Newark Cogen", "Penobscot Energy Recovery", "Curtis-Palmer
Hydroelectric", "Philadelphia Cogen", "Maine Energy Recovery" and "Turners
Falls."

At the bottom left corner of the page appears a map of Australia with the
location of our facilities noted on the map.

To the left of the Australia map appears the following list of project names and
locations: "Gladstone Power Station", "Loy Yang Power A" and "Collinsville."

At the bottom right of the page appears a map of Europe with the location of
our facilities noted on the map.

To the left of the Europe map appears the following list of project names and
locations: "Killingholme", "Schkopau", "ECK Generating", "Enfield Energy
Centre", "MIBRAG" and "Energy Center Kladno."
<PAGE> 4

YOU SHOULD RELY ONLY ON INFORMATION CONTAINED IN THIS PROSPECTUS. NRG
ENERGY, INC. HAS NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT
INFORMATION. NRG ENERGY, INC. IS NOT MAKING AN OFFER OF THESE SECURITIES IN ANY
STATE WHERE THE OFFER IS NOT PERMITTED. YOU SHOULD NOT ASSUME THAT THE
INFORMATION PROVIDED BY THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN
THE DATE ON THE FRONT OF THIS PROSPECTUS.

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Summary..................................................... 1
Risk Factors................................................ 7
Use of Proceeds............................................. 18
Dividend Policy............................................. 18
Capitalization.............................................. 19
Selected Consolidated Financial and Other Data.............. 20
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 22
Business.................................................... 32
Management.................................................. 66
Ownership of Capital Stock.................................. 76
Relationships and Related Transactions...................... 77
Description of Capital Stock................................ 79
Description of Indebtedness................................. 83
Shares Eligible for Future Sale............................. 88
Material United States Tax Consequences to
Non-United States
Holders................................................... 89
Underwriting................................................ 91
Legal Matters............................................... 93
Experts..................................................... 93
Available Information....................................... 93
Index to Financial Statements............................... F-1
</TABLE>

<PAGE> 5

SUMMARY

The following summary is qualified in its entirety by, and should be read
together with, the more detailed financial and other information included in
this prospectus. All of the following information reflects our recapitalization,
to be effective immediately prior to this offering, and assumes that the
underwriters have not exercised their option to purchase an additional 4,225,500
shares of common stock within 30 days of the date of this prospectus. Before you
invest in our common stock, you should consider carefully the information
contained in the section entitled "Risk Factors," beginning on page 7.

NRG ENERGY, INC.

NRG Energy, Inc. is a leading global energy company primarily engaged in
the acquisition, development, ownership and operation of power generation
facilities and the sale of energy, capacity and related products. We believe we
are one of the three largest independent power generation companies in the
United States and the sixth largest independent power generation company in the
world, measured by our net ownership interest in power generation facilities. We
own all or a portion of 57 generation projects that have a total generating
capacity of 23,660 megawatts ("MW"); our net ownership interest in those
projects is 13,664 MW. Upon the closing of our pending acquisition from Conectiv
of interests in six power generation facilities, which we expect to occur later
this year, we will have interests in projects having a total generating capacity
of 28,722 MW; our net ownership interest in those projects will be 15,539 MW. In
addition, we have an active acquisition and development program through which we
are pursuing additional generation projects.

As the following table illustrates, we have grown significantly during the
last three years, primarily as a result of our success in acquiring domestic
power generation facilities:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
------- ------- --------
<S> <C> <C> <C>
Net Ownership Interest (in MW at year end)................. 2,637 3,300 10,990
Operating Income (in thousands)............................ $18,109 $57,012 $109,520
</TABLE>

We intend to continue our growth through a combination of targeted
acquisitions in selected core markets, the expansion or repowering of existing
facilities and the development of new greenfield projects. To prepare for
expansion, repowering and greenfield opportunities, we have recently agreed to
purchase 16 turbine generators from GE Power Systems and two turbine generators
from Siemens Westinghouse over a six year period commencing in 2001. These new
turbines, which we expect to install at domestic facilities, will have a
combined generating capacity of approximately 3,300 MW.

In addition to our power generation projects, we also have interests in
district heating and cooling systems and steam transmission operations. Our
thermal and chilled water businesses have a steam and chilled water capacity
equivalent to approximately 1,204 MW. We believe that through our subsidiary NEO
Corporation we are one of the largest landfill gas generation companies in the
United States, extracting methane from landfills to generate electricity. NEO
owns 30 landfill gas collection systems and has 55 MW of net ownership interests
in related electric generation facilities. NEO also has 35 MW of net ownership
interests in 18 small hydroelectric facilities.

MARKET OPPORTUNITY

The power industry is one of the largest industries in the world,
accounting for approximately $200 billion in annual revenues and having
approximately 800,000 MW of installed generating capacity in the United States
alone. The generation segment of the industry historically has been
characterized by regulated electric utilities producing and selling electricity
to a captive customer base. However, the power generation market has been
evolving from a regulated market based upon cost of service pricing to a non-

1
<PAGE> 6

regulated competitive market. We believe that the power industry will continue
to undergo substantial restructuring over the next several years and will
experience significant growth in the future.

As of January 2000, 22 states had enacted legislation to restructure their
electric utility industries, four additional state public utility commissions
had issued comprehensive restructuring orders and 20 additional states had
active legislative or regulatory processes underway to study restructuring and
propose implementing legislation. As a result, from January 1, 1997 through
December 31, 1999, approximately 70,000 MW of the power generating capacity in
the United States had been sold or transferred by regulated electric utilities
to independent power producers. We expect in excess of 70,000 MW of additional
power generating capacity to be sold to independent power producers by the end
of 2002.

We believe that increasing demand and the need to replace old and
inefficient generation facilities will create a significant need for additional
power generating capacity throughout the United States. In our view, these
factors combined with recent restructuring legislation provide an attractive
environment in the United States for an independent power producer like us with
a history of successfully developing, acquiring and operating power generation
facilities.

Outside of the United States, many governments in developed economies are
privatizing their utilities and developing regulatory structures that are
expected to encourage competition in the electricity sector, having realized
that their energy assets can be sold to raise capital without hindering system
reliability. In developing countries, the demand for electricity is expected to
grow rapidly. In order to satisfy this anticipated increase in demand, many
countries have adopted active government programs designed to encourage private
investment in power generation facilities. We believe that these market trends
will continue to create opportunities to acquire and develop power generation
facilities globally.

STRATEGY

Our vision is to be a well-positioned, top three generator of power in
selected core markets. Central to this vision is the pursuit of a well-balanced
generation business diversified in terms of geographic location, fuel type and
dispatch level. Currently, 80% of our generation is located in the United States
in three core markets: our Northeast, South Central and West Coast regions. With
our diversified asset base, we seek to have generating capacity available to
back up any given facility during its outages, whether planned or unplanned,
while having ample resources to take advantage of peak power market price
opportunities and periods of constrained availability of generating capacity,
fuels and transmission.

The following charts illustrate our diversity:

GEOGRAPHIC LOCATION(1)

<TABLE>
<CAPTION>
U.S. EUROPE AUSTRALIA OTHER
- ---- ------ --------- -----
<S> <C> <C> <C>
80 9.00 10.00 1.00
</TABLE>

PRIMARY FUEL TYPE(1)(2)

<TABLE>
<CAPTION>
COAL GAS OIL OTHER
- ---- --- --- -----
<S> <C> <C> <C>
35 37 26 2
</TABLE>

DISPATCH LEVEL(3)

<TABLE>
<CAPTION>
PEAKING INTERMEDIATE BASE-LOAD
- ------- ------------ ---------
<S> <C> <C>
41 19 40
</TABLE>

- ---------------

(1) Based upon MW of net ownership interest as of March 31, 2000.

(2) Several of our generation facilities, constituting approximately 3,900 MW of
generating capacity, are capable of utilizing more than one fuel, which can
be switched as fuel prices fluctuate.

(3) Estimated for 2000 based upon historic dispatch data. We define "base-load"
as facilities that we expect to operate greater than 60% of the year,
"intermediate" as facilities that we expect to operate between 20% and 60%
of the year and "peaking" as facilities that we expect to operate less than
20% of the year, assuming utilization of primary fuel type.

2
<PAGE> 7

site expansion projects and greenfield projects. We believe that our operational
skills and experience give us a strong competitive position in the unregulated
generation marketplace.

We have organized our operations geographically such that inventories,
maintenance, backup power supply and other operational functions are pooled
within a region. This approach enables us to realize cost savings and enhances
our ability to meet our facility availability goals. Our availability goals are
not driven by traditional benchmarks, such as daily or annual availability, but
are focused on each facility's availability during periods when power prices are
significantly above the variable cost of producing power at that
facility -- what we call "in-market" availability.

By leveraging the talents of our regional management teams, focusing on our
regional market expertise and operating experience and utilizing our asset base
on a regional rather than a project basis, we believe we can best position
ourselves for long term profitability. Achieving "critical mass" in core markets
should allow us to capitalize on opportunities available in those markets.

We do not own nor do we have any present intention to own any interest in
nuclear generation facilities.

Domestic. We intend to focus our near-term domestic development and
acquisition plans on our existing three core markets, our Northeast, South
Central and West Coast regions, and to add the Mid-Atlantic region as our fourth
core market upon the closing of our planned acquisition from Conectiv. We will
consider domestic projects outside of these markets if we believe that an
opportunity exists to create a new core market or that the projected returns
from a particular project warrant an investment.

International. Based upon our assessment of market opportunities and our
portfolio risk management criteria, we intend to leverage our reputation,
experience and expertise in order to acquire foreign assets in selected
countries. We are presently focusing our international development and
acquisition activities in the United Kingdom, Central Europe, Turkey, Australia
and, to a lesser extent, Latin America. In the future, we will consider other
areas that are consistent with our strategy.

RECENT DEVELOPMENTS

TURBINE ACQUISITIONS

In February 2000, we executed a memorandum of understanding with GE Power
Systems, a division of General Electric Company, to purchase 11 gas turbine
generators and five steam turbine generators, with an option to purchase
additional units. The purchases will take place over the next five years with
the first delivery scheduled to be made in 2002. The 16 turbines will have an
equivalent generation output of approximately 3,000 MW and an acquisition cost
of approximately $500 million.

In March 2000, we entered into an agreement with Great River Energy under
which Great River assigned to us all of its rights and obligations with respect
to two 135 MW turbines being built for it by Siemens Westinghouse. Our total
cost for the turbines, which are scheduled for delivery in the first or second
quarter of 2001, will be approximately $43 million.

We expect to install the turbines described above at existing plant sites
in the United States as well as new greenfield sites.

RECENT AND PENDING GENERATION ACQUISITIONS

CAJUN FACILITIES

In March 2000, we acquired 1,708 MW of coal and gas-fired generation assets
in Louisiana for approximately $1,026 million. These assets were formerly owned
by Cajun Electric Power Cooperative, Inc., and we refer to them as the "Cajun
facilities." We sell a significant amount of the energy and capacity of the
Cajun facilities to 11 of Cajun Electric's former power cooperative members.
Seven of these cooperatives have entered into 25-year power purchase agreements
with us, and four have entered into two to four year power purchase agreements.
In addition, we sell power under contract to two
3
<PAGE> 8

municipal power authorities and one investor-owned utility that were former
customers of Cajun Electric. We estimate that payments under the contracts with
the 11 cooperatives will account for approximately 72% of the Cajun facilities'
projected 2001 revenues, and that payments under the contracts with the
municipal power authorities and the investor-owned utility will account for
approximately an additional 7% of such revenues.

KILLINGHOLME FACILITY

In March 2000, we acquired the Killingholme A generation facility from
National Power plc for L390 million (approximately $615 million at the time of
the acquisition), subject to post-closing adjustments. Killingholme is a
combined cycle gas-fired baseload facility located in North Lincolnshire,
England. The facility comprises three units with a total generating capacity of
680 MW. We own and operate the facility, which sells its power into the
wholesale electricity market of England and Wales.

CONNECTICUT FACILITIES

In December 1999, we acquired four gas and oil-fired electric generation
facilities and six remote oil-fired turbine facilities from Connecticut Light &
Power Company for approximately $519 million. These facilities are located
throughout Connecticut and have a combined generating capacity of 2,235 MW. In
October 1999, we entered into a four-year standard offer service wholesale sales
agreement with Connecticut Light & Power pursuant to which we are obligated to
supply at fixed prices a portion of its aggregate retail load. The quantity of
power to be supplied is equal to 35% of Connecticut Light & Power's standard
offer service load during calendar year 2000, 40% during calendar years 2001 and
2002, and 45% during calendar year 2003. We estimate that 45% of Connecticut
Light & Power's standard offer service load in 2003 will be approximately 2,000
MW at peak requirement.

CONECTIV FACILITIES

In January 2000, we executed purchase agreements with subsidiaries of
Conectiv to acquire 1,875 MW of coal, gas and oil-fired electric generating
capacity and other assets. We will pay approximately $800 million for the
assets, a portion of which will be financed by project-level debt. The assets
include the BL England and Deepwater facilities in New Jersey, the Indian River
facility in Delaware and the Vienna facility in Maryland, and interests in the
Conemaugh (7.6%) and Keystone (6.2%) facilities in Pennsylvania. The purchase
also includes excess emission allowances. Subject to receipt of required
regulatory approvals, we expect the acquisition to close in the fourth quarter
of 2000. Subject to final documentation, we will sell 500 MW of capacity and
associated energy to a subsidiary of Conectiv under a five-year power purchase
agreement commencing upon the closing of the acquisition.

PROPOSED MERGER OF NORTHERN STATES POWER COMPANY

We have been acquiring and developing power generation projects since 1989,
when we were formed as a wholly-owned subsidiary of Northern States Power
Company, an investor-owned utility that serves customers in the upper Midwest
and owns and operates approximately 7,100 MW of generating capacity. On March
24, 1999, Northern States Power and New Century Energies, Inc., a Colorado-based
public utility holding company, entered into an agreement providing for the
merger of the two companies. Following the merger, Northern States Power's
utility assets will be held in a subsidiary of the surviving corporation in the
merger, which will be renamed "Xcel Energy, Inc.", and the shares of our class A
common stock that will be owned by Northern States Power will be transferred to
a wholly-owned subsidiary of Xcel Energy. The merger has been approved by the
shareholders of both companies and by the Federal Energy Regulatory Commission,
but remains subject to standard closing conditions and other regulatory
approvals. It is currently expected that the merger will be completed in the
second or third quarter of 2000.

CORPORATE INFORMATION

We are incorporated in Delaware and our headquarters and principal
executive offices are located at 1221 Nicollet Mall, Suite 700, Minneapolis,
Minnesota 55403. Our telephone number is (612) 373-5300.

4
<PAGE> 9

THE OFFERING

Common stock offered by NRG... 28,170,000 shares(1)

Common stock to be
outstanding after the
offering.................... 28,170,000 shares(1)(2)

Class A common stock to be
outstanding after the
offering.................... 147,604,500 shares(3)

Total common stock and class
A common stock to be
outstanding after the
offering.................... 175,774,500 shares(1)(2)

Use of proceeds............... To repay $300 million of indebtedness owed to
Citicorp USA, Inc. Remaining proceeds will be
used for general corporate purposes, including
working capital, capital expenditures and
business acquisitions. None of the proceeds
will be distributed to Northern States Power.
See "Use of Proceeds."

Listing....................... We have applied to have the common stock listed
on the NYSE.

Proposed symbol............... "NRG"

- ---------------

(1) Excludes 4,225,500 shares of common stock that the underwriters have an
option to purchase from us within 30 days of the date of this prospectus.

(2) Excludes approximately 5,700,000 shares issuable upon the exercise of stock
options granted to our employees and non-employee directors under the NRG
2000 Long-Term Incentive Compensation Plan.

(3) Shares of class A common stock have 10 votes per share and are convertible
on a share-for-share basis into shares of common stock. Shares of common
stock have one vote per share. In all other respects, shares of class A
common stock and shares of common stock have identical rights and
privileges. All outstanding shares of class A common stock will be held by
Northern States Power.

5
<PAGE> 10

SUMMARY CONSOLIDATED FINANCIAL AND OPERATING DATA

The summary historical financial data set forth below as of December 31,
1997, 1998 and 1999, and for the years then ended, have been derived from our
audited consolidated financial statements. The financial data set forth below as
of March 31, 2000, and for the three-month periods then ended, have been derived
from our unaudited financial statements, which were prepared on a basis
consistent with our audited consolidated financial statements. We have supplied
the selected capacity data set forth below under the caption "Other Generation
Data." All amounts are set forth in thousands, except for net ownership interest
and per share amounts.

<TABLE>
<CAPTION>
YEAR ENDED THREE MONTHS
DECEMBER 31, ENDED MARCH 31,
------------------------------------------------- -------------------
PRO PRO
FORMA FORMA
1997 1998 1999 1999(1) 2000 2000(1)
---------- ---------- ---------- ---------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
CONSOLIDATED INCOME STATEMENT DATA
Revenues from wholly-owned operations............. $ 92,052 $ 100,424 $ 432,518 $ 801,080 $332,671 $412,653
Equity in earnings of unconsolidated affiliates... 26,200 81,706 67,500 67,500 (9,644) (9,644)
Operating income (loss)........................... 18,109 57,012 109,520 189,665 62,937 74,811
Other income (expense)(2)......................... 11,371 9,379 14,970 13,100 (267) 254
Interest expense.................................. (30,989) (50,313) (93,376) (166,624) (52,317) (70,629)
Income tax (benefit) expense(3)................... (23,491) (25,654) (26,081) (24,001) 1,607 (841)
Net income (loss)................................. $ 21,982 $ 41,732 $ 57,195 $ 60,142 $ 8,746 $ 5,277
---------- ---------- ---------- ---------- -------- --------
Earnings per share -- basic and diluted........... $ .15 $ .28 $ .39 $ .41 $ .06 $ .04
Weighted average shares outstanding -- basic and
diluted......................................... 147,605 147,605 147,605 147,605 147,605 147,605
</TABLE>

<TABLE>
<CAPTION>
AS OF AS OF
DECEMBER 31, MARCH 31,
------------------------------------ ----------
1997 1998 1999 2000
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
CONSOLIDATED BALANCE SHEET DATA
Net property, plant and equipment............... $ 185,891 $ 204,729 $1,975,403 $3,669,654
Total assets.................................... 1,168,102 1,293,426 3,431,684 5,293,808
Long-term recourse debt, including current
maturities.................................... 499,982 504,781 915,000 1,169,608
Long-term non-recourse debt, including
current maturities............................ 120,873 121,695 1,056,860 2,325,677
Stockholder's equity............................ 450,698 579,332 893,654 872,120
</TABLE>

- ---------------

(1) The pro forma financial information gives effect to our March 31, 2000
acquisition of the Cajun facilities as if that acquisition had occurred on
January 1, 1999. We do not believe that the pro forma data is indicative of
our future revenues and earnings, because the previous owner of the Cajun
facilities sold energy and capacity and purchased coal upon terms
substantially different from those under which we will operate these
facilities. Thus, we believe the pro forma financial information is of
limited use in making an investment decision.

(2) These amounts include pretax charges of $9.0 million in 1997, $26.7 million
in 1998 and $0 in 1999 to write down the carrying value of certain energy
projects. These amounts also include the pre-tax gain on sale of our
interest in projects of $8.7 million in 1997, $30.0 million in 1998 and
$15.5 million in 1999.

(3) We have substantial tax credits that can be utilized by Northern States
Power. Northern States Power pays us for these tax credits on a quarterly
basis.

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RISK FACTORS

Before you invest in our common stock, you should be aware of the
significant risks described below. You should carefully consider these risks,
together with all of the other information included in this prospectus, before
you decide whether to purchase shares of our common stock.

Some of the information in this prospectus contains forward-looking
statements that involve substantial risks and uncertainties. You can identify
these statements by forward-looking words such as "may," "will," "expect,"
"anticipate," "believe," "estimate" and "continue" or similar words. You should
read statements that contain these words carefully because they: (1) discuss our
future expectations; (2) contain projections of our future results of operations
or of our future financial condition; or (3) state other "forward-looking"
information. We believe that it is important to communicate our future
expectations to our investors. However, our future results and financial
condition will be impacted by events or factors in the future that we have not
been able to accurately predict or over which we have no control.

The risk factors listed in this section, as well as any cautionary language
in this prospectus, provide examples of risks, uncertainties and events that may
cause our actual results to differ materially from the expectations we describe
in our forward-looking statements. Before you invest in our common stock, you
should be aware that the occurrence of the events described in these risk
factors and elsewhere in this prospectus could have a material adverse effect on
our business, financial condition and results of operations and on the price of
our common stock.

RISKS RELATING TO THE WHOLESALE POWER MARKETS

OUR REVENUES ARE NOT PREDICTABLE BECAUSE MANY OF OUR POWER GENERATION
FACILITIES OPERATE, WHOLLY OR PARTIALLY, WITHOUT LONG-TERM POWER PURCHASE
AGREEMENTS.

Historically, substantially all revenues from independent power generation
facilities were derived under power purchase agreements having terms in excess
of 15 years, pursuant to which all energy and capacity was generally sold to a
single party at fixed prices. Because of changes in the industry, the percentage
of facilities, including ours, with these types of long-term power purchase
agreements has decreased, and it is likely that over time, most of our
facilities will operate without these agreements. Without the benefit of these
types of power purchase agreements, we cannot assure you that we will be able to
sell the power generated by our facilities or that our facilities will be able
to operate profitably.

BECAUSE WHOLESALE POWER PRICES ARE SUBJECT TO EXTREME VOLATILITY, THE
REVENUES THAT WE GENERATE ARE SUBJECT TO SIGNIFICANT FLUCTUATIONS.

We must sell all or a portion of the energy, capacity and other products
from many of our facilities into wholesale power markets. The prices of energy
products in those markets are influenced by many factors outside of our control,
including fuel prices, transmission constraints, supply and demand, weather,
economic conditions, and the rules, regulations and actions of the system
operators in those markets. In addition, unlike most other commodities, energy
products cannot be stored and therefore must be produced concurrently with their
use. As a result, the wholesale power markets are subject to significant price
fluctuations over relatively short periods of time and can be unpredictable.

WE HAVE A LIMITED HISTORY OF SELLING AND MARKETING PRODUCTS IN THE
WHOLESALE POWER MARKETS AND MAY NOT BE ABLE TO SUCCESSFULLY MANAGE THE
RISKS ASSOCIATED WITH THIS ASPECT OF OUR BUSINESS.

We are exposed to market risks through our power marketing business, which
involves the establishment of trading positions in the energy, fuel and emission
allowance markets on a short-term basis. We sell forward contracts and options
and establish positions in, and sell on the spot market, our energy, capacity
and other energy products that are not otherwise committed under long-term
contracts. In addition, we use these trading activities to procure fuel and
emission allowances for our facilities on the spot market. We have been managing
risks associated with price volatility in this manner for only a limited amount
of time. We may not be able to effectively manage this price volatility, and may
not be able to

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successfully manage the other risks associated with trading in energy markets,
including the risk that counter parties may not perform.

RISKS RELATING TO OUR OPERATIONS

WE HAVE MADE SUBSTANTIAL INVESTMENTS IN OUR RECENT ACQUISITIONS AND OUR
SUCCESS DEPENDS ON THE APPROPRIATENESS OF THE PRICES WE PAID IN THESE
ACQUISITIONS AS WELL AS ON OUR ABILITY TO SUCCESSFULLY INTEGRATE, OPERATE
AND MANAGE THE ACQUIRED ASSETS.

During the period from December 31, 1998 through March 31, 2000, we have
more than quadrupled our net ownership interests in power generation facilities,
expanding from 3,300 MW of net ownership interests in power generation
facilities to approximately 13,664 MW of net ownership interests. During the
rest of this year, if we complete the pending acquisition from Conectiv, we will
increase our net ownership interests in power generation facilities by an
additional 14%. The prices we paid in these acquisitions were based on our
assumptions as to the economics of operating the acquired facilities and the
prices at which we would be able to sell energy, capacity and other products
from them. If any of the assumptions as to a given facility prove to be
materially inaccurate, it could have a significant impact on the financial
performance of that facility and possibly on our entire company. In connection
with these acquisitions, we have hired and will hire a substantial number of new
employees. We may not be able to successfully integrate all of the newly hired
employees, or profitably integrate, operate, maintain and manage our newly
acquired power generation facilities in a competitive environment. In addition,
operational issues may arise as a result of a lack of integration or our lack of
familiarity with issues specific to a particular facility.

OUR PROJECT DEVELOPMENT AND ACQUISITION ACTIVITIES MAY NOT BE SUCCESSFUL
WHICH WOULD IMPAIR OUR ABILITY TO EXECUTE OUR GROWTH STRATEGY.

We may not be able to identify attractive acquisition or development
opportunities or to complete acquisitions or development projects that we
undertake. If we are not able to identify and complete additional acquisitions
and development projects, we will not be able to successfully execute our growth
strategy. Factors that could cause our acquisition and development activities to
be unsuccessful include the following:

- competition,

- inability to obtain additional capital on acceptable terms,

- inability to obtain required governmental permits and approvals,

- cost-overruns or delays in development that make continuation of a
project impracticable,

- inability to negotiate acceptable acquisition, construction, fuel supply
or other material agreements, and

- inability to hire and retain qualified personnel.

WE INCUR SIGNIFICANT EXPENSES IN EVALUATING POTENTIAL PROJECTS, MOST
OF WHICH ARE NOT ULTIMATELY ACQUIRED OR COMPLETED.

In order to implement our growth strategy, we must continue to actively
pursue acquisition and development opportunities. Substantial expenses are
incurred in investigating and evaluating any potential opportunity before we can
determine whether the opportunity is feasible or economically attractive. In
addition, we expect to participate in many competitive bidding processes for
power generation facilities that require us to incur substantial expenses
without any assurance that our bids will be accepted. As a result, we expect
that our development expenses will increase in the future with no assurance that
we will be successful in acquiring or completing additional new projects.

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CONSTRUCTION, EXPANSION, REFURBISHMENT AND OPERATION OF POWER GENERATION
FACILITIES INVOLVE SIGNIFICANT RISKS THAT CANNOT ALWAYS BE COVERED BY
INSURANCE OR CONTRACTUAL PROTECTIONS.

The construction, expansion and refurbishment of power generation, thermal
energy production and transmission and resource recovery facilities involve many
risks, including:

- supply interruptions,

- work stoppages,

- labor disputes,

- social unrest,

- weather interferences,

- unforeseen engineering, environmental and geological problems, and

- unanticipated cost overruns.

The ongoing operation of these facilities involves all of the risks
described above, in addition to risks relating to the breakdown or failure of
equipment or processes and performance below expected levels of output or
efficiency. New plants may employ recently developed and technologically complex
equipment, especially in the case of newer environmental emission control
technology. While we maintain insurance, obtain warranties from vendors and
obligate contractors to meet certain performance levels, the proceeds of such
insurance, warranties or performance guarantees may not be adequate to cover
lost revenues, increased expenses or liquidated damages payments. Any of these
risks could cause us to operate below expected capacity levels, which in turn
could result in lost revenues, increased expenses, higher maintenance costs and
penalties. As a result, a project may operate at a loss or be unable to fund
principal and interest payments under its project financing agreements, which
may result in a default under that project's indebtedness.

WE ARE EXPOSED TO THE RISK OF FUEL COST INCREASES AND INTERRUPTION IN FUEL
SUPPLY BECAUSE OUR FACILITIES GENERALLY DO NOT HAVE LONG-TERM FUEL SUPPLY
AGREEMENTS.

Most of our domestic power generation facilities that sell energy into the
wholesale power markets purchase fuel under short-term contracts or on the spot
market. Even though we attempt to hedge some portion of our known fuel
requirements, we still may face the risk of supply interruptions and fuel price
volatility. The price we can obtain for the sale of energy may not rise at the
same rate, or may not rise at all, to match a rise in fuel costs. This may have
a material adverse effect on our financial performance.

WE OFTEN RELY ON SINGLE SUPPLIERS AND AT TIMES WE RELY ON SINGLE CUSTOMERS
AT OUR FACILITIES, EXPOSING US TO SIGNIFICANT FINANCIAL RISKS IF EITHER
SHOULD FAIL TO PERFORM THEIR OBLIGATIONS.

We often rely on a single supplier for the provision of fuel, water and
other services required for operation of a facility, and at times, we rely on a
single customer or a few customers to purchase all or a significant portion of a
facility's output, in some cases under long-term agreements that provide the
support for any project debt used to finance the facility. The failure of any
one customer or supplier to fulfill its contractual obligations to the facility
could have a material adverse effect on such facility's financial results.
Consequently, the financial performance of any such facility is dependent on the
continued performance by customers and suppliers of their obligations under
these long-term agreements and, in particular, on the credit quality of the
project's customers and suppliers.

OUR SIGNIFICANT BUSINESS OPERATIONS OUTSIDE THE UNITED STATES EXPOSE US TO
LEGAL, TAX, CURRENCY, INFLATION, CONVERTIBILITY AND REPATRIATION RISKS, AS
WELL AS POTENTIAL CONSTRAINTS ON THE DEVELOPMENT AND OPERATION OF OUR
POTENTIAL BUSINESS, ANY OF WHICH CAN LIMIT THE BENEFITS TO US OF EVEN A
SUCCESSFUL FOREIGN PROJECT.

A key component of our business strategy is the development and acquisition
of projects outside the United States in areas such as the United Kingdom,
Australia, Central Europe and Latin America. The

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economic and political conditions in many of the countries where we have assets
or in which we are or may be exploring development or acquisition opportunities
present many risks. These risks, such as delays in permitting and licensing,
construction delays and interruption of business, as well as risks of war,
expropriation, nationalization, renegotiation or nullification of existing
contracts and changes in law or tax policy are generally greater than risks in
the United States. The uncertainty of the legal environment in certain foreign
countries in which we may develop or acquire projects could make it more
difficult to obtain non-recourse project financing on suitable terms and could
impair our ability to enforce our rights under agreements relating to these
projects.

Operations in foreign countries also can present currency exchange,
inflation, convertibility and repatriation risks. In countries in which we may
develop or acquire projects in the future, economic and monetary conditions and
other factors could affect our ability to convert our earnings to United States
dollars or other acceptable currencies or to move funds offshore from such
countries. Furthermore, the central bank of any foreign country may have the
authority in certain circumstances to suspend, restrict or otherwise impose
conditions on foreign exchange transactions or to approve distributions to
foreign investors. Although we generally seek to structure our power purchase
agreements and other project revenue agreements to provide for payments to be
made in, or indexed to, United States dollars or a currency freely convertible
into United States dollars, we can offer no assurance that we will be able to
achieve this structure in all cases or that a power purchaser or other customer
will be able to obtain acceptable currency to pay their obligations to us.

As part of privatizations or other international acquisition opportunities,
we may make investments in ancillary businesses not directly related to power
generation, thermal energy production and transmission or resource recovery and
in which our management may not have had prior experience. In such cases, our
policy is to invest with partners having the necessary expertise. However, we
can offer no assurance that such persons will be available as co-venturers in
every case. In addition, as a condition to participating in privatizations and
refurbishments of formerly state-owned businesses, we may be required to
undertake transitional obligations relating to union contracts, employment
levels and benefits obligations for employees, which could prevent or delay the
achievement of desirable operating efficiencies and financial performance.

THE LOY YANG FACILITY IN WHICH WE HAVE INVESTED IS EXPERIENCING FINANCIAL
DIFFICULTIES BECAUSE OF LOWER THAN EXPECTED WHOLESALE POWER PRICES, WHICH
COULD RESULT IN AN EVENT OF DEFAULT UNDER ITS LOAN AGREEMENTS.

Energy prices in the Victoria region of the National Electricity Market of
Australia into which our Loy Yang facility sells its power have been
significantly lower than we had expected when we acquired our interest in that
facility. As a result, the Loy Yang project company is currently prohibited by
its loan agreements from making equity distributions to the project owners.
Based on our forecasted power prices, we expect that the Loy Yang project
company will fail to meet required coverage ratios under its loan agreements
beginning in the third quarter of 2001, which constitutes an event of default.
Moreover, if market prices in Victoria continue at current levels, which are
below our forecasted power prices, we expect that the Loy Yang project company
will be unable to service its long-term debt obligations beginning in the first
quarter of 2002. In either case, absent a restructuring of the project company's
debt, the project company's lenders would be allowed to accelerate the project
company's indebtedness. We could be required to write off all or a significant
portion of our current US$250 million investment in this project as a result of
such acceleration, or as a result of a determination by the project company that
a write-down of its assets is required or our determination that we would not be
able to recover our investment in the project.

RISKS RELATING TO OUR CORPORATE AND FINANCIAL STRUCTURE

BECAUSE WE OWN LESS THAN 100% OF SOME OF OUR PROJECT INVESTMENTS, WE CANNOT
EXERCISE COMPLETE CONTROL OVER THEIR OPERATIONS.

We have limited control over the development, construction, acquisition or
operation of some project investments and joint ventures because our investments
are in projects where we beneficially own less than
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50% of the ownership interests. A substantial portion of our future investments
in international projects may also take the form of minority interests. We seek
to exert a degree of influence with respect to the management and operation of
projects in which we own less than 50% of the ownership interests by negotiating
to obtain positions on management committees or to receive certain limited
governance rights such as rights to veto significant actions. However, we may
not always succeed in such negotiations. We may be dependent on our co-venturers
to construct and operate such projects. Our co-venturers may not have the level
of experience, technical expertise, human resources management and other
attributes necessary to construct and operate these projects. The approval of
co-venturers also may be required for us to receive distributions of funds from
projects or to transfer our interest in projects.

WE REQUIRE SIGNIFICANT AMOUNTS OF CAPITAL TO GROW OUR BUSINESS AND OUR
FUTURE ACCESS TO SUCH FUNDS IS UNCERTAIN.

We will require continued access to substantial debt and equity capital
from outside sources on acceptable terms in order to assure the success of
future projects and acquisitions, including the planned Conectiv acquisition.
Our ability to arrange debt financing, either at the corporate level or on a
non-recourse project-level basis and the costs of such capital are dependent on
numerous factors, including:

- general economic and capital market conditions,

- credit availability from banks and other financial institutions,

- investor confidence in us, our partners and the regional wholesale power
markets,

- maintenance of acceptable credit ratings,

- the success of current projects,

- the perceived quality of new projects, and

- provisions of tax and securities laws that may impact raising capital in
this manner.

In order to access capital on a substantially non-recourse basis in the future,
we may have to make larger equity investments in, or provide more financial
support for, our project subsidiaries. We also may not be successful in
structuring future financing for our projects on a substantially non-recourse
basis.

To date, the equity capital for our projects has been provided by equity
contributions from Northern States Power, internally-generated cash flow from
our projects and other borrowings. We cannot assure you that Northern States
Power will continue to provide additional equity capital to us or permit us to
raise additional equity capital from others. Any inability to raise additional
equity capital will restrict our ability to execute our growth strategy.

WE HAVE SUBSTANTIAL INDEBTEDNESS, WHICH COULD LIMIT OUR ABILITY TO GROW AND
OUR FLEXIBILITY IN OPERATING OUR PROJECTS.

As of March 31, 2000, we had total recourse debt of $1,774 million, with an
additional $2,325 million of non-recourse debt appearing on our balance sheet.
The percentage of our total recourse debt to recourse debt and equity was 67.0%
as of March 31, 2000. The substantial amount of debt that we have and the debt
of our project subsidiaries and project affiliates presents the risk that we
might not generate sufficient cash to service our indebtedness, and that our
leveraged capital structure could limit our ability to finance the acquisition
and development of additional projects, to compete effectively, to operate
successfully under adverse economic conditions and to fully implement our
strategy. The terms of our debt and the debt of our project subsidiaries and
project affiliates also restrict our flexibility in operating our projects.

In addition, our lenders may accelerate our credit facilities and public
debt instruments upon the occurrence of events of default or if we undergo a
change of control. Because Northern States Power will control approximately 98%
of the total voting power of our common stock and our class A common stock, we
will have no ability to prevent a change of control. If our indebtedness is
accelerated, we could be forced into bankruptcy, and you could lose your entire
investment.

Although we expect that the cash available from our domestic operations and
the repayment to us of loans made by us to our foreign affiliates will be
sufficient to service our corporate-level indebtedness, there

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can be no assurance that these funds will be sufficient to make corporate-level
debt payments as and when due. If we elect to repatriate cash from foreign
subsidiaries or affiliates to make these payments in case of such a shortfall,
then we may incur United States taxes, net of any available foreign tax credits,
on the repatriation of such foreign cash.

WE HAVE GUARANTEED OBLIGATIONS AND LIABILITIES OF OUR PROJECT SUBSIDIARIES
AND AFFILIATES WHICH WOULD BE DIFFICULT FOR US TO SATISFY IF THEY ALL CAME
DUE SIMULTANEOUSLY.

In many of our projects, we have executed guarantees of the project
affiliate's indebtedness, equity or operating obligations. In addition, in
connection with the purchase and sale of fuel, emission allowances and power
generation products to and from third parties with respect to the operation of
some of our generation facilities, we are required to guarantee a portion of the
obligations of certain of our subsidiaries. These guarantees totaled
approximately $504 million as of March 31, 2000. We may not be able to satisfy
all of these guarantees and other obligations if they were to come due at the
same time, which would have a material adverse effect on us.

OUR HOLDING COMPANY STRUCTURE LIMITS OUR ACCESS TO THE FUNDS OF PROJECT
SUBSIDIARIES AND PROJECT AFFILIATES THAT WE WILL NEED IN ORDER TO SERVICE
OUR CORPORATE-LEVEL INDEBTEDNESS.

Substantially all of our operations are conducted by our project
subsidiaries and project affiliates. Our cash flow and our ability to service
our corporate-level indebtedness when due is dependent upon our receipt of cash
dividends and distributions or other transfers from our projects and other
subsidiaries. The debt agreements of our subsidiaries and project affiliates
generally restrict their ability to pay dividends, make distributions or
otherwise transfer funds to us. In addition, a substantial amount of the assets
of our project subsidiaries and project affiliates has been pledged as
collateral under their debt agreements.

Our project subsidiaries and project affiliates are separate and distinct
legal entities that have no obligation, contingent or otherwise, to pay any
amounts due under our indebtedness or to make any funds available to us, whether
by dividends, loans or other payments, and they do not guarantee the payment of
our corporate-level indebtedness. We own less than 50% of the ownership
interests in many of our foreign projects, and therefore we are unable to
unilaterally cause dividends or distributions to be made from these operations.

WE ARE CONTROLLED BY NORTHERN STATES POWER COMPANY. NORTHERN STATES POWER
MAY NOT ALWAYS EXERCISE ITS CONTROL IN A WAY THAT BENEFITS OUR PUBLIC
STOCKHOLDERS.

Northern States Power will hold approximately 98% of the total voting power
of our common stock and our class A common stock following this offering.
Accordingly, without the approval of the holders of our common stock, Northern
States Power will be able to control the vote on all matters submitted to a vote
of the stockholders and in particular be able to elect all our directors, amend
our certificate of incorporation or effect a merger, sale of assets, or other
major corporate transaction, defeat any non-negotiated takeover attempt,
determine the amount and timing of dividends paid on common stock, and otherwise
control our management and operations and the outcome of all matters submitted
for a stockholder vote. In circumstances involving a conflict of interest
between Northern States Power, as the controlling stockholder, on the one hand,
and our other stockholders on the other, we can offer no assurance that Northern
States Power would not exercise its power to control us in a manner that would
benefit Northern States Power to the detriment of our other stockholders.

In addition, Northern States Power may enter into credit agreements,
indentures or other contracts which limit the activities of its subsidiaries.
While we would not likely be contractually bound by these limitations, Northern
States Power would likely cause its representatives on our board to direct our
business so as not to breach any of these agreements.

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OUR CERTIFICATE OF INCORPORATION AND BYLAW PROVISIONS, AND SEVERAL OTHER
FACTORS, COULD LIMIT ANOTHER PARTY'S ABILITY TO ACQUIRE US AND COULD
DEPRIVE YOU OF THE OPPORTUNITY TO OBTAIN A TAKEOVER PREMIUM FOR YOUR SHARES
OF COMMON STOCK.

A number of provisions that are in our certificate of incorporation and
bylaws will make it difficult for another company to acquire us and for you to
receive any related takeover premium for your shares. For example, our
certificate of incorporation allows our board of directors to issue up to
200,000,000 preferred shares without a stockholder vote and provides that
stockholders may not act by written consent and may not call a special meeting.
In addition, our capital structure may deter a potential change in control,
because our voting power will be concentrated in our class A common stock.

POTENTIAL CONFLICTS OF INTEREST WITH OUR CONTROLLING STOCKHOLDER MAY BE
RESOLVED IN A MANNER THAT IS ADVERSE TO US.

Northern States Power, our controlling stockholder, and directors and
officers of Northern States Power and its subsidiaries who may be our directors,
are in positions involving the possibility of conflicts of interest with respect
to transactions in which both we and Northern States Power have an interest. In
addition, Northern States Power, subject to its fiduciary duties owed to our
minority stockholders, may compete with us for business opportunities that may
be attractive to both us and to Northern States Power. We can offer no assurance
that any such conflict will be resolved in our favor.

THE PENDING MERGER OF NORTHERN STATES POWER AND NEW CENTURY ENERGIES WILL
CONSTRAIN THE CONDUCT OF OUR BUSINESS.

It is expected that the pending merger of Northern States Power and New
Century Energies will be accounted for as a "pooling of interest." In accordance
with the "pooling of interest" rules, neither company can alter their equity
interests or dispose of a material portion of their assets through the date of
the merger and for a period of time thereafter. These constraints may limit our
flexibility to conduct our business as we otherwise would absent such
constraints.

After the merger, the shares of our class A common stock that are owned by
Northern States Power will be owned by a wholly-owned subsidiary of the
surviving corporation in the merger, Xcel Energy. Xcel Energy will be subject to
the provisions of various energy-related laws and regulations, including the
Public Utility Holding Company Act of 1935 ("PUHCA"), and, in turn, we will be
subject to constraints imposed by PUHCA. See "Business -- Energy Regulation in
the United States".

IF NORTHERN STATES POWER COULD NOT CONSOLIDATE US ON THEIR UNITED STATES
FEDERAL INCOME TAX RETURNS, WE COULD LOSE THE REIMBURSEMENT WE RECEIVE FOR
TAX BENEFITS.

We are a member of Northern States Power's consolidated tax group for
purposes of United States federal income taxes. We have generated significant
tax assets in the past from which Northern States Power has been able to
benefit. We received, subject to possible adjustment, $13.4 million for the year
ended December 31, 1999 for the use of such benefits. If Northern States Power
owns common stock or class A common stock representing less than 80% of our
voting power, or equity securities representing less than 80% of our value, or
cannot generate substantial taxable income to utilize such tax benefits, we will
no longer receive a cash reimbursement for these benefits on a dollar-for-dollar
basis and we may not be able to use all of the benefits immediately.

MANY OF OUR INCOME TAX REPORTING POSITIONS HAVE NOT BEEN AUDITED AND COULD
BE DISALLOWED.

In connection with the preparation of Northern States Power's consolidated
income tax returns, we have taken tax positions on many issues, including issues
relating to Section 29 tax credits and international tax structures. Although we
believe that our reporting positions are correct, many of these returns have not
been audited and we cannot assure you that our reporting positions will not be
disallowed.

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RISKS RELATING TO OUR INDUSTRY

OUR BUSINESS IS SUBJECT TO SUBSTANTIAL GOVERNMENTAL REGULATION AND
PERMITTING REQUIREMENTS AND MAY BE ADVERSELY AFFECTED BY ANY FUTURE
INABILITY TO COMPLY WITH EXISTING OR FUTURE REGULATIONS OR REQUIREMENTS.

In General. Our business is subject to extensive energy, environmental and
other laws and regulations of federal, state and local authorities. We generally
are required to obtain and comply with a wide variety of licenses, permits and
other approvals in order to operate our facilities. We may incur significant
additional costs because of our compliance with these requirements. If we fail
to comply with these requirements, we could be subject to civil or criminal
liability and the imposition of liens or fines. In addition, existing
regulations may be revised or reinterpreted, new laws and regulations may be
adopted or become applicable to us or our facilities, and future changes in laws
and regulation may have a detrimental effect on our business. Furthermore, with
the continuing trend toward stricter standards, greater regulation, more
extensive permitting requirements and an increase in the assets we operate, we
expect our environmental expenditures to be substantial in the future.

Energy Regulation. PUHCA and the Federal Power Act ("FPA") regulate public
utility holding companies and their subsidiaries and place certain constraints
on the conduct of their business. The Public Utilities Regulatory Policies Act
of 1978 ("PURPA") provides to qualifying facilities ("QFs") exemptions from
federal and state laws and regulations, including PUHCA and the FPA. The Energy
Policy Act of 1992 also provides relief from regulation under PUHCA to exempt
wholesale generators ("EWGs") and foreign utility companies ("FUCOs").
Maintaining the status of our facilities as QFs, EWGs or FUCOs is conditioned on
their continuing to meet statutory criteria, and could be jeopardized, for
example, by the making of retail sales by an EWG in violation of the
requirements of the Energy Policy Act. Until the completion of the merger
between Northern States Power and New Century Energies, we are not and will not
be subject to regulation as a holding company under PUHCA as long as the
domestic power plants we own are QFs under PURPA or are EWGs, and as long as our
foreign utility operations are exempted as EWGs or FUCOs or are otherwise
exempted under PUHCA; thereafter, we will be subject to the regulations
described in "Business -- Energy Regulation -- United States." These regulations
include restrictions imposed upon aggregate investment by registered holding
companies in EWGs and FUCOs that are financed by contributions or guarantees by
the parent holding company. These investment restrictions, issued pursuant to
SEC regulations, limit registered holding company investment in EWGs and FUCOs
without prior SEC approval to 50% of the registered holding company's
consolidated retained earnings. The existence of such investment cap and the
potential need to request SEC waivers of or increases in the cap could delay or
prevent any infusions of capital from Xcel Energy that it may otherwise desire
to make.

We are continually in the process of obtaining or renewing federal, state
and local approvals required to operate our facilities. Additional regulatory
approvals may be required in the future due to a change in laws and regulations,
a change in our customers or other reasons. We may not always be able to obtain
all required regulatory approvals, and we may not be able to obtain any
necessary modifications to existing regulatory approvals or maintain all
required regulatory approvals. If there is a delay in obtaining any required
regulatory approvals or if we fail to obtain and comply with any required
regulatory approvals, the operation of our facilities or the sale of electricity
to third parties could be prevented or subject to additional costs.

Environmental Regulation. In acquiring many of our facilities, we assumed
on-site liabilities associated with the environmental condition of those
facilities, regardless of when such liabilities arose and whether known or
unknown, and in some cases agreed to indemnify the former owners of those
facilities for on-site environmental liabilities. We may not at all times be in
compliance with all applicable environmental laws and regulations. Steps to
bring our facilities into compliance could be prohibitively expensive, and may
cause us to be unable to pay our debts when due. Moreover, environmental laws
and regulations can change.

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For example, on October 14, 1999, Governor Pataki of New York announced
that he was ordering the New York Department of Environmental Conservation to
require further reductions of sulphur dioxide and nitrogen oxides emissions from
New York power plants, beyond that which is required under current federal and
state law. These reductions would be phased in between January 1, 2003 and
January 1, 2007. Compliance with these emission reductions requirements, if they
become effective, could have a material adverse impact on the operation of some
of our facilities located in the State of New York. In addition, the Connecticut
legislature has in the past considered, but rejected, legislation that would
require older electrical generation stations to comply with more stringent
pollution standards than are currently in effect in Connecticut for nitrogen
oxides and sulphur dioxide emissions. In 1999 and 2000, legislation was proposed
in the Connecticut legislature that could require our Connecticut facilities to
rely on more expensive fuels or install additional air pollution control
equipment. If such legislation were to become law without reflecting the benefit
of critical elements of current federal emission reduction initiatives, such as
market based emission trading between sources located across broad geographic
regions, our Connecticut facilities may be placed at a significant competitive
disadvantage.

We are subject to environmental investigations and lawsuits both on the
state and federal level. For instance, the Office of the Attorney General of the
State of New York and the New York Department of Environmental Conservation are
investigating physical changes made at the Huntley and Dunkirk facilities prior
to our assumption of ownership. The Attorney General has alleged that these
changes represent major modifications undertaken without obtaining the required
permits. Although we have a right to indemnification by the previous owner for
fines, penalties, assessments and related losses resulting from the previous
owner's failure to comply with environmental laws and regulations, if these
facilities did not comply with the applicable permit requirements, we could be
required, among other things, to install specified pollution control technology
to further reduce pollutant emissions from the Dunkirk and Huntley facilities,
and we could become subject to fines and penalties associated with the current
and prior operation of the facilities. See "Business -- Legal Proceedings."

In addition, on November 3, 1999, the United States Department of Justice
filed suit against seven electric utilities for alleged violations of Clean Air
Act requirements related to modifications of existing sources at seventeen
utility generation stations located in the southern and midwestern regions of
the United States. The EPA also issued administrative notices of violation
alleging similar violations at eight other power plants owned by some of the
electric utilities named as defendants in the lawsuit, and also issued an
administrative order to the Tennessee Valley Authority for similar violations at
seven of its power plants. To date, no lawsuits or administrative actions have
been brought against us or any of our subsidiaries or affiliates or the former
owners of our facilities alleging similar violations, although a subsidiary of
Conectiv has received information requests from the EPA regarding the Deepwater
and BL England facilities that we have agreed to purchase. Lawsuits or
administrative actions alleging similar violations at our facilities could be
filed in the future and if successful, could have a material adverse effect on
our business.

OUR COMPETITION IS INCREASING.

The independent power industry is characterized by numerous strong and
capable competitors, some of which may have more extensive operating experience,
more extensive experience in the acquisition and development of power generation
facilities, larger staffs or greater financial resources than we do. Many of our
competitors also are seeking attractive power generation opportunities, both in
the United States and abroad. This competition may adversely affect our ability
to make investments or acquisitions. In recent years, the independent power
industry has been characterized by increased competition for asset purchases and
development opportunities.

In addition, regulatory changes have also been proposed to increase access
to transmission grids by utility and non-utility purchasers and sellers of
electricity. Industry deregulation may encourage the disaggregation of
vertically integrated utilities into separate generation, transmission and
distribution businesses. As a result, significant additional competitors could
become active in the generation segment of our industry.
15
<PAGE> 20

WE FACE ONGOING CHANGES IN THE UNITED STATES UTILITY INDUSTRY THAT COULD
AFFECT OUR COMPETITIVENESS.

The United States electric utility industry is currently experiencing
increasing competitive pressures, primarily in wholesale markets, as a result of
consumer demands, technological advances, greater availability of natural
gas-fired generation that is more efficient than our generation facilities and
other factors. The Federal Energy Regulatory Commission ("FERC") has implemented
and continues to propose regulatory changes to increase access to the nationwide
transmission grid by utility and non-utility purchasers and sellers of
electricity. In addition, a number of states are considering or implementing
methods to introduce and promote retail competition. Recently, some utilities
have brought litigation aimed at forcing the renegotiation or termination of
power purchase agreements requiring payments to owners of QF projects based upon
past estimates of avoided cost that are now substantially in excess of market
prices. In the future, utilities, with the approval of state public utility
commissions, could seek to abrogate their existing power purchase agreements.

Proposals have been introduced in Congress to repeal PURPA and PUHCA, and
FERC has publicly indicated support for the PUHCA repeal effort. If the repeal
of PURPA or PUHCA occurs, either separately or as part of legislation designed
to encourage the broader introduction of wholesale and retail competition, the
significant competitive advantages that independent power producers currently
enjoy over certain regulated utility companies would be eliminated or sharply
curtailed, and the ability of regulated utility companies to compete more
directly with independent power companies would be increased. To the extent
competitive pressures increase and the pricing and sale of electricity assumes
more characteristics of a commodity business, the economics of domestic
independent power generation projects may come under increasing pressure.
Deregulation may not only continue to fuel the current trend toward
consolidation among domestic utilities, but may also encourage the
disaggregation of vertically-integrated utilities into separate generation,
transmission and distribution businesses.

In addition, the independent system operators who oversee most of the
wholesale power markets have in the past imposed, and may in the future continue
to impose, price limitations and other mechanisms to address some of the
volatility in these markets. For example, the independent system operator for
the New York Power Pool has recently imposed price limitations on certain
ancillary services sold in this market, and, together with several New York
utilities, has sought authority from FERC to adjust the market-clearing prices
for certain of these services on a retroactive basis. We have joined several
other independent power producers in New York in filing a claim with FERC
challenging these actions and requests. If our positions do not prevail, our
revenues from ancillary services sold in the New York Power Pool could be
substantially reduced. Although we would attempt to adjust our business
operations to mitigate the future impact of such a ruling, the potential
negative impact on our revenues for the first quarter of 2000 would include the
potential refund of approximately $8.0 million of revenues collected in February
2000 and the inability to collect approximately $8.2 million included in
revenues, but not yet collected, for March 2000.

These types of price limitations and other mechanisms in New York and
elsewhere may adversely impact the profitability of our generation facilities
that sell energy into the wholesale power markets. Given the extreme volatility
and lack of meaningful long-term price history in many of these markets and the
imposition of price limitations by independent system operators, we can offer no
assurance that we will be able to operate profitably in all wholesale power
markets.

RISKS RELATING TO THE MARKET FOR OUR COMMON STOCK

OUR COMMON STOCK WILL HAVE LIMITED VOTING POWER.

Our common stock entitles its holders to one vote for each share, and our
class A common stock entitles its holders to ten votes for each share. Upon
completion of this offering, class A common stock will constitute approximately
84% of our total outstanding common equity and approximately 98% of total voting
power and thus Northern States Power will be able to exercise a controlling
influence over our business.

16
<PAGE> 21

WE CAN OFFER NO ASSURANCE THAT AN ACTIVE PUBLIC MARKET FOR OUR COMMON STOCK
WILL DEVELOP.

Prior to the offering, Northern States Power held all of our outstanding
common stock and therefore there is no public trading market for our common
stock. We have applied to have our common stock approved for listing on the
NYSE. We can offer no assurance that an active public market will develop or
that, if a public market develops, the market price for our common stock will
equal or exceed the public offering price set forth on the cover page of this
prospectus. See "Underwriting."

A SUBSTANTIAL NUMBER OF OUR SHARES WILL BE AVAILABLE FOR FUTURE SALE BY OUR
STOCKHOLDERS, WHICH COULD DEPRESS THE MARKET PRICE OF OUR COMMON STOCK.

Northern States Power will own 147,604,500 shares of class A common stock.
The class A common stock will be convertible into common stock on a
share-for-share basis and will be converted if sold by Northern States Power to
a third party. We have agreed, if so requested by Northern States Power, to file
registration statements and take other steps to enable Northern States Power to
sell any shares of common stock held by it. Northern States Power has agreed
with the underwriters, subject to certain exceptions, not to sell any shares of
common stock for a period of 180 days following the date of this prospectus. Any
sales of substantial amounts of common stock could adversely affect the
prevailing market prices for the common stock. See "Relationships and Related
Transactions", "Shares Eligible for Future Sale" and "Underwriting".

17
<PAGE> 22

USE OF PROCEEDS

The net proceeds from this offering are estimated to be approximately
$449.1 million, assuming an initial public offering price of $17.00 per share.
Approximately $300 million of the net proceeds will be used to repay a loan from
Citicorp USA, Inc., which matures on August 31, 2000 and bears interest at a
floating rate, which at March 31, 2000 was 6.43%. The proceeds from the Citicorp
USA loan were used to fund a portion of the purchase price of the Cajun
facilities acquired by us in March 2000.

The remaining net proceeds will be used for general corporate purposes,
which may include funding of capital expenditures and potential acquisitions,
such as the pending acquisition of generation assets from Conectiv, the
development and construction of new facilities and additions to working capital.
Funds not immediately required for such purposes may be used to temporarily
reduce any outstanding balances under our revolving credit facility. The
majority of the outstanding balance on our revolving credit facility was
borrowed to fund the acquisition of assets from Connecticut Light & Power and
bears interest at a floating rate, which was 7.20% at March 31, 2000.

No proceeds of this offering will be distributed to Northern States Power.

DIVIDEND POLICY

We currently intend to retain future earnings, if any, to fund the
development and growth of our business. Therefore, we do not currently
anticipate paying any cash dividends.

18
<PAGE> 23

CAPITALIZATION

Capitalization is the amount invested in a company and is a common
measurement of a company's size. The table below shows our cash position and
capitalization as of March 31, 2000:

- on an actual basis; and

- on an adjusted basis to give effect to the sale of the 28,170,000 shares
of our common stock offered by this prospectus at an assumed initial
public offering price of $17.00 per share and the application of the net
proceeds from the sale, including the repayment of our $300 million loan
from Citicorp USA, after deducting underwriting discounts and
commissions and estimated offering expenses.

The table below does not reflect options to purchase approximately
5,700,000 shares of our common stock under stock options granted to employees
and non-employee directors under the NRG 2000 Long-Term Incentive Compensation
Plan. You should read this table in conjunction with the consolidated financial
statements and related notes that are included in this prospectus.

<TABLE>
<CAPTION>
MARCH 31, 2000
------------------------
ACTUAL AS ADJUSTED
---------- -----------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents................................... $ 137,923 $ 287,005
========== ==========
Current portion of long-term debt........................... 24,789 24,789
Short-term debt:
Non-recourse (1).......................................... -- --
Recourse(2)............................................... 604,000 304,000
Long-term debt
Non-recourse (1).......................................... 2,300,888 2,300,888
Recourse (2).............................................. 1,169,608 1,169,608
Stockholders' equity:
Preferred stock........................................... -- --
Common stock.............................................. -- 281
Class A common stock...................................... 1,476 1,476
Additional paid-in capital................................ 780,438 1,229,239
Retained earnings......................................... 195,956 195,956
Accumulated other comprehensive income (loss)(3).......... (105,750) (105,750)
---------- ----------
Total stockholders' equity................................ 872,120 1,321,202
---------- ----------
Total capitalization................................... $4,971,405 $5,120,487
========== ==========
</TABLE>

- ---------------
(1) Non-recourse debt is indebtedness incurred by a subsidiary for which there
is no recourse to NRG for repayment.

(2) Recourse debt is a direct corporate-level obligation of NRG.

(3) Represents cumulative currency translation adjustments related to various
international projects. See Note 2 to our Financial Statements.

19
<PAGE> 24

SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA

The selected consolidated financial data set forth below as of December 31,
1995, 1996, 1997, 1998 and 1999 and for the years then ended, have been derived
from our audited consolidated financial statements. The financial data set forth
below as of March 31, 1999 and March 31, 2000, and for the three-month periods
then ended, have been derived from our unaudited financial statements, which
were prepared on a basis consistent with our audited consolidated financial
statements. We have supplied selected capacity and other data set forth below
under the caption "Other Data." All amounts are set forth in thousands, except
per share amounts.

CONSOLIDATED STATEMENTS OF INCOME DATA:

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------------------------- ------------------------------
PRO FORMA PRO FORMA
1995 1996 1997 1998 1999 1999(1) 1999 2000 2000(1)
------- ------- ------- -------- -------- --------- ------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned
operations..................... $64,180 $71,649 $92,052 $100,424 $432,518 $801,080 $37,847 $332,671 $412,653
Equity in earnings of
unconsolidated affiliates...... 28,639 32,815 26,200 81,706 67,500 67,500 8,667 (9,644) (9,644)
------- ------- ------- -------- -------- -------- ------- -------- --------
Total operating revenues......... 92,819 104,464 118,252 182,130 500,018 868,580 46,514 323,027 403,009
OPERATING COSTS AND EXPENSES
Cost of wholly-owned
operations..................... 32,535 36,562 46,717 52,413 269,900 513,944 27,940 214,923 273,551
Depreciation and amortization.... 8,283 8,378 10,310 16,320 37,026 64,595 4,734 19,987 27,044
General, administrative, and
development.................... 34,647 39,248 43,116 56,385 83,572 100,376 15,985 25,180 27,603
------- ------- ------- -------- -------- -------- ------- -------- --------
Total operating costs and
expenses....................... 75,465 84,188 100,143 125,118 390,498 678,915 48,659 260,090 328,198
------- ------- ------- -------- -------- -------- ------- -------- --------
OPERATING INCOME (LOSS).......... 17,354 20,276 18,109 57,012 109,520 189,665 (2,145) 62,937 74,811
OTHER INCOME (EXPENSE)
Minority interest................ -- -- (131) (2,251) (2,456) (2,456) (464) (1,798) (1,798)
Other income, net(2)............. 29,746 9,477 11,502 11,630 17,426 15,556 734 1,531 2,052
Interest expense................. (7,089) (15,430) (30,989) (50,313) (93,376) (166,624) (11,059) (52,317) (70,629)
------- ------- ------- -------- -------- -------- ------- -------- --------
Total other income (expense)..... 22,657 (5,953) (19,618) (40,934) (78,406) (153,524) (10,789) (52,584) (70,375)
------- ------- ------- -------- -------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME
TAXES.......................... 40,011 14,323 (1,509) 16,078 31,114 36,141 (12,934) 10,353 4,436
INCOME TAX (BENEFIT)
EXPENSE(3)..................... 8,810 (5,655) (23,491) (25,654) (26,081) (24,001) (11,994) 1,607 (841)
------- ------- ------- -------- -------- -------- ------- -------- --------
NET INCOME (LOSS)................ $31,201 $19,978 $21,982 $ 41,732 $ 57,195 $ 60,142 $ (940) 8,746 5,277
======= ======= ======= ======== ======== ======== ======= ======== ========
Earnings (loss) per share --basic
and diluted.................... $ .21 $ .14 $ .15 $ .28 $ .39 $ .41 $ (.01) $ .06 $ .04
Weighted average shares
outstanding -- basic and
diluted........................ 147,605 147,605 147,605 147,605 147,605 147,605 147,605 147,605 147,605
</TABLE>

CONSOLIDATED BALANCE SHEET DATA:

<TABLE>
<CAPTION>
AS OF
AS OF DECEMBER 31, MARCH 31,
---------------------------------------------------------- -----------------------
1995 1996 1997 1998 1999 1999 2000
-------- -------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Net property, plant and
equipment.................... $111,919 $129,649 $ 185,891 $ 204,729 $1,975,403 $ 207,473 $3,669,654
Net equity investments in
projects..................... 221,129 365,749 694,655 800,924 932,591 814,807 893,303
Total assets................... 454,589 680,809 1,168,102 1,293,426 3,431,684 1,298,679 5,293,808
Long-term debt, including
current maturities........... 90,034 212,141 620,855 626,476 1,971,860 498,019 3,495,285
Stockholder's equity........... 319,764 421,914 450,698 579,332 893,654 680,017 872,120
</TABLE>

20
<PAGE> 25

OTHER DATA:

<TABLE>
<CAPTION>
AS OF AND FOR THE
AS OF AND FOR THE YEAR ENDED THREE MONTHS
DECEMBER 31, ENDED MARCH 31,
------------------------------------------- -----------------
1995 1996 1997 1998 1999 2000
------ ------ ------ ------ ------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Consolidated EBITDA(4)..................................... 55,383 38,131 39,790 82,711 161,516 82,657
Total debt to total capitalization ratio................... 22.0% 33.5% 57.9% 52.0% 72.4% 82.5%
Ratio of recourse debt to recourse debt and equity......... 5.4% 30.9% 52.6% 46.6% 58.4% 67.0%
Consolidated interest expense coverage ratio(5)............ 7.81x 2.47x 1.28x 1.64x 1.72x 1.58x
Power generation capacity (MW), net........................ 999 1,326 2,637 3,300 10,990 13,664
Thermal energy generation capacity:
mmBtus per hour, net..................................... 2,318 2,654 2,693 2,905 3,400 3,400
MW equivalent, net(6).................................... 812 917 950 1,012 1,204 1,204
</TABLE>

- ---------------

(2) These amounts include equity in gain from project termination settlements in
1995 of $29.9 million related to the settlement and termination of the San
Joaquin Valley power purchase agreements with Pacific Gas & Electric, and
include pretax charges of $5.0 million in 1995, $1.5 million in 1996, $9.0
million in 1997, $26.7 million in 1998 and $0 in 1999, to write down the
carrying value of certain energy projects. These amounts also include the
gain on sale of interest in projects of $8.7 million in 1997, $30.0 million
in 1998 and $15.5 million in 1999.

(3) We are included in the consolidated federal income tax and state franchise
tax returns of Northern States Power. We calculate our tax position on a
separate company basis under a tax sharing agreement with Northern States
Power and receive payment from Northern States Power for tax benefits and
pay Northern States Power for tax liabilities.

(4) EBITDA is the sum of income (loss) before income taxes, interest expense
(net of capitalized interest) and depreciation and amortization expense.
EBITDA is a measure of financial performance not defined under generally
accepted accounting principles, which you should not consider in isolation
or as a substitute for net income, cash flows from operations or other
income or cash flow data prepared in accordance with generally accepted
accounting principles or as a measure of a company's profitability or
liquidity. In addition, EBITDA may not be comparable to similarly titled
measures presented by other companies and could be misleading because all
companies and analysts do not calculate it in the same fashion.

(5) This coverage ratio equals EBITDA divided by interest expense.

(6) Our conversion of thermal generation capacity to MW from British thermal
units per hour is based upon the thermal constant of 3,412.14 British
thermal units per hour per kilowatt hour. Our conversion of chilled water
capacity to MW is based upon 12,000 British thermal units per hour per ton
of chilled water capacity, as well as the thermal constant of 3,412.14
British thermal units per hour per kilowatt hour.

21
<PAGE> 26

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

You should read the following in conjunction with our consolidated
financial statements and notes thereto, "Risk Factors," and "Selected
Consolidated Financial and Other Data," included elsewhere in this prospectus. A
complete listing of our projects that are discussed in this section is set forth
on the inside back cover of this prospectus.

OVERVIEW

We are a leading global energy company primarily engaged in the
acquisition, development, ownership and operation of power generation facilities
and the sale of energy, capacity and related products. We have grown
significantly during the last three years. During this period, we have grown
from a company deriving most of our revenues from power generation facilities in
which we owned less than a 50% interest and from heating, cooling and thermal
activities, to one of the largest independent power generation companies in the
United States (measured by our net ownership interests in power generation
projects), deriving over 78% of our revenues from our wholly-owned power
generation facilities in 1999.

Since January 1, 1997, we have acquired 12,338 MW of net ownership
interests in power generation facilities. During 1997, we acquired 1,311 MW of
net ownership interests in power generation facilities, primarily as a result of
our acquisition of interests in Crockett Cogeneration and other projects. In
1998, we acquired a 50% interest in 1,218 MW of generating capacity in Southern
California. Since January 1, 1999, we have acquired an additional 6,980 MW of
100% owned generating capacity in the Northeast United States, 680 MW of 100%
owned generating capacity in the United Kingdom and 1,708 MW of 100% owned
generating capacity in Louisiana. We intend to continue growing through targeted
acquisitions, repowering and the expansion of existing facilities and the
development of new greenfield projects.

Source of Revenues and Equity in Earnings of Unconsolidated Affiliates. Our
operating revenues and expenses are primarily related to the operations of our
controlled subsidiaries, which are consolidated for accounting purposes.
Significant consolidated subsidiaries include NRG Northeast Generating LLC, NRG
South Central Generating LLC, NEO Corporation, NRG Thermal, Inc., and Crockett
Cogeneration. Investments in project companies over which we exercise
significant influence, but do not control, are accounted for using the equity
method of accounting. The operating results of these entities are reflected in
total operating revenues in the form of equity in earnings of affiliates.
Significant investments accounted for using the equity method include MIBRAG,
Gladstone, Schkopau, Loy Yang, COBEE, West Coast Power LLC, Energy Developments
Limited and ECK Generating. In 1999, we consolidated our Pittsburgh and San
Francisco thermal operations and Crockett Cogeneration, which we previously
accounted for using the equity method.

Our operating revenues are derived primarily from the sale of electrical
energy, capacity and other energy products from our power generation facilities.
Revenues from these facilities are received pursuant to:

- long-term contracts of more than one year including:

- power purchase agreements with utilities and other third parties
(generally 2-25 years);

- standard offer agreements to provide load serving entities with a
percentage of their requirements (generally 4-9 years); and

- "transition" power purchase agreements with the former owners of
acquired facilities
(generally 3-5 years).

- short-term contracts or other commitments of one year or less and spot
sales including:

- spot market and other sales into various wholesale power markets; and

- bilateral contracts with third parties.

22
<PAGE> 27

The following charts illustrate the sources of our domestic power
generation revenue (excluding thermal and resource recovery revenues and the
revenues of NEO Corporation) and equity in earnings of international affiliates
engaged in power generation for the year ended December 31, 1999:

DOMESTIC

<TABLE>
<CAPTION>
LONG TERM SHORT TERM
- --------- ----------
<S> <C>
73 27
</TABLE>

INTERNATIONAL(1)

<TABLE>
<CAPTION>
LONG TERM SHORT TERM
- --------- ----------
<S> <C>
96 4
</TABLE>

- ---------------
(1) Consists solely of equity in earnings of international affiliates.

Operating Costs and Expenses. The principal costs and expenses of our
operations are fuel used to generate energy, labor to operate and maintain our
facilities, depreciation and amortization, general and administrative costs and
development expenses.

Seasonality. Demand for energy as well as energy and capacity prices tend
to be higher in peak market periods, which are dictated by weather patterns. As
a result of a portfolio consisting of assets predominantly located in the United
States, we expect our revenues and profitability to be highest during the third
quarter of the calendar year.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2000 COMPARED TO THREE MONTHS ENDED MARCH 31,
1999

Revenues. For the quarter ended March 31, 2000, we had total revenues of
$323.0 million, which includes operating revenues and equity in earnings of
unconsolidated affiliates, compared to $46.5 million for the quarter ended March
31, 1999, an increase of $276.5 million or 594.5%. Our operating revenues from
wholly-owned operations were $332.7 million, an increase of $294.8 million or
780%, over the same period in 1999. Revenues from our Northeast assets that were
acquired during 1999 accounted for approximately $228.0 million of this
increase. Approximately $35.8 million of the increase was due to a tolling
agreement related to the Killingholme facility, which was in effect from January
1, 2000 to the date of our acquisition of this facility, March 29, 2000. Also,
the acquisition of additional ownership interests in, and the resulting
consolidation of, our Pittsburgh and San Francisco thermal operations together
with the consolidation of Crockett Cogeneration accounted for approximately
$25.5 million of the increase in revenues. For the quarter ended March 31, 2000,
revenues from wholly owned operations consisted of revenue from electrical
generation (92.4%), heating, cooling and thermal activities (6.5%) and technical
services (1.1%).

Equity in losses of unconsolidated project affiliates was $9.6 million for
the quarter ended March 31, 2000, compared to earnings of $8.7 million for the
quarter ended March 31, 1999, a decrease of 211%. Reduced earnings from our
investment in West Coast Power LLC accounted for $11.1 million of the decrease.
The West Coast Power LLC results were down due to interest on project level debt
that was issued in June 1999, a favorable business interruption insurance
settlement that was recorded in the first quarter of 1999, and costs associated
with the Encina facility and the San Diego combustion turbines, which are summer
peaking facilities that were acquired in May 1999. In addition, equity earnings
from NEO decreased by $2.4 million primarily due to operating losses from a
project that was acquired in October 1999. This project produces a net profit
for us after consideration of Section 29 credits, which are included in income
taxes. Equity earnings from the Loy Yang project decreased by $2.4 million due
to a

23
<PAGE> 28

change in accounting for tax benefits associated with the project. Equity
earnings were also reduced by the consolidation of our Pittsburgh and San
Francisco thermal operations and Crockett Cogeneration subsidiaries during 1999.

Operating Costs and Expenses. Cost of wholly-owned operations was $214.9
million for the quarter, an increase of $187.0 million, or 669.2%, over the same
period in 1999. Approximately $146 million of the increase was due to the
acquisition of our Northeast assets during 1999. The remaining increase was
primarily due to the consolidation of Crockett Cogeneration and the Pittsburgh
and San Francisco thermal operations. Cost of operations, as a percentage of
revenues from wholly-owned operations for the period, was 64.6% which is 12.6%
less then the prior year period.

Our depreciation and amortization costs were $20.0 million for the quarter
ended March 31, 2000, compared to $4.7 million for the quarter ended March 31,
1999. The increase resulted primarily from the addition of our Northeast assets
during 1999 and the acquisition of additional ownership interests in, and the
resulting consolidation of, our Pittsburgh and San Francisco thermal operations,
together with the consolidation of Crockett Cogeneration, which contributed to
the increase in depreciation and amortization.

Our general, administrative and development costs were $25.2 million for
the quarter ended March 31, 2000, compared to $16.0 million for the quarter
ended March 31, 1999. The $9.2 million increase is due primarily to increased
business development, associated legal, technical, and accounting expenses,
employees and equipment resulting from expanded operations and preparation for
several acquisitions that took place in 1999 and during the first quarter of
2000. As a percent of total revenues, administrative and general expenses
declined to 7.8% from 34.4% during the same period one-year earlier.

Other Income (Expense). Other expense was $52.6 million for the quarter,
compared with $10.8 million for the same period in 1999. The increase in Other
Expense was primarily due to an increase in interest expense, which was $52.3
million for the quarter, compared to $11.0 million for the quarter ended March
31, 1999. We added $750 million of project level debt related to our Northeast
asset acquisitions resulting in $18.2 million of incremental interest expense.
In addition, we issued $300 million of senior notes in June 1999 and $240
million of senior notes in November 1999. Also, a higher average outstanding
balance of our revolving line of credit and the consolidation of Crockett
Cogeneration and our Pittsburgh and San Francisco thermal operations contributed
to higher interest expense.

Income Tax. Because we are included in the consolidated federal income tax
return of Northern States Power, we pay to and we are paid by Northern States
Power on a dollar-for-dollar basis for the increase or reduction, respectively,
of Northern States Power's taxes attributable to the respective tax liabilities
or benefits we create. Income tax expense was $1.6 million for the quarter ended
March 31, 2000, compared to an income tax benefit of $12.0 million for the
quarter ended March 31, 1999. The increase in income tax expense was primarily
due to higher United States taxable income versus foreign taxable income. In
addition, we no longer recognized the tax benefits related to the losses
generated by the Loy Yang facility. This increase in tax expense was partially
offset by additional Section 29 tax credits generated by growth in NEO's
portfolio of landfill gas projects.

Net Income. Net income for the quarter ended March 31, 2000, was $8.7
million, an increase of $9.7 million compared to net loss of $0.9 million in the
same period in 1999. This increase was due to the factors described above.

The independent system operator for the New York Power Pool has recently
sought authority from FERC to adjust the market-clearing prices for certain
ancillary services on a retroactive basis beginning January 29, 2000. We and
several other independent power producers are challenging this action. If the
independent system operator prevails, our revenues from ancillary services sold
in the New York Power Pool could be substantially reduced. Although we would
attempt to adjust our business operations to mitigate the future impact of such
a ruling, the potential negative impact on our revenues for the first quarter of
2000 would include the potential refund of approximately $8.0 million of
revenues collected in February 2000 and the inability to collect approximately
$8.2 million included in revenues, but not yet collected, for March 2000.

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<PAGE> 29

FISCAL YEAR ENDED DECEMBER 31, 1999 COMPARED TO FISCAL YEAR ENDED DECEMBER
31, 1998

Revenues. For the year ended December 31, 1999, we had total revenues of
$500.0 million, which includes operating revenues and equity in earnings of
unconsolidated affiliates, compared to $182.1 million for the year ended
December 31, 1998, an increase of $317.9 million or 174.5%. Our operating
revenues from wholly-owned operations were $432.5 million, an increase of $332.1
million, or 330.7%, over the same period in 1998. Revenues from our Northeast
assets that were acquired during 1999 accounted for approximately $303.6 million
of this increase. In 1999, the acquisition of additional ownership interests in,
and resulting consolidation of, our Pittsburgh and San Francisco thermal
operations, together with the consolidation of Crockett Cogeneration, accounted
for approximately $29.1 million of the increase in revenues. In 1999, operating
revenues from wholly-owned operations consisted of revenue from electrical
generation (78.3%), heating, cooling and thermal activities (17.6%) and
technical services (4.1%), and in 1998, they consisted of operating revenue from
electrical generation (46.2%), heating, cooling and thermal activities (46.0%)
and technical services (7.8%).

For 1999, our equity in earnings of unconsolidated affiliates was $67.5
million, compared to $81.7 million for 1998, a decrease of $14.2 million or
17.4%. This change was primarily the result of a cooler summer in the western
region of the United States in 1999 and financing costs related to our El
Segundo and Long Beach generation facilities, which accounted for a $12.8
million reduction in equity in earnings from these affiliates. Lower earnings at
Mt. Poso, together with the consolidation of our Pittsburgh and San Francisco
thermal operations and Crockett Cogeneration also contributed to the decrease in
equity in earnings during 1999. These decreases were partially offset by
increased earnings from MIBRAG and a favorable legal settlement at one of our
affiliates.

Operating Costs and Expenses. For 1999, our cost of wholly-owned
operations was $269.9 million, compared to $52.4 million in 1998, an increase of
$217.5 million or 415%. Costs associated with the ownership and operation of our
Northeast assets that were acquired during 1999 accounted for approximately
$194.9 million of the $269.9 million. The remaining increase resulted from the
consolidation of our Pittsburgh and San Francisco thermal operations and
Crockett Cogeneration. Increases also resulted from the addition of new projects
during 1999 by NEO.

Our depreciation and amortization costs were $37.0 million for 1999,
compared to $16.3 million for 1998, an increase of $20.7 million or 127%. This
increase resulted primarily from the addition of our Northeast assets and the
addition of new projects by NEO. The acquisition of additional ownership
interests in, and resulting consolidation of, our Pittsburgh and San Francisco
thermal operations, together with the consolidation of Crockett Cogeneration,
also contributed to the increase in depreciation and amortization.

Our general and administrative costs were $59.9 million for 1999, compared
to $42.0 million for 1998, an increase of $17.9 million or 43%. Approximately
$7.8 million of the increase was a direct result of the ownership and operation
of our Northeast assets during 1999. The remaining increase was due primarily to
the consolidation of certain affiliates described above, which were previously
accounted for using the equity method, and an overall increase in legal,
technical and accounting support resulting from expanded operations.

Our development expenses were $23.7 million for 1999, compared to $14.4
million for 1998, an increase of $9.3 million or 65%. Our development expenses
include development office costs, internal personnel costs, and fees paid to
outside service providers in connection with the pursuit of new investment
opportunities. The 1999 increase was due primarily to the pursuit of a greater
number of potential opportunities during the year.

Other Income (Expense). Minority interest in projects was $2.5 million for
1999 compared to $2.3 million for 1998. Minority interest relates to projects
that were acquired in November 1997 and thermal operations in which we have a
minority interest.

Other income, net was $17.4 million in 1999 compared to $11.6 million in
1998, an increase of $5.8 million or 50%. This increase was primarily the result
of the 1999 pretax gain of $11.0 million on the
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<PAGE> 30

sell-down of our ownership interest in Cogeneration Corporation of America from
approximately 45% to 20%. This increase was offset in part by a $2.0 million
reclassification of management fees from income to equity in earnings of
unconsolidated subsidiaries, compared to a 1998 $29.9 million gain from sale of
interests in projects, offset in part by a $26.7 million write down of the
carrying value of other projects. The 1998 charges included a $22.0 million
write off of our entire investment, which included development expenses as well
as fees incurred in connection with the termination of an interest rate hedge,
in a project we were pursuing in West Java, Indonesia. This write off was due to
uncertainties surrounding infrastructure projects in Indonesia.

Interest expense was $93.4 million for 1999 compared with $50.3 million for
1998, an increase of $43.1 million or 86%. The increase in interest expense
primarily resulted from the acquisition of our Northeast assets, which was
primarily funded at the end of the second quarter, and the issuance of $300
million of senior notes in June 1999 and $240 million of senior notes in
November 1999. In addition, a higher average outstanding balance on our
revolving line of credit and the consolidation of Crockett Cogeneration and our
Pittsburgh and San Francisco thermal operations contributed to higher interest
expense.

Income Tax. We generated substantial income tax benefits as a result of
our operations. Because we are included in the consolidated federal income tax
return of Northern States Power, we pay to and we are paid by Northern States
Power on a dollar-for-dollar basis for the increase or reduction, respectively,
of Northern States Power's taxes attributable to the respective tax liabilities
or benefits we create. We have recorded an income tax benefit due to the
recognition of Section 29 tax credits associated with NEO, foreign tax benefits
related to the Loy Yang project and tax losses resulting from accelerated
depreciation of certain fixed assets. The Section 29 credits comprised $20.4
million of our 1999 tax benefit compared with $15.9 million in 1998. The
increase in Section 29 credits is due to the growth of NEO's portfolio of
landfill gas projects.

Net Income. For 1999, we had net income of $57.2 million compared to $41.7
million in 1998, an increase of $15.5 million or 37.2%. This increase was due to
the factors described above.

FISCAL YEAR ENDED DECEMBER 31, 1998 COMPARED TO FISCAL YEAR ENDED DECEMBER
31, 1997

Revenues. For the year ended December 31, 1998, we had total revenues of
$182.1 million, compared to $118.3 million for the year ended December 31, 1997,
an increase of $63.8 million or 54%. Operating revenues from wholly-owned
operations for 1998 were $100.4 million, compared to $92.0 million in 1997, an
increase of $8.4 million, or 9.1%. The acquisition of new facilities,
principally the Camas Power Boiler, accounted for this increase. Unusually mild
weather in 1998 in the upper Midwest led to lower revenues in our heating and
cooling operations, which partially offset the 1998 revenue increase. In 1998,
operating revenues from wholly-owned operations consisted of revenue from
electrical generation (46.2%), heating, cooling and thermal activities (46.6%),
and technical services (7.8%), while in 1997, they consisted of operating
revenues from heating, cooling and thermal activities (54%), electrical
generation (32%), and technical services (14%).

For 1998, our equity in earnings of unconsolidated affiliates was $81.7
million, compared to $26.2 million for 1997, an increase of $55.5 million or
212%. This increase primarily resulted from the acquisition of interests in new
projects, including the El Segundo, Long Beach, Crockett Cogeneration and Mt.
Poso projects, an increase in our holdings in Energy Developments Limited, and
improved performance during a full year of ownership from Loy Yang.

Operating Costs and Expenses. For 1998, our cost of wholly-owned
operations was $52.4 million, compared to $46.7 million in 1997, an increase of
$5.7 million or 12%. The increase in cost of operations was due to new NEO
projects and increased expenses in our heating, cooling and thermal operations.

Our depreciation and amortization costs were $16.3 million for 1998,
compared to $10.3 million for 1997, an increase of $6.0 million or 58%. The
depreciation and amortization increase primarily resulted

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<PAGE> 31

from increased amortization of intangible assets related to the acquisition of
Crockett Cogeneration and other projects and additional depreciation due to the
acquisition of additional projects by NEO.

Our general and administrative costs were $42.0 million for 1998, compared
to $32.2 million for 1997, an increase of $9.8 million or 30%. This increase was
due primarily to increased legal, technical and accounting expenses resulting
from expanded operations.

Our development expenses were $14.4 million for 1998, compared to $10.9
million for 1997, an increase of $3.5 million or 32%. This increase was due
primarily to increased business development activities.

Other Income (Expense). Minority interest in projects was $2.3 million for
1998 compared to $0.1 million for 1997. Minority interest relates to projects
that were acquired in November 1997. We recorded a total gain of $30.0 million
in 1998 related to project sales. In October 1998, we sold our 110 MW
Mid-Continent Power Company facility in Oklahoma to Cogeneration Corporation of
America, our affiliate, for a $2.1 million gain. Also in October 1998, we sold
13.35% of our interest in ECK Generating for a gain of $1.6 million. We continue
to own a 44.5% interest in the ECK Generating project. In December 1998, we sold
half of our 50% interest in our Enfield project to an affiliate of El Paso
International for a $26.2 million gain.

For 1998, we recorded $26.7 million in total project write-downs compared
to write-downs of $9.0 million in 1997. The 1998 write down included a $22.0
million write off of our entire investment, which included development expenses
as well as fees incurred in connection with the termination of an interest rate
hedge, in a project we were pursuing in West Java, Indonesia, a $1.9 million
charge related to our investment in the Sunnyside project in Utah and $2.8
million of accumulated project development expenditures related to the Alto
Cachopoal project in Chile. The 1997 charges consisted of a write-down of our
investment in the Sunnyside project. At the end of 1998, no amounts remained on
the balance sheet for these investments.

Other income of $8.4 million in 1998 compared to $11.8 million in 1997
primarily reflected a reduction in interest income from loans to affiliates
during 1998.

Interest expense was $50.3 million for 1998 compared with $31.0 million for
1997, an increase of $19.3 million or 62%. This increase was due primarily to
the issuance of $250 million of senior notes in June 1997, interest on larger
balances outstanding under our revolving line of credit incurred in connection
with the purchase of Crockett Cogeneration and other projects and new debt
obtained for certain NEO projects.

Income Tax. The Section 29 credits comprised $15.9 million of our 1998 tax
benefit compared with $9.8 million in 1997. The increase in Section 29 credits
was due to the growth of NEO's portfolio of landfill gas projects.

Net Income. For 1998, we had net income of $41.7 million compared to $22.0
million in 1997, an increase of $19.7 million or 90%. This increase was due to
the factors described above.

LIQUIDITY AND CAPITAL RESOURCES

To date, we and our subsidiaries have obtained cash from operations,
issuance of debt securities, borrowings under credit facilities, capital
contributions from Northern States Power, the sale of tax benefits to Northern
States Power and proceeds from non-recourse project financing. We have used
these funds to finance operations, service debt obligations, fund the
acquisition, development and construction of generation facilities, finance
capital expenditures and meet other cash and liquidity needs.

From January 1, 1997, through March 31, 2000, our financing activities
provided cash totaling approximately $3,991 million, including $430.9 million in
capital contributions from Northern States Power. Financing activities for 1999
included $1,473 million in gross proceeds from the issuance of long and short
term debt and $250.0 million of capital contributions from Northern States
Power. These inflows were partially offset by $18.6 million in payments on
long-term debt. In 1999, we used $11.4 million of

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<PAGE> 32

cash in operating activities. Our use of cash in 1999 primarily related to
ongoing working capital requirements for new operations. During the three months
ended March 31, 2000, financing activities included $2,446.9 million in gross
proceeds from the issuance of long-term and short-term debt. These inflows were
partially offset by $715.5 million in repayments of long-term debt. For the
three months ended March 31, 2000, we generated $156.8 million of cash in
operating activities.

Financings at the NRG Level. Our objective is to maintain and improve our
credit ratings, which are presently at "Baa3" from Moody's and "BBB-" from
Standard & Poor's. We intend to do so by prudently leveraging our project
subsidiary companies and by maintaining a corporate capital structure that is
consistent with these credit rating objectives.

Since January 1997, we have issued approximately $1,040 million of
long-term corporate-level indebtedness. All of such debt is unsecured and ranks
senior to all of our existing and future subordinated indebtedness. This amount
includes $250 million of 7.5% senior notes due 2007 and $300 million of 7.5%
senior notes due 2009. These senior notes were used primarily to support equity
requirements for projects acquired and in development. Interest on all of these
notes is paid semi-annually through their maturity dates.

In November 1999, we issued $240 million of 8% remarketable or redeemable
securities ("ROARS") due 2013. On November 1, 2003, Credit Suisse Financial
Products may remarket the ROARS at a fixed rate of interest through 2013 or, at
our option, at a floating rate of interest for up to one year and then at a
fixed rate of interest through 2013. Interest is payable semi-annually beginning
May 1, 2000 through November 1, 2003, and then at intervals and interest rates
specified in the indenture. On November 1, 2003, the ROARS will either be
mandatorily tendered to and purchased by Credit Suisse Financial Products or
mandatorily redeemed by us at prices specified in the indenture.

In March 2000, we issued L160 million (approximately $250 million at the
time of issuance) of 7.97% reset senior notes due 2020, principally to finance
our equity investment in the Killingholme facility. On March 15, 2005, these
senior notes may be remarketed by Bank of America, N.A. at a fixed rate of
interest through the maturity date or, at our option, at a floating rate of
interest for up to one year and then at a fixed rate of interest through 2020.
Interest is payable semi-annually on these securities beginning September 15,
2000 through March 15, 2005, and then at intervals and interest rates
established in the remarketing process. On March 15, 2005, these senior notes
will either be mandatorily tendered to and purchased by Bank of America or
mandatorily redeemed by us at prices specified in the indenture.

In addition, we have a $500 million revolving credit facility with ABN AMRO
Bank, N.V. under a commitment fee arrangement that matures on March 9, 2001.
This facility provides short-term financing in the form of bank loans. At March
31, 2000, we had $304 million outstanding under this facility.

In March 2000, we borrowed $300 million under a short-term bridge facility
with Citicorp USA, Inc., that expires on August 31, 2000 and bears interest at a
floating rate, which was 6.43% at March 31, 2000. Proceeds from this loan, which
were used to fund the acquisition of the Cajun facilities, will be repaid with a
portion of the proceeds of this offering. In connection with the extension of
this bridge facility, Northern States Power provided a support agreement on our
behalf to Citicorp USA.

In November 1999, we entered into a $125 million standby letter of credit
facility with Australia and New Zealand Banking Group Limited as administrative
agent. The facility provides for issuances of letters of credit for our account
with respect to financial and performance guarantees that we or our project
affiliates undertake. The facility terminates on November 31, 2002.

Financings at the Project Level. We have generally financed the
acquisition and development of our projects under financing arrangements to be
repaid solely from each of our project's cash flows, which are typically secured
by the plant's physical assets and equity interests in the project company. We
have agreed, in some instances, to undertake limited financial support for
certain of our project affiliates in the form of certain limited obligations and
contingent liabilities. As of March 31, 2000, our affiliates had approximately
$2,325 million of indebtedness outstanding which is non-recourse to us. The most
significant of these financings include the following:

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<PAGE> 33

- $800 million of senior secured bonds issued by NRG South Central
Generating LLC in March 2000 consisting of:

- $500 million of 8.962% bonds due 2016; and

- $300 million of 9.479% bonds due 2024.

- $750 million of senior secured bonds issued by NRG Northeast Generating
LLC in February 2000 consisting of:

- $320 million of 8.065% bonds due 2004;

- $130 million of 8.842% bonds due 2015; and

- $300 million of 9.292% bonds due 2024.

- In March 2000, three of our subsidiaries entered into a L335 million
(approximately $533 million at March 31, 2000) secured borrowing
facility agreement with Bank of America International Limited, as
arranger. Under this facility, the financial institutions party to the
facility agreement have made available to our subsidiaries various term
loans (L235 million) for the purpose of financing the acquisition of the
Killingholme facility and revolving credit and letter of credit
facilities (collectively, L100 million) for the purpose of providing
working capital for operating the Killingholme facility and for other
purposes. The final maturity date of the facility is the earlier of June
30, 2019, or the date on which all borrowings and commitments under the
largest tranche of the term loan facility have been repaid or cancelled.

- $255 million of 8.13% secured indebtedness due 2014 of Crockett
Cogeneration that we recorded in 1999 when we consolidated this entity
for accounting purposes as a result of an increase in our percentage
interest in future distributions due to satisfaction of specified
aggregate distribution levels by Crockett Cogeneration to its owners.

We have used cash flows provided by our financing activities primarily to
facilitate investments in our subsidiaries. From January 1, 1997, through
December 31, 1999, we used approximately $2,286 million of cash for our
investing activities. In 1999, we incurred $94.9 million in capital
expenditures.

Over the next several years, we intend to focus on the expansion or
repowering of existing facilities and the development of greenfield projects as
well as acquisitions of thermal energy production and transmission facilities in
the United States. Internationally, we intend to continue to pursue development
and acquisition opportunities in selected countries. We expect to meet our cash
and financing needs over the next several years through a combination of cash
flows from operations and additional financing arrangements.

We have committed to purchase the Conectiv assets for approximately $800
million in late 2000 and intend to finance this purchase with a combination of
project-level and corporate-level debt. Additionally, we have contracted to
purchase 16 turbine generators from General Electric at an acquisition cost of
approximately $500 million payable over five years, as well as two turbines from
Great River Energy for $43 million. In addition, we have ongoing annual capital
expenditures of approximately $35 to $70 million for environmental and other
investment at our existing projects. We expect to fund the turbine purchases and
these levels of ongoing capital expenditures from internally generated cash
flow.

Our future growth strategy is dependent upon significant new capital
investment. We expect to expend, principally through our project subsidiaries,
approximately $1,050 million (including $800 million for the acquisition of
assets from Conectiv) to acquire non-regulated projects and properties during
the remainder of 2000. We expect to finance our future capital requirements with
a combination of project-level debt, internally generated funds, corporate-level
debt and additional equity. Our ability to arrange future financing is dependent
on a number of factors. To the extent we were unable to raise additional capital
on attractive terms either at the corporate level or on a non-recourse project
level, it would have a material adverse effect on our ability to grow.

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IMPACT OF ENERGY PRICE CHANGES, INTEREST RATES AND FOREIGN CURRENCY FLUCTUATIONS

We use derivative financial instruments to mitigate the impact of changes
in electricity and fuel prices on our margins, the impact of changes in foreign
currency exchange rates on our international project cash flows and the impact
of changes in interest rates on our cost of borrowing.

Electricity and fuel prices tend to fluctuate significantly as they are
influenced by many factors, including general economic conditions and changes in
supply and demand. In particular, our power marketing subsidiary is exposed to
the risk of changes in market prices of fuel oil, natural gas and electricity.
To assist us in achieving our objective of maximizing net operating margins
while minimizing our exposure to volatility in the electricity, fuel oil and
natural gas markets, our power marketing subsidiary, NRG Power Marketing, uses a
variety of instruments, including options, swaps and forward contracts.
Contracts for the transmission and transportation of these commodities are also
authorized, as necessary, in order to meet physical delivery requirements and
obligations.

NRG Power Marketing operates within strict risk management guidelines that
have been approved by its board of directors. These guidelines:

- generally prohibit speculative trading activities, meaning that we have
to be able to produce from our assets, or accept and utilize the
commodity being traded;

- do not permit more than 50% of the uncommitted energy or capacity of any
facility to be sold forward without the approval of the board of
directors of NRG Power Marketing; and

- require approval of all counter parties and their trading limits by our
Treasurer.

As of December 31, 1999, a 10% increase in fuel oil, natural gas and
electricity forward prices would have resulted in a gain on our outstanding
forward contracts of approximately $11.9 million. Conversely, a 10% decrease in
fuel oil, natural gas and electricity forward prices would have resulted in a
loss on these contracts of approximately $11.9 million. These potential gains
and losses on energy forward contracts may be offset by the gains and losses on
the underlying commodities being hedged.

For all derivative financial instruments, we and our subsidiaries are
exposed to losses in the event of nonperformance by counter parties to such
derivative financial instruments. We have established controls to determine and
monitor the creditworthiness of counter parties in order to mitigate our
exposure to counter party credit risk.

SFAS 52 requires foreign currency gains to be reflected in the income
statement if settlement of an obligation is in a currency other than the local
currency of the entity. A portion of the Kladno project debt is in non-local
currencies, namely United States dollars and German deutsche marks. As of
December 31, 1999, if the value of the Czech koruna had decreased by 10% in
relation to the United States dollar and the German deutsche mark, we would have
recorded a $5.5 million after tax loss on the currency transaction adjustment.
If the value of the Czech koruna were to have increased by 10%, we would have
recorded a $5.5 million after tax gain on the currency transaction adjustment.
The potential impacts on our income statement of these currency fluctuations are
a result of the debt structure of the project and are not indicative of the
long-term earnings potential of the investment. Kladno is the only project we
have at this time with this type of debt structure.

We have historically used interest rate hedging contracts to mitigate the
risks associated with movements in interest rates and, when deemed appropriate,
have entered into swap agreements effectively converting fixed rate obligations
into floating rate obligations. As of March 31, 2000, we had four interest rate
swap agreements with notional amounts totaling approximately $692 million. If
the swaps had been discontinued on March 31, 2000, we would have owed the
counter parties approximately $2 million. Based on the investment grade rating
of the counter parties, we believe that our exposure to credit risk due to
nonperformance by the counter parties to our hedging contracts is insignificant.

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- We entered into a swap agreement effectively converting the 7.5% fixed
rate on $200 million of our Senior Notes due 2007 to a variable rate
based on the London Interbank Offered Rate. The swap expires on June 1,
2009.

- A second swap effectively converts a $16 million issue of non-recourse
variable rate debt into a fixed rate debt. The swap expires on September
30, 2002 and is secured by the Camas Power Boiler assets.

- A third swap converts $177 million of non-recourse variable rate debt
into fixed rate debt. The swap expires on December 17, 2014 and is
secured by the Crockett Cogeneration assets.

- A fourth swap converts L188 million of non-recourse variable rate debt
into fixed rate debt. The swap expires on June 30, 2019 and is secured by
the Killingholme assets.

NEW ACCOUNTING STANDARDS

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." This statement
requires that all derivatives be recognized at fair value in the balance sheet
and that changes in fair value be recognized either currently in earnings or
deferred as a component of Other Comprehensive Income, depending on the intended
use of the derivative, its resulting designation and its effectiveness. We plan
to adopt this standard in the first quarter of 2001, as required. We have not
determined the potential impact of implementing this statement.

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BUSINESS

INTRODUCTION

We are a leading global energy company primarily engaged in the
acquisition, development, ownership and operation of power generation facilities
and the sale of energy, capacity and related products. We believe we are one of
the three largest independent power generation companies in the United States
and the sixth largest independent power generation company in the world measured
by our net ownership interest in power generation facilities. We own all or a
portion of 57 generation projects that have a total generating capacity of
23,660 MW; our net ownership interest in those projects is 13,664 MW. Upon the
closing of our pending acquisition from Conectiv of interests in six power
generation facilities, which we expect to occur later this year, we will have
interests in projects having a total generating capacity of 28,722 MW; our net
ownership interest in those projects will be 15,539 MW. In addition, we have an
active acquisition and development program through which we are pursuing
additional generation projects.

As the following table illustrates, we have grown significantly during the
last three years, primarily as a result of our success in acquiring domestic
power generation facilities:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
------- ------- --------
<S> <C> <C> <C>
Net Ownership Interest (in MW at year end)(1)...... 2,637 3,300 10,990
Operating Income (in thousands).................... $18,109 $57,012 $109,520
</TABLE>

- ---------------

(1) All references to our MW ownership in this prospectus include MW
attributable to projects under construction, which totaled 616 MW at
December 31, 1997, 284 MW at December 31, 1998, 252 MW at December 31, 1999,
and 383 MW at March 31, 2000.

We intend to continue our growth through a combination of targeted
acquisitions in selected core markets, the expansion or repowering of existing
facilities and the development of new greenfield projects. To prepare for
expansion, repowering and greenfield opportunities, we recently agreed to
purchase 16 turbine generators from GE Power Systems and two turbine generators
from Siemens Westinghouse over a six year period commencing in 2001. These new
turbines, which we expect to install at domestic facilities, will have a
combined capacity of approximately 3,300 MW.

In addition to our power generation projects, we also have interests in
district heating and cooling systems and steam generation and transmission
operations and landfill gas generation. Our thermal and chilled water
businesses, with operations in Minnesota, California and Pennsylvania, have a
steam and chilled water capacity equivalent to approximately 1,204 MW. We
believe that, through our subsidiary NEO Corporation, we are also one of the
largest landfill gas generation companies in the United States, extracting
methane from landfills to generate electricity. NEO owns 30 landfill gas
collection systems and has 55 MW of net ownership interest in related electric
generation facilities. NEO also has 35 MW of net ownership interests in 18 small
hydroelectric facilities.

MARKET OPPORTUNITY

The power industry is one of the largest industries in the world,
accounting for approximately $200 billion in annual revenues and approximately
800,000 MW of installed generating capacity in the United States alone. The
generation segment of the industry historically has been characterized by
regulated electric utilities producing and selling electricity to a captive
customer base. However, the power generation market has been evolving from a
regulated market based upon cost of service pricing to a non-regulated
competitive market. We believe that the power industry will continue to undergo
substantial restructuring over the next several years and will experience
significant growth in the future.

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implementing legislation. As a result, from January 1, 1997 through December 31,
1999, approximately 70,000 MW of power generating capacity in the United States
had been sold or transferred by regulated electric utilities to independent
power producers. We expect in excess of 70,000 additional MW of power generating
capacity in the United States to be sold to independent power producers by the
end of 2002.

We believe that increasing demand and the need to replace old and
inefficient generation facilities will create a significant need for additional
power generating capacity throughout the United States. In our view, these
factors combined with recent restructuring legislation provide an attractive
domestic environment for an independent power producer like us with a history of
successfully developing, acquiring and operating power generation facilities.

OUR HISTORY

We have been acquiring and developing power generation facilities since
1989, when we were formed as a wholly-owned subsidiary of Northern States Power
to take advantage of opportunities in the independent power market that had
developed as a result of economic factors and legal and regulatory changes in
the United States and throughout the world. During the early 1990s, we gained
experience in acquiring interests in and operating smaller domestic generation
facilities and established our landfill gas, resource recovery and district
heating and cooling businesses.

In 1993 we began focusing our development efforts outside the United States
in response to the growing trend among foreign governments to privatize
government-owned electric utility assets. We capitalized on our senior
management's background and experience with our parent company, which has an
excellent reputation as an owner and operator of coal-fired power plants; this,
combined with Northern States Power's strong track record on environmental
issues, was instrumental in our success in early global privatization
initiatives in Germany and Australia. Since that time, we have gained experience
in the development and operation of gas-fired power plants and have established
an international reputation as a reliable and experienced owner and operator of
power plants, which has allowed us to enjoy continued success in selected
markets globally.

In the mid-1990s, the international privatization trend was augmented by
electric utility restructuring in the United States. As regulators began opening
domestic markets to competition and electric utilities began selling their
electric generation assets, we refocused a significant portion of our
development and acquisition efforts on independent power projects in the United
States with a goal of becoming a significant owner of generation assets in
certain core markets. Since January 1, 1997, we have acquired approximately
10,489 MW of power generating capacity in the United States: 7,025 MW in our
Northeast region, 1,888 MW in our South Central region, and 1,576 MW in our West
Coast region. We continue to pursue targeted acquisition opportunities in our
core United States markets. In addition, in January 2000 we agreed to purchase
1,875 MW of power generation assets in the Mid-Atlantic United States from
Conectiv. We expect to complete this acquisition during the fourth quarter of
2000 subject to receipt of required regulatory approvals.

During the 1990s, we also expanded our landfill gas, resource recovery and
district heating and cooling businesses. These businesses differentiate us as an
independent power producer experienced in diverse fuels and alternative energy.
We believe we are one of the largest district heating and cooling providers in
the United States and one of the largest landfill gas operators in the United
States.

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<PAGE> 38

As the table below indicates, our management team has substantial
experience in the electric utility and independent power businesses gained at
NRG, Northern States Power and, in the case of Keith G. Hilless, at the
Queensland Transmission and Supply Corporation and at the Queensland Electricity
Commission in Australia.

<TABLE>
<CAPTION>
YEARS OF
EXPERIENCE IN
ELECTRIC
GENERATION
NAME CURRENT POSITION YEARS WITH NRG INDUSTRY
- ---- -------------------------------------- -------------- -------------
<S> <C> <C> <C>
David H. Peterson.............. Chairman of the Board, President,
Chief Executive Officer and Director 11 36
Leonard A. Bluhm............... Executive Vice President and Chief
Financial Officer 9 28
Keith G. Hilless............... Senior Vice President, Asia Pacific 3 8
Craig A. Mataczynski........... Senior Vice President, North America 6 17
John A. Noer................... Senior Vice President 1 32
Ronald J. Will................. Senior Vice President, Europe 8 39
</TABLE>

OUR INDEPENDENT POWER GENERATION BUSINESS

DOMESTIC

Our near-term domestic development and acquisition plans are focused on
core markets that we consider to have attractive business fundamentals and where
we believe we have the ability to achieve the scale needed to enhance our
long-term profitability. Our current core domestic markets are the Northeast,
South Central and West Coast regions of the United States. The table that
follows summarizes our domestic power generation operations in these core
markets.

<TABLE>
<CAPTION>
TOTAL OUR NET
CAPACITY OWNERSHIP
UNITED STATES REGIONS STATES OF OPERATION PRIMARY FUELS (MW) INTEREST (MW)
- --------------------- ------------------- -------------------- -------- -------------
<S> <C> <C> <C> <C>
Northeast...................... Connecticut, Maine, Gas, Coal and Oil 7,602 7,099
Massachusetts, New
Jersey, New York and
Pennsylvania
South Central.................. Louisiana, Illinois Gas and Coal 2,832 2,138
and Oklahoma
West Coast..................... California Gas and Coal 3,151 1,603
------ ------
Total Domestic............... 13,585 10,840
====== ======
</TABLE>

Upon completion of our acquisition of power generation assets from
Conectiv, we intend to establish the Mid-Atlantic region as our fourth domestic
core market.

INTERNATIONAL

In selected global markets, we have pursued development and acquisition
opportunities in those countries in which we believe that the legal, political
and economic environment is conducive to foreign investment. We are presently
focusing our international development activities in the United Kingdom, Central
Europe, Turkey, Australia and, to a lesser extent, Latin America.

34
<PAGE> 39

The table that follows describes our existing international power
generation operations.

<TABLE>
<CAPTION>
TOTAL OUR NET
CAPACITY OWNERSHIP
GLOBAL MARKETS COUNTRIES OF OPERATION PRIMARY FUELS (MW) INTEREST (MW)
- -------------- ---------------------- ------------------ -------- -------------
<S> <C> <C> <C> <C>
Australia...................... Australia Coal, Landfill Gas 4,146 1,312
and Methane
Europe......................... Czech Republic, Germany Coal and Gas 2,642 1,223
and United Kingdom
Latin America.................. Bolivia, Colombia, Hydro, Gas, Coal, 1,078 186
Guatemala, Honduras, Oil and Geothermal
Jamaica and Peru
------ ------
Total International.......... 7,866 2,721
====== ======
</TABLE>

STRATEGY

GEOGRAPHIC LOCATION(1)

<TABLE>
<CAPTION>
U.S. EUROPE AUSTRALIA OTHER
- ---- ------ --------- -----
<S> <C> <C> <C>
80 9.00 10.00 1.00
</TABLE>

PRIMARY FUEL TYPE(1)(2)

<TABLE>
<CAPTION>
COAL GAS OIL OTHER
- ---- --- --- -----
<S> <C> <C> <C>
35 37 26 2
</TABLE>

DISPATCH LEVEL(3)

<TABLE>
<CAPTION>
PEAKING INTERMEDIATE BASE-LOAD
- ------- ------------ ---------
<S> <C> <C>
41 19 40
</TABLE>

- ---------------

(1) Based upon MW of net ownership interest as of March 31, 2000

(2) Several of our generation facilities, constituting approximately 3,900 MW of
generating capacity, are capable of utilizing more than one fuel, which can
be switched as fuel prices fluctuate.

Our strategy is to capitalize on our acquisition, development and operating
skills to build a balanced, global portfolio of power and thermal generation
assets. We intend to implement this strategy by continuing an aggressive, but
thoughtful, acquisition program and accelerating our development of expansion
projects at existing facilities and projects at new sites, also known as
"greenfield development". We believe that our operational skills and experience
give us a strong competitive position in the unregulated generation marketplace.

35
<PAGE> 40

availability during periods when power prices are significantly above the
variable cost of producing power at that facility -- what we call "in-market"
availability.

By leveraging the talents of our regional management teams, focusing on our
regional market expertise and operating and utilizing our asset base on a
regional rather than a project basis, we believe we can best position ourselves
for long-term profitability. Achieving "critical mass" in core markets should
allow us to capitalize on opportunities available in those markets.

We do not own nor do we have any present intention to own any interest in
nuclear generation facilities.

DOMESTIC

The domestic power generation market is evolving from a regulated, utility
dominated market based upon cost-of-service pricing to an independent power
generation market based on competitive market pricing. While most domestic
generation capacity is still utility owned and subject to cost-of-service
regulation, we expect the evolution to continue as regulated utility power
generation assets are divested to non-regulated generators. In addition, we
expect that a significant share of the new generation capacity that is built to
serve increasing demand and to replace less efficient facilities will be
developed and owned by independent power producers like us.

In order to position ourselves for growth in this transitioning market, we
have decided to focus our near-term domestic development and acquisition plans
on our existing three core markets, our Northeast, South Central and West Coast
regions, and to add the Mid-Atlantic region as our fourth core market upon
closing of our planned acquisition from Conectiv. We believe that attractive
business fundamentals and growth opportunities exist that will enable us to
pursue a top three position in each of these markets. We will consider domestic
projects outside of these markets if we believe that an opportunity exists to
create a new core market or that the expected returns from a particular project
warrant an investment.

We have been active in acquiring assets from utility generation divestiture
programs and have focused on the following factors and characteristics in
evaluating potential acquisitions:

- cost of competing power generation in the relevant markets;

- assets that provide diversity in terms of dispatch level, fuel source
and access to wholesale power markets within a region;

- assets in high priced or transmission constrained markets;

- assets that allow for the sale of multiple power generation products,
including energy, capacity and ancillary services;

- assets that can support our other regional assets or have the potential
to sell into attractive adjacent markets;

- assets that are being sold with initial transition power purchase
agreements to stabilize cash flows and earnings during our initial years
of ownership; and

- assets that provide opportunities for future capacity expansion or
repowerings.

Once we have acquired one or more power plants in a given market, we will
then look to build additional capacity in such market as appropriate by
acquiring additional power generation facilities, expanding or repowering
facilities at existing sites or through greenfield development. The 16 new
turbines that we recently contracted to purchase from GE, representing
approximately 3,000 MW of capacity, and the two 135 MW turbines being built by
Siemens Westinghouse will be the foundation for our domestic development
program.

INTERNATIONAL

Historically, the majority of power generating capacity outside of the
United States has been owned and controlled by governments. During the past
decade, however, many foreign governments have moved

36
<PAGE> 41

to privatize power generation plant ownership through sales to third parties and
by encouraging new capacity development and refurbishment of existing assets by
independent power developers. Governments have taken a variety of approaches to
encourage the development of competitive power markets, from awarding long-term
contracts for energy and capacity to purchasers of power generation to creating
competitive wholesale markets for selling and trading energy, capacity and
related products.

We believe that there will be significant opportunities to invest in
attractive projects in international markets. Based upon our assessment of
market opportunities and our portfolio risk management criteria, we intend to
leverage our reputation, experience and expertise in order to acquire foreign
assets in selected countries. As market opportunities develop, we expect that
our international strategy will be consistent with our domestic core market
strategy in terms of geographic, fuel and dispatch diversification. We believe
operating and asset diversity will allow us to reduce business and market risks,
while positioning us to take advantage of market opportunities, including peak
power market price opportunities and periods of constrained availability of
generating capacity, fuels and transmission.

To manage our international asset portfolio risks, we utilize a portfolio
risk management discipline based upon country risk, as identified by an
independent, internationally recognized organization. This portfolio tool, which
has been endorsed by our board of directors, requires that we manage our entire
portfolio of generation capacity to maintain a high quality, weighted average,
equivalent country risk. Using this tool, we are able to monitor the exposure we
are taking in emerging markets to maintain an appropriate balance in our asset
portfolio.

We are presently focusing our international development in the United
Kingdom, Central Europe, Turkey, Australia and, to a lesser extent, Latin
America. In the future, we will consider international projects outside of these
markets if we believe that an opportunity exists to create a new core market or
that the expected returns from a particular project warrant an investment.

We expect to acquire or develop most international projects on a joint
venture basis to enable us to share the risks associated with the acquisition
and development of larger projects. Joint acquisition and development of future
projects also should further reduce our financial risk by allowing us to build a
more diversified portfolio of projects. Where appropriate, we will include a
local or host country partner or a partner with substantial experience in the
area. By doing so, we expect to gain a number of advantages, including technical
expertise, greater knowledge of and experience with the political, economic,
cultural and social conditions and commercial practices of the region or country
where the project is being developed, and the ability to leverage our skilled
personnel and financial resources. Among other things, a local partner may also
assist in obtaining financing from local capital markets, building political and
community support for the project and obtaining local regulatory approvals.

HOW WE SELL OUR GENERATING CAPACITY AND ENERGY

A facility's revenue under a power purchase agreement usually consists of
two payments: energy and capacity. Energy payments, which are intended to cover
the variable costs of electric generation, such as fuel costs and variable
operation and maintenance expenses, are normally based on a facility's net
electrical output measured in kilowatt hours, with payment rates either fixed or
indexed to fuel costs. Capacity payments, which are generally intended to
provide funds for the fixed costs incurred by the facility, such as debt service
on the project financing and an equity return, are normally calculated based on
the net electrical output or the declared capacity of a facility and its
availability.

- long-term contracts of more than one year including:

- power purchase agreements with utilities and other third parties
(generally 2-25 years);

37
<PAGE> 42

- - standard offer agreements to provide load serving entities with a percentage
of their requirements (generally 4-9 years); and

- "transition" power purchase agreements with the former owners of
acquired facilities
(generally 3-5 years).

- short-term contracts or other commitments of one year or less and spot
sales including:

- spot market and other sales into various wholesale power markets; and

- bilateral contracts with third parties.

Our objective is to mitigate variability in our earnings by having
approximately 40-70% of our capacity contracted for under contracts greater than
one year, generally seeking to enter into contracts with lengths of 1-5 years,
selling half of our remaining capacity in the forward market for 30-365 days,
and selling the other half of our remaining capacity in the spot market to
capture opportunities in the market when prices are higher. By following this
strategy, we seek to achieve positive, stable returns while retaining the
flexibility to capture premium returns when available.

We derived approximately 36% of our 1999 revenues from two customers:
Consolidated Edison Company of New York (17%) and Niagara Mohawk Power
Corporation (19%). We sell energy and capacity to these customers under
transition agreements expiring in 2002 and 2003, respectively. For the first
quarter of 2000, we derived approximately 54.8% of our revenues from three
customers: Connecticut Light & Power (26.5%), Niagara Mohawk Power Corporation
(16.2%) and Consolidated Edison Company of New York (12.1%).

POWER MARKETING AND FUEL PROCUREMENT

Our energy marketing subsidiary, NRG Power Marketing, Inc., was formed in
1997 to maximize the utilization of and return from our generation assets and to
mitigate the risks associated with those assets. This subsidiary markets energy
and energy related commodities, including electricity, natural gas, oil, coal
and emission allowances. By using internal resources to acquire fuel for and to
market electricity generated by our domestic facilities, we believe we can
secure the best pricing available in the markets in which we sell power and
enhance our ability to compete. NRG Power Marketing provides a full range of
energy management services for our generation facilities in our Northeast and
South Central regions. These services are provided under power sales and agency
agreements pursuant to which NRG Power Marketing manages the sales and marketing
of energy, capacity and ancillary services from these facilities and also
manages the purchase and sales of fuels and emission allowances needed to
operate these facilities.

NRG Power Marketing operates within strict limits, typically selling only
our available capacity and not engaging in any speculative activity by selling
in excess of what we reasonably believe our facilities are capable of producing
or will produce. The overall objective of our power marketing activities is to
achieve an appropriate rate of return on our generation asset portfolio without
taking on any undue risks.

In order to achieve our objectives, we have assembled an experienced team.
NRG Power Marketing managerial employees have an average of 6-7 years of power
marketing or similar trading experience. In addition, we have taken steps to
align the interest of the power marketing staff with the overall performance of
our generation assets by basing their incentive compensation primarily upon the
success and profitability of our generation facilities.

In an effort to maximize our returns, we manage our power marketing for our
100% owned domestic assets centrally from our Minneapolis headquarters. We
operate a trading floor, from which we monitor power and fuel prices, weather
conditions and other factors affecting our business in each of our core markets.
For example, we have a Northeast desk to manage power marketing for our
Northeast assets. This desk is further divided by the three power pools in that
region, namely, the Pennsylvania, New Jersey and Maryland power pool, the New
England power pool and the New York power pool.

Although we have entered into a partnership with Dynegy Power Corporation
for the marketing of power from our West Coast generation assets, our strategy
and overall objectives remain the same. Accordingly, Dynegy is limited to sales
that can be covered by the West Coast facilities and cannot enter

38
<PAGE> 43

into any speculative trades and sell more than the available capacity from these
facilities. In addition, Dynegy cannot enter into an agreement for longer than a
30-day period without our approval.

In Europe, our first project not covered by long-term agreements is
Killingholme. Our strategy in Europe is similar to our strategy in the United
States; a regional desk has been established in the United Kingdom and a central
trading floor will be established as we continue to grow in Europe.

NRG Power Marketing handles fuel procurement and trading of emissions
allowances in order to support our overall needs. Generally we seek to hedge
prices for 50% to 70% of our expected fuel requirements during the succeeding 12
to 24 month period. This provides us with certainty as to a portion of our fuel
costs while allowing us to maintain flexibility to address lower than expected
dispatch rates and to take advantage of the dual fuel capabilities at many of
our facilities.

NRG Power Marketing conducts its activities in accordance with risk
management guidelines approved by the NRG Power Marketing board of directors,
which has primary responsibility for oversight of NRG Power Marketing
activities. The members of the NRG Power Marketing board of directors are our
Chairman and Chief Executive Officer, Senior Vice President -- North America,
and our General Counsel. NRG Power Marketing reports monthly to our Financial
Risk Management Committee, which consists of our Chief Financial Officer,
Treasurer, Controller, Senior Vice President -- North America and Northern
States Power's Treasurer. The trading authority of each of our power marketing
employees is determined by the position they hold. For example, contract
administrators and fuel managers are limited to forward positions of up to one
month, with a per transaction risk limit of $350,000. Transactions that would
exceed these limits must receive varying levels of advance approvals.
Transactions with a term of over one year and a risk greater than $1.25 million
need to be approved by the NRG Power Marketing board. Our risk management
guidelines also require that our treasury department perform a credit review,
and approve all counter parties, prior to NRG Power Marketing entering into
transactions with such counter parties. Our risk management guidelines also
require that our treasury department approve in advance credit limits for all
counter parties.

We do not engage in speculative trading, thus all transactions are for
physical delivery of the particular commodity for the specified period. These
physical delivery transactions may take the form of fixed price, floating price
or indexed sales or purchases, and options on physical transactions, such as
puts, calls, basis transactions and swaps, are also permitted. Contracts for the
transmission and transportation of these commodities are also authorized, as
necessary, in order to meet physical delivery requirements and obligations. All
forward sales and purchases of electricity and fuel are reported to the board of
directors of NRG Power Marketing and to our Financial Risk Management Committee.
In accordance with the risk management guidelines, no more than 50% of the
uncommitted energy or capacity of any facility will be sold forward without the
approval of the board of directors of NRG Power Marketing. Violation by any
employee of any of the risk management guidelines is grounds for immediate
termination of employment.

PLANT OPERATIONS

Our success depends on our ability to achieve operational efficiencies and
high availability at our generation facilities. In the new unregulated energy
industry, minimizing operating costs without compromising safety or
environmental standards while maximizing plant flexibility and maintaining high
reliability is critical to maximizing profit margins. Our operations and
maintenance practices are designed to achieve these goals.

Accordingly, we place a high level of importance on maximizing the
operational performance and availability of our generation assets. Our
availability goals are not driven by traditional benchmarks, such as daily or
annual availability, but are focused on each facility's availability during
periods when power prices are significantly above the variable cost of producing
power at that facility -- what we call "in-market" availability.

Our overall corporate strategy of establishing a top three presence in
certain core markets is in part driven by our operational strategy. While our
approach to plant management emphasizes the operational

39
<PAGE> 44

autonomy of our individual plant managers and staff to identify and resolve
operations and maintenance issues at their respective facilities, we are also
implementing a regional shared practices system in order to facilitate the
exchange of information and best practices among the plants in our various
regions. We have organized our operations geographically such that inventories,
maintenance, backup and other operational functions are pooled within a region.
This approach enables us to realize cost savings and enhances our ability to
meet our facility availability goals. Plant supervisors and staff within core
markets and across our company typically participate in weekly conference calls
in order to discuss operational issues and share best practices.

We have a long track record of excellence in operating a diverse portfolio
of generation assets. We currently operate and maintain approximately 17,600 MW
of generating capacity, approximately 9,500 MW of which we do not wholly own. We
are establishing a compensation and incentive program to motivate our operations
staff to realize operational efficiency and in-market availability goals. In the
short time since we have closed our most recent acquisitions in the northeastern
United States, we have been successful in increasing the efficiency and
availability of most of these facilities while at the same time reducing the
number of staff required to operate such facilities.

Another example of our successful operating performance is our Gladstone
facility. Although we only own 37.5% of this facility, we are the sole operator
and receive an annual operating fee and are eligible to receive a monthly
operating performance bonus for achieving plant availability targets. We have
earned performance bonuses in a majority of the months since our acquisition of
this facility in March 1994.

At facilities where we are an equity holder, but do not have operational
responsibility, we typically require that we have a seat on a management
committee or an operational committee. Through these positions, we are able to
be kept abreast of plant status, pose questions and receive timely responses on
pressing operations issues. At various times, we have used our technical
personnel or we have contracted to use Northern States Power's personnel to
provide consulting assistance for these projects.

Finally, safety is a key area of concern to us. We believe that the most
efficient and profitable performance of our facilities can only be accomplished
within a safe working environment for our employees. Our compensation and
incentive program includes safety as a factor in evaluating our employees, and
we have a well-developed reporting system to track safety and environmental
incidents at our facilities.

MANAGEMENT, ORGANIZATIONAL AND CORPORATE DEVELOPMENT STAFF STRUCTURE

We have established three major corporate regions, North America, Europe
and Australia, and have placed senior vice presidents in charge of each.
Further, we have subdivided the North American and European generation business
regions as follows: the North American business into Northeast, South Central
and West Coast regions and the European business into the United Kingdom and
Central Europe regions. The senior vice presidents and regional staff of each
region are responsible for the full spectrum of development activities as well
as for asset optimization within their region.

Our regional structure promotes market expertise and knowledge within our
core markets. Each regional team carefully evaluates greenfield and acquisition
opportunities against risk and return guidelines determined by management. Ten
years of development experience have resulted in thorough and efficient due
diligence procedures, whereby our cross-functional teams focus on the particular
issues that are most critical to each project under consideration. If an
opportunity meets the requirements of the regional management team and will
strengthen our regional portfolio, our senior management must review the project
before it is presented to our board of directors.

INDEPENDENT POWER GENERATION PROJECTS -- DOMESTIC

Most of our domestic projects are grouped under three regional holding
companies corresponding to our domestic core markets. In order to better manage
our domestic projects and to more effectively develop new projects in these
regions, we have recently established regional offices in Pittsburgh,

40
<PAGE> 45

Pennsylvania (Northeast region), Baton Rouge, Louisiana (South Central region)
and San Diego, California (West Coast region). Upon the completion of the
Conectiv asset acquisition, it is expected that those assets will be grouped
into a new Mid-Atlantic region.

We intend our generation facilities within each region to be operated as a
separate business. This regional portfolio structure will allow us to coordinate
the operations of our assets to take advantage of regional opportunities, reduce
risks related to outages, whether planned or unplanned, and pursue expansion
plans on a regional basis.

NORTHEAST REGION

We own approximately 7,100 MW of generating capacity in the Northeast
United States, primarily in New York, New Jersey, Connecticut, Massachusetts and
Pennsylvania. These generation facilities are well diversified in terms of
dispatch level (base-load, intermediate and peaking), fuel type (coal, natural
gas and oil) and customers. In addition, we believe certain of our facilities
and facility sites in the Northeast provide opportunities for repowering or
expansion of existing generating capacity.

Our Northeast facilities are generally competitively positioned within
their respective market dispatch levels with favorable market dynamics and
locations close to the major load centers in the New York Power Pool and New
England Power Pool. For example, the Arthur Kill and Astoria gas turbine
facilities are located in the New York City in-city market and represent
approximately 20% of the installed capacity inside this transmission constrained
area. Load serving entities in the New York City in-city market must currently
contract for 80% of their requirements from in-city resources. We believe there
is presently limited potential to construct new in-city generation capacity or
to gain transmission access to other generating capacity.

We currently sell a portion of the energy and capacity generated by our
assets in the Northeast region into the New York Power Pool. The independent
system operator for the New York Power Pool has recently imposed price
limitations on certain ancillary services sold in this market, and has sought
authority from FERC to adjust the market-clearing prices for these services on a
retroactive basis. We have joined several other independent power producers in
New York in filing a claim with FERC challenging these actions. If the
independent system operator prevails, our revenues from ancillary services sold
in the New York Power Pool could be substantially reduced. Although we would
attempt to adjust our business operations to mitigate the future impacts of such
a ruling, the potential negative impacts on our revenues for the first quarter
of 2000 would include the potential refund of approximately $8.0 million of
revenues collected in February 2000 and the inability to collect approximately
$8.2 million included in revenues, but not yet collected, for March 2000.

To achieve financing, cost and administrative advantages we have pooled our
100% owned Northeast generation assets into a regional holding company, NRG
Northeast Generating LLC. Through NRG Northeast Generating, we financed a
significant portion of the purchase prices for the separate acquisitions of
these generation facilities by means of a $750 million debt financing, which was
completed in February 2000.

Through our ownership of 20% of Cogeneration Corporation of America, our
Northeast assets also include several small, indirectly held, interests in
facilities located in New York, New Jersey and Pennsylvania.

41
<PAGE> 46

The following table summarizes our Northeast generation assets:

<TABLE>
<CAPTION>
OUR NET
OUR OWNERSHIP
TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- -------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Oswego, New York.................... NIMO/NYISO 1,700 100.00% 1,700 Oil/Gas
Huntley, New York................... NIMO/NYISO 760 100.00% 760 Coal
Dunkirk, New York................... NIMO/NYISO 600 100.00% 600 Coal
Arthur Kill, New York............... Con Ed/NYISO 842 100.00% 842 Gas
Astoria Gas Turbines, New York...... Con Ed/NYISO 614 100.00% 614 Gas
Somerset, Massachusetts(1).......... EUA/NEPOOL/ISO-NE 229 100.00% 229 Coal/Oil
Middletown, Connecticut............. NEPOOL/NYPP/ISO-NE 856 100.00% 856 Oil/Gas
Montville, Connecticut.............. NEPOOL/NYPP/ISO-NE 498 100.00% 498 Gas/Oil
Norwalk, Connecticut................ NEPOOL/NYPP/ISO-NE 353 100.00% 353 Oil
Devon, Connecticut.................. NEPOOL/NYPP/ISO-NE 401 100.00% 401 Gas/Oil
Connecticut Turbines, Connecticut... NEPOOL/NYPP/ISO-NE 127 100.00% 127 Oil
CogenAmerica (Grays Ferry), Penn.... PECO Energy 150 10.00% 15 Gas/Oil
CogenAmerica (Parlin), New Jersey... Jersey Central Power & Light 122 20.00% 24 Gas/Oil
CogenAmerica (Newark), New Jersey... Jersey Central Power & Light 54 20.00% 11 Gas/Oil
Other(2)............................ Various 296 Various 69 Various
----- -----
Total............................. 7,602 7,099
===== =====
</TABLE>

- ---------------

(1) Includes 69 MW of deactivated reserve.

(2) Includes 69 MW of net ownership interest in seven projects.

The following generation facilities were purchased together in bundled
transactions:

- Astoria and Arthur Kill facilities for $505 million;

- Huntley and Dunkirk facilities for $355 million; and

- Middletown, Montville, Norwalk, Devon and Connecticut combustion turbine
facilities for $519 million.

The purchase prices for each of the facilities described below, other than the
Oswego and Somerset facilities, reflect an allocation of the purchase price paid
in the bundled transaction in which the facility was acquired.

Oswego Facility. The Oswego facility was acquired from Niagara Mohawk
Power Corporation and Rochester Gas & Electric Company in October 1999 for a
purchase price of $85 million. The Oswego facility, located in Oswego, New York,
is a natural gas/oil-fired, peaking plant consisting of two units with a total
capacity of 1,700 MW. The Oswego facility is currently a source of excess
emission allowances that can be utilized at other facilities. We expect to
operate this facility as a peaking facility. In connection with this
acquisition, we entered into a four-year transition power purchase agreement
with Niagara Mohawk Power under which we agreed to sell to Niagara Mohawk Power
100% of the capacity of one unit, an option for up to 40% of the capacity of the
second unit, and an option to purchase a nominal amount of energy from both
units.

Huntley Facility. The Huntley facility was acquired from Niagara Mohawk
Power in June 1999 for a purchase price of $155.7 million. The Huntley facility,
located near Buffalo, New York, is a coal-fired, base-load facility consisting
of six units with a total capacity of 760 MW. The Huntley facility is among the
lowest cost fossil fuel plants that sell into the New York Power Pool. We plan
to operate it as a base-load facility. In connection with the acquisition of
this facility, we entered into four-year transition power purchase agreements
under which we agreed to sell to Niagara Mohawk Power 100% of the capacity of,
and an option to purchase up to 45% of the annual energy output from, certain
units of the Huntley facility.

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<PAGE> 47

Dunkirk Facility. The Dunkirk facility was acquired from Niagara Mohawk
Power in June 1999 for a purchase price of $199.3 million. The Dunkirk facility,
located in Dunkirk, New York, is a coal-fired, base-load facility consisting of
four units with a total capacity of 600 MW. The Dunkirk facility is among the
lowest variable cost fossil fuel plants that sell into the New York Power Pool.
We plan to operate it as a base-load facility. In connection with the
acquisition of this facility, we entered into four-year transition power
purchase agreements under which we agreed to sell to Niagara Mohawk Power 100%
of the capacity of, and an option to purchase up to 39% of the annual energy
output from, the Dunkirk facility.

Arthur Kill Facility. The Arthur Kill facility was acquired from
Consolidated Edison Company of New York, Inc. in June 1999 for a purchase price
of $395.6 million. The Arthur Kill facility, located in Staten Island, New York,
is a natural gas/oil-fired, intermediate/peaking plant consisting of three units
with a total capacity of 842 MW.

Astoria Gas Turbines. The Astoria gas turbines were acquired from
Consolidated Edison in June 1999 for a purchase price of $109.5 million. The
Astoria facility, located in Queens, New York, is a gas/ liquid fuel-fired,
peaking plant consisting of 11 units with a total capacity of 614 MW.

In connection with the acquisition of the Arthur Kill and the Astoria
facilities, we entered into transition capacity sales agreements under which we
agreed to sell to Consolidated Edison at a fixed price, during certain periods,
up to 100% of the capacity of each of the Arthur Kill and Astoria facilities for
a transition period ending on the earlier of (a) December 31, 2002 or (b) the
date such facility receives notice from the independent system operator in New
York State that none of the electric generation capacity of such facility is
required for meeting the installed capacity requirements in New York City.

Somerset Facility. The Somerset facility was acquired from Montaup
Electric Company, an affiliate of Eastern Utilities Associates, in April 1999
for a purchase price of $55 million. The Somerset facility, located in Somerset,
Massachusetts, is an oil/coal-fired, base-load/peaking facility consisting of
three units with a total capacity of 229 MW (160 MW of which is currently
operational). The Somerset facility provides low variable cost capacity,
strategically positioned to sell power into the New England Power Pool. We
intend to operate this facility as a peaking and base-load facility, depending
on market conditions. In connection with this acquisition, we also entered into
a wholesale standard offer service agreement under which we are obligated to
provide approximately 30% of the energy and capacity requirements of certain
affiliates of Eastern Utilities Associates, which we estimate to be
approximately 275 MW at peak requirement, until December 31, 2009. The
difference between this service requirement and our operational capacity at
Somerset is made up by a combination of power supplied by our other Northeast
facilities and purchased power.

Connecticut Facilities

In connection with the acquisition in December 1999 of the Middletown,
Montville, Norwalk, Devon and Connecticut combustion turbine facilities from
Connecticut Light & Power, we entered into a four-year standard offer service
wholesale sales agreement with Connecticut Light & Power pursuant to which we
will supply to Connecticut Light & Power at fixed prices a portion of
Connecticut Light & Power's aggregate retail load. The quantity of power to be
supplied is equal to 35% of Connecticut Light & Power's standard offer service
load during calendar year 2000, 40% during calendar years 2001 and 2002, and 45%
during calendar year 2003. We estimate that 45% of Connecticut Light & Power's
standard offer service load in 2003 will be approximately 2,000 MW at peak
requirement. The agreement terminates on December 31, 2003. This contract is
valued at $1,700 million. We believe the Connecticut facilities are
strategically positioned for sales into the New England Power Pool and have a
competitive advantage on transmission charges; we will operate these facilities
as peaking and intermediate facilities to take advantage of market volatility.

Middletown Facility. The Middletown facility was acquired for a purchase
price of $92.5 million. The Middletown facility, located in Middletown,
Connecticut, is a natural gas/oil-fired intermediate/ peaking plant consisting
of four units with a total capacity of 856 MW.

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<PAGE> 48

Montville Facility. The Montville facility was acquired for a purchase
price of $216.2 million. The Montville facility, located in Uncasville,
Connecticut, is a natural gas/oil-fired intermediate/peaking load plant
consisting of four units with a total capacity of 498 MW.

Norwalk Facility. The Norwalk facility was acquired for a purchase price
of $75.0 million. The Norwalk facility, located in Norwalk, Connecticut, is an
oil-fired, intermediate/peaking load plant consisting of three units with a
total capacity of 353 MW.

Devon Facility. The Devon facility was acquired for a purchase price of
$113.3 million. The Devon facility, located in Milford, Connecticut, is a
natural gas/oil-fired, intermediate/peaking load facility consisting of seven
units with a total capacity of 401 MW.

Connecticut Combustion Turbines. These six combustion turbines were
acquired for a purchase price of $22.3 million. These facilities, located in
Branford, Torrington Terminal, Franklin Drive and Cos Cob, Connecticut, are
oil-fired, peaking units consisting of six units with a total capacity of 127
MW.

SOUTH CENTRAL REGION

We own approximately 1,888 MW of generating capacity in the South Central
United States, primarily in Louisiana. Our South Central generation assets
consist primarily of our net ownership of 1,708 MW of power generation
facilities in New Roads, Louisiana that we acquired in March 2000 as a result of
a competitive bidding process following a Chapter 11 bankruptcy. We refer to
these facilities as the Cajun facilities. We believe that the Cajun facilities
and related infrastructure provide significant opportunities for expanding our
generation capacity in the region. We intend to further augment our recent
acquisition of the Cajun facilities in Louisiana with additional projects in the
area.

To achieve financing, cost and administrative advantages we formed a
regional holding company, NRG South Central Generating LLC, to hold our
ownership interest in Louisiana Generating LLC, the owner of the Cajun
facilities. Through NRG South Central Generating, we financed a significant
portion of the purchase price for the Cajun facilities by means of an $800
million debt financing completed in March 2000.

Through our ownership of 20% of Cogeneration Corporation of America, our
South Central assets also include two small, indirectly held interests in
facilities located in Oklahoma and Illinois.

The following table summarizes our South Central generation assets:

- ---------------

(1) Under construction, expected to be phased into service between June and
December 2000.

(2) Includes 100 MW expected to be in service June 2000.

(3) Includes 55 MW of net ownership interest in three facilities.

Cajun Facilities. The Cajun facilities were acquired in a competitive
bidding process following a Chapter 11 bankruptcy filing by their former owner,
Cajun Electric Power Cooperative, Inc. We paid

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<PAGE> 49

approximately $1.026 billion for these facilities. The Cajun facilities consist
of 100% of two gas-fired, intermediate/peaking power generation units with a
total capacity of 220 MW, which we collectively refer to as "Big Cajun I," and
two coal-fired, base-load power generation units with a total capacity of 1,150
MW and a 58% interest in a third coal-fired, base-load unit with a total
capacity of 575 MW, which we collectively refer to as "Big Cajun II." The Cajun
facilities have benefited from an extensive maintenance program over their
history and from capital expenditures in excess of $26 million from 1997 through
1999 while under the stewardship of Cajun Electric's bankruptcy trustee.

We believe the bankruptcy resulted from Cajun Electric's inability to
service approximately $4,200 million in secured debt provided in part by the
Rural Utilities Service of the United States Department of Agriculture, most of
which was incurred as a result of the purchase by Cajun Electric of a 30%
interest in the River Bend Nuclear Station Unit I, a nuclear power generation
facility located in Saint Francisville, Louisiana. Cajun Electric's 30% interest
in the River Bend nuclear facility was transferred to Entergy Gulf States in
December 1997. We have no ownership interest in the River Bend nuclear facility
or responsibility for any indebtedness of Cajun Electric to the Rural Utilities
Service or otherwise.

We sell most of the energy and capacity of the Cajun facilities to 11 of
Cajun Electric's former power cooperative members. Seven of these cooperatives
have entered into 25-year power purchase agreements with us, and four have
entered into two to four year power purchase agreements. In addition, we sell
power under contract to two municipal power authorities and one investor-owned
utility that were former customers of Cajun Electric. We estimate that payments
under the contracts with the 11 cooperatives will account for approximately 72%
of the Cajun facility's projected 2001 revenues, and that payments under the
contracts with the municipal power authorities and the investor-owned utility
will, in addition, account for an approximately 7% of such revenues.

Rocky Road Facility. We acquired a 50% interest in the Rocky Road facility
from Dynegy in December 1999 for a purchase price of approximately $60.0
million. The Rocky Road facility, located in East Dundee, Illinois, is a
gas-fired, peaking facility consisting of two units with a total capacity of 250
MW. The facility began commercial operations in June 1999 and received approval
for the installation of an additional 100 MW natural gas combustion turbine in
October 1999. The expansion is expected to be in service before the start of the
peak summer 2000 season. This facility sells energy into the ECAR and MAIN
wholesale power markets.

Sterlington Facility. The Sterlington facility is a 200 MW simple cycle,
gas-fired, peaking facility under construction in Sterlington, Louisiana.
Commercial operations are expected to be phased in between June and December
2000. We anticipate that the facility will sell power into five nearby power
pools.

WEST COAST REGION

We own approximately 1,603 MW of generating capacity on the West Coast of
the United States. Our West Coast generation assets consist primarily of a 50%
interest in West Coast Power LLC and a 58% interest in the Crockett Cogeneration
facility. In May 1999, we and Dynegy formed West Coast Power to serve as the
holding company for a portfolio of operating companies which own generation
assets in Southern California. These assets are currently comprised of the El
Segundo Generating Station, the Long Beach Generating Station, the Encina
Generating Station and 17 combustion turbines in the San Diego area. We believe
certain of our facilities and facility sites on the West Coast provide
opportunities for repowering or expansion of generating capacity.

We and Dynegy intend to utilize West Coast Power as a growth vehicle
through which future investments in assets serving the California power market
will be held. We believe that West Coast Power will benefit from synergies and
economies of scale through a common management structure, and that it has an
attractive mixture of revenue sources, including merchant and, as described
below, "must-run" plants. In addition, West Coast Power has power marketing
flexibility, in which a power shortage in one unit or plant can be compensated
for with excess power from another unit. Dynegy is providing power marketing
services to West Coast Power.

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<PAGE> 50

In June 1999, West Coast Power financed a significant portion of the
purchase price for its assets with a five-year, $362.5 million limited-recourse
bank facility secured by the limited liability company interests and project
assets of the El Segundo, Long Beach and Encina facilities and the San Diego
combustion turbines.

The Encina facility and the San Diego combustion turbines are currently
subject to "Reliability Must-Run" agreements with the California independent
system operator. These must-run agreements take the form of a call option
contract under which the California independent system operator will pay a fixed
capacity payment for the right to dispatch the unit, and variable costs are
passed through at cost. Must-run agreements with the California independent
system operator are intended to mitigate regional market power and make up for
inadequate power supplies in a specific area. The must-run agreements require us
to provide power and ancillary services when requested by the California
independent system operator. The must-run agreements have a one-year term, which
the California independent system operator may extend indefinitely for
additional one-year periods. We estimate that payment made under must-run
contracts will account for approximately 17% to 21% of the revenues from
projects owned by West Coast Power.

The following table summarizes our West Coast generation assets:

- ---------------

(1) Includes our net ownership interest in three small facilities.

El Segundo Facility. The El Segundo facility was acquired from Southern
California Edison Company in April 1998 for a purchase price of $87.7 million.
The El Segundo facility, located in El Segundo, California, is a gas-fired,
intermediate facility consisting of four units with a total capacity of 1,020
MW. The El Segundo facility sells electricity through the California power
exchange.

Encina Facility. The Encina facility was acquired from San Diego Gas &
Electric in May 1999 for a purchase price of $290.5 million. The Encina
facility, located in Carlsbad, California, is a gas-fired, intermediate/peaking
facility consisting of six units with a total capacity of 965 MW. The Encina
facility sells electricity through the California power exchange and under
must-run agreements.

Long Beach Facility. The Long Beach facility was acquired from Southern
California Edison in March 1998 for a purchase price of $29.8 million. The Long
Beach facility, located in Long Beach, California, is a gas-fired, peaking
facility consisting of nine units with a total capacity of 530 MW. The Long
Beach facility sells peak electricity and ancillary services through the
California power exchange.

San Diego Combustion Turbines. The San Diego combustion turbines were
acquired from San Diego Gas & Electric in May 1999 for a purchase price of $69.1
million. The San Diego combustion turbines, located on seven different sites in
San Diego County, California, consist of 17 combustion turbines with a total
capacity of 253 MW. The combustion turbines have the ability to provide spinning
reserve, black start capability, quick start capability, voltage support and
quick load capability for the ancillary services market. The combustion turbines
sell electricity through the California power exchange and under must-run
agreements.

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<PAGE> 51

Crockett Cogeneration Facility. We own a 58% interest in the Crockett
cogeneration facility located in Crockett, California on the San Francisco Bay.
We acquired our interest in November 1997 for $46.4 million. The Crockett
facility is a gas-fired facility with a total capacity of 240 MW. This facility
supplies all of the refinery steam needs of the adjacent C&H Sugar Company
refinery and sells capacity and energy under a modified, interim standard offer
power sales agreement to Pacific Gas & Electric Company, which expires in May
2026.

Mt. Poso Cogeneration Facility. We own a 39% interest in the Mt. Poso
cogeneration facility located near Bakersfield, California. We acquired an
initial 22% interest in November 1997 for $14.3 million and our remaining
interest in June 1998 for $4.7 million. The Mt. Poso facility is a coal-fired
facility with a total capacity of 50 MW. The facility sells steam to an adjacent
oil field owned by the project company and the capacity and energy are sold
under a long-term, interim standard offer power sales agreement to Pacific Gas &
Electric, which expires in May 2019.

PENDING MID-ATLANTIC ACQUISITIONS

In January 2000, we executed purchase agreements with subsidiaries of
Conectiv to acquire 1,875 MW of coal, gas and oil-fired electric generating
capacity and other assets. We will pay approximately $800 million for the
assets, a portion of which will be financed by project-level debt. The assets
include the BL England and Deepwater facilities in New Jersey, the Indian River
facility in Delaware and the Vienna facility in Maryland, and interests in the
Conemaugh (7.6%) and Keystone (6.2%) facilities in Pennsylvania. The purchase
also includes excess emissions allowances. Subject to receipt of required
regulatory approvals, we expect the acquisition to close in the fourth quarter
of 2000. Subject to final documentation, we will sell 500 MW of capacity and
associated energy to a subsidiary of Conectiv under a five-year power purchase
agreement commencing upon the closing of the acquisition.

The following table summarizes the generation assets we expect to acquire
from Conectiv:

<TABLE>
<CAPTION>
OUR OUR NET
TOTAL OWNERSHIP OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- ------ --------- ------------------ ---------
<S> <C> <C> <C> <C> <C>
BL England, New Jersey......... Conectiv/PJM 447 100.00% 447 Coal/Oil
Deepwater, New Jersey.......... Conectiv/PJM 239 100.00% 239 Gas/Coal/Oil
Indian River, Delaware......... Conectiv/PJM 784 100.00% 784 Coal
Vienna, Maryland............... Conectiv/PJM 170 100.00% 170 Oil
Conemaugh, Pennsylvania........ Conectiv/PJM 1,711 7.55% 129 Coal
Keystone, Pennsylvania......... Conectiv/PJM 1,711 6.17% 106 Coal
----- -----
Total........................ 5,062 1,875
===== =====
</TABLE>

DOMESTIC DEVELOPMENT

We are currently pursuing a number of development projects in our core
domestic markets. We have recently agreed to purchase 16 turbine generators from
GE Power Systems and two turbine generators from Siemens Westinghouse over a six
year period commencing in 2001. These new turbines, which we expect to install
at domestic facilities, will have a combined capacity of approximately 3,300 MW.

Our development activities in the United States also include greenfield
opportunities. With our partners, Salt River Project and Dynegy, we announced
plans to develop an 825 MW gas-fired, combined-cycle generation facility to
serve the growing demand for electricity in the greater Phoenix area. Final
negotiations on project agreements are in progress and site permitting has
begun.

INDEPENDENT POWER GENERATION PROJECTS -- INTERNATIONAL

AUSTRALIA

We are one of the largest independent power producers in Australia with a
net ownership interest of 1,312 MW in power generation facilities. We intend to
maintain our position in the market through

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<PAGE> 52

additional acquisitions and development of new projects. We will also look for
opportunities in selected countries in the Asia Pacific region to become
established within the region.

The following table summarizes our Australian generation assets:

<TABLE>
<CAPTION>
OUR NET
OUR OWNERSHIP
POWER MARKET/ TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER MW INTEREST (MW) FUEL TYPE
- ----------------------------- ------------- ------ --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Gladstone Power Station (Queensland),
Australia............................. QPTC; Boyne Smelter 1,680 37.50% 630 Coal
Loy Yang Power A (Victoria),
Australia............................. Victorian Pool 2,000 25.37% 507 Coal
Collinsville (Collinsville),
Australia............................. QPTC 192 50.00% 96 Coal
Energy Developments Limited (Various),
Australia............................. Various 274 29.14% 79 LFG/Methane
----- -----
Total................................. 4,146 1,312
===== =====
</TABLE>

Gladstone Facility. The Gladstone facility is a 1,680 MW coal-fired power
generation facility located in Gladstone, Australia. We acquired a 37.5%
ownership interest in the Gladstone facility for $64.9 million when the facility
was privatized in March 1994.

We are responsible for operation and maintenance of the Gladstone facility
pursuant to a 17 year operation and maintenance agreement that commenced in
1994, which includes an annual bonus based on availability targets. The
Gladstone facility sells electricity to the Queensland Power Trading Corporation
and also to Boyne Smelters Limited. Pursuant to an interconnection and power
pooling agreement, Queensland Power is obligated to accept all electricity
generated by the facility, subject to merit order dispatch, for an initial term
of 35 years.

Queensland Power also entered into a 35-year capacity purchase agreement
with each of the project's owners for such owner's percentage of the capacity of
the Gladstone facility, excluding that sold directly to Boyne Smelters. Under
the capacity purchase agreements, the facility owners are paid both a capacity
and an energy charge by Queensland Power. The capacity charge is designed to
cover the projected fixed costs allocable to Queensland Power, including debt
service and an equity return, and is adjusted to reflect variations in interest
rates. A capacity bonus is also available if the equivalent availability factor
exceeds 88% on a 24 month rolling average basis, and damages are payable by the
project's owners if it is less than 82% on that same basis. As of March 31,
2000, the two-year average equivalent availability factor was 88.4%.

The owners of Boyne Smelters have also entered into a power purchase
agreement with each of the project's owners, providing for the sale and purchase
of such owner's percentage share of capacity allocated to Boyne Smelters. The
term of each of these power purchase agreements is 35 years. The owners of Boyne
Smelters is obligated to pay to each of the project's owners a demand charge
that is intended to cover the fixed costs of supplying capacity to Boyne
Smelters, including debt service and return on equity. The owners of Boyne
Smelters are also obligated to pay an energy charge based on the fuel cost
associated with the production of energy from the Gladstone facility. Expansion
at Boyne Smelters resulted in an increase in capacity utilization from
approximately 41% in 1994 to 60% in 1999. We anticipate that the capacity
utilization will increase to approximately 64% in 2000.

Recent reforms in the Queensland electricity industry arising from the
introduction of the National Electricity Market have changed the regulatory
framework in which the Gladstone facility operates. In particular, the existing
arrangements relating to the commitment and dispatch of the facility and the
supply of power to customers of the facility no longer accord with the
mechanisms for buying and selling electricity in Queensland. As a result,
Queensland Power and the other parties to the project agreements have entered
into negotiations to alter the agreements to accomplish two goals: (1)
compliance with the new framework arising from the introduction of the National
Electricity Market, while ensuring that the actual operation of the facility is
similar to that under the existing agreements and (2) preservation, to the
extent possible, of the commercial positions of all parties. We expect amended
agreements to be

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<PAGE> 53

finalized and signed by the end of calendar year 2000 and we believe that any
amended agreements will have no impact on the risk profile or financial
performance of the Gladstone facility.

Effective December 9, 1999, the Australian government reduced the corporate
income tax rate. This reduction of Australian corporate income tax rates
resulted in an increase in our net income related to this facility of $3.9
million for 1999.

Loy Yang Facility. We have a 25.4% interest in Loy Yang Power which owns
and operates the 2,000 MW Loy Yang A brown coal fired thermal power station and
the adjacent Loy Yang coal mine located in Victoria, Australia. This interest
was purchased for AUS$340 million (approximately US$264.3 million at the time of
the acquisition) in 1997. The power station has four units, each with a 500 MW
boiler and turbo generator, which commenced commercial operation between July
1984 and December 1988. In addition, Loy Yang manages the common infrastructure
facilities that are located on the Loy Yang site, which service not only the Loy
Yang A facility, but also the adjacent Loy Yang B 1,000 MW power station, a
pulverized dried brown coal plant, and several other nearby power stations.

The wholesale electricity market in Australia is regulated under the
National Electricity Law which provides for a legally enforceable National
Electricity Code which defines the market rules. The code also makes provision
for the establishment of the National Electricity Market Management Company to
manage the power system, maintain system security and administer the spot
market. Under the rules of the National Electricity Market, the Loy Yang
facility is required to sell all of its output of electricity through the
competitive wholesale market for electricity operated and administered by the
National Electricity Market.

In the National Electricity Market power pool system, it is not possible
for a generator such as Loy Yang to enter into traditional power purchase
agreements. In order to provide a hedge against pool price volatility,
generators have entered into "contracts for differences" with distribution
companies, electricity retailers and industrial customers. These contracts for
differences are financial hedging instruments, which have the effect of fixing
the price for a specified quantity of electricity for a particular seller and
purchaser over a defined period. They establish a "strike price" for a certain
volume of electricity purchased by the user during a specified period;
differences between that "strike price" and the actual price set by the pool
give rise to "difference payments" between the parties at the end of the period.
Even if Loy Yang is producing less than its contracted quantity it will still be
required to make and will be entitled to receive difference payments for the
amounts set forth in its contracts for differences.

Loy Yang also has contracts with the Victorian distribution companies in
respect of regulated customer load. These contracts, called "vesting contracts,"
account for approximately 64% of Loy Yang's forecasted revenue from generation,
and provide some stability in Loy Yang's revenues until all these contracts
expire on December 31, 2000. Loy Yang's contracts for differences are generally
for a term of one to two years, and the volume of load covered by these
contracts will increase as vesting contracts expire. The combination of the
contracts for differences and the vesting contracts covered approximately 90% of
Loy Yang's load at March 31, 2000.

Energy prices in the Victoria region of the National Electricity Market of
Australia into which our Loy Yang facility sells its power have been
significantly lower than we had expected when we acquired our interest in the
facility. As a result, the Loy Yang project company is currently prohibited by
its loan agreements from making equity distributions to the project owners.
Based on our forecasted power prices, we expect that the Loy Yang project
company will fail to meet required coverage ratios under its loan agreements
beginning in the third quarter of 2001, which would constitute an event of
default. Moreover, if market prices in Victoria continue at current levels
(which are below our current power price projections) we expect that the Loy
Yang project company will be unable to service its long-term debt obligations
beginning in the first quarter of 2002. In either case, absent a restructuring
of the project company's debt, the project company's lenders would be allowed to
accelerate the project company's indebtedness. We could be required to write-off
all or a significant portion of our current $250 million investment in this
project as a result of such acceleration, a determination by the project company
that a write-down of its assets is required or our determination that we would
not be able to recover our investment in this project.

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<PAGE> 54

In February 2000, CMS Energy announced its intention to divest its 49.6%
ownership in the Loy Yang project. CMS Energy indicated that it intended to sell
its interest because the project was no longer of strategic value to its
portfolio and had not met its financial expectations. The remaining partners in
the Loy Yang project have rights of first refusal with respect to CMS Energy's
sale of its interest.

The 1999 reduction of Australian corporate income tax rates described above
resulted in a decrease in our net income related to this facility of $3.4
million for 1999.

Collinsville Facility. The Collinsville Power Station is a 192 MW
coal-fired power generation facility located in Collinsville, Australia. In
March 1996, we acquired a 50% ownership interest in the idled Collinsville
facility for US$11.9 million when it was privatized by the Queensland State
government. The Collinsville facility was recommissioned and commenced
operations on August 11, 1998. We and Transfield Holdings Pty Ltd, the project's
other 50% owner, have entered into an 18-year power purchase agreement with
Queensland Power under which Queensland Power will pay both a capacity and an
energy charge to the project's owners. The capacity charge is designed to cover
the projected fixed costs allocable to Queensland Power, including debt service
and an equity return. The energy charge is based on the fuel costs associated
with the production of energy from the facility.

Energy Developments Limited. Energy Developments Limited, a publicly
traded company listed on the Australian Stock Exchange, owns and operates
approximately 274 MW of generation primarily in Australia. Between February 1997
and April 1998, we acquired a total of 14,609,670 common shares and 16,800,000
convertible, non-voting preference shares of Energy Developments. We paid a
total of approximately AUS$69.1 million (US$44.5 million at the time of
acquisition), or AUS$2.20 (US$1.42) per share, for the shares, which represent
approximately a 29% ownership interest in Energy Developments. We have agreed to
restrictions on our ability to purchase more shares or to dispose of any
existing shares of Energy Developments. The preference shares do not become
convertible into common shares unless a takeover bid is made for Energy
Developments. In such event, if Energy Developments fails to comply with an
obligation to appoint directors nominated by the owner of the preference shares,
the preference shares can be converted at the option of the owner to common
shares on a share-for-share basis. The common shares of Energy Developments
traded at AUS$12.35 (approximately US$7.50) per share on March 31, 2000.

EUROPE

We have been a significant participant in the independent power generation
markets in Germany and the Czech Republic since our entry into those markets in
1993. Our growth in Europe was also augmented in early-2000 with the acquisition
of the Killingholme facility and the expected mid-2000 commencement of
commercial operations at the Enfield facility, both of which are located in the
United Kingdom. We intend to continue our growth efforts in these countries and
to develop projects in countries such as Poland, Estonia and Turkey.

The following table summarizes our European generation assets:

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Killingholme Facility. In March 2000, we acquired the 680 MW gas-fired
Killingholme combined-cycle, baseload facility in North Lincolnshire, England
from National Power plc. The purchase price was L390 million (approximately $615
million at the time of acquisition), subject to post-closing adjustments. We
financed the acquisition with a 19-year non-recourse credit facility that
provided for L235 million (approximately $374 million at March 31, 2000) for the
costs of the acquisition and L100 million (approximately $159 million at March
31, 2000) for letters of credit and working capital needs. We are selling power
from the facility into the wholesale electricity market of England and Wales.
The facility has a ten and one half year contract to purchase up to 70% of its
natural gas requirements from a subsidiary of Centrica plc. From January 1, 2000
through the date of the acquisition, we entered into a tolling agreement with
National Power pursuant to which we received revenues based on the prevailing
market prices for electricity in exchange for payments to National Power based
on the incremental operating cost of the facility.

We anticipate that prices for power in the wholesale electricity market of
England and Wales will decrease over the short term due to new trading rules
which are expected to come into effect and increased competition in this market.
This expected market trend was taken into account when we bid to acquire this
facility. We have entered into short-term agreements to sell a portion of the
output of the Killingholme facility, and, in the future, we intend to enter into
similar short-term and long-term agreements that will provide a degree of
stability to our revenues from the facility.

Enfield Facility. We hold a 25% interest in the Enfield Energy Center, a
396 MW gas-fired facility in the North London borough of Enfield, for which our
net investment is expected to be approximately $10.5 million. This project was
scheduled to commence commercial operation in November 1999, but due to problems
in the design and manufacture of the rotors and gas turbines, has been delayed
until June 2000. Although the construction contractor is contractually obligated
to make certain payments to partially compensate the owners of the project for
such delays, the obligation to make such payments in this situation and the
amount of such payments are being disputed. Nevertheless, we expect that once
the project is completed it will function as anticipated, and we do not expect
this delay to have a material adverse effect on the operations or financial
performance of the facility.

Schkopau Facility. In 1993, we acquired for $18.2 million an indirect 50%
interest in a German limited liability company, Saale Energie GmbH, which then
acquired a 41.9% interest in a 960 MW coal-fired power plant that was under
construction in the East German city of Schkopau. The first 425 MW unit of the
Schkopau plant began operation in January 1996, the 110 MW turbine in February
1996, and the second 425 MW unit in July 1996. The coal is provided under a
long-term contract by MIBRAG's Profen lignite mine.

Saale Energie sells its allocated 400 MW portion of the plant's capacity
under a 25-year contract with VEAG, a major German utility that controls the
high-voltage transmission of electricity in the former East Germany. VEAG pays a
price that is made up of three components, the first of which is designed to
recover installation and capital costs, the second to recover operating and
other variable costs, and the third to cover fuel supply and transportation
costs. We receive 50% of the net profits from these VEAG payments through our
ownership interest in Saale Energie.

MIBRAG. We indirectly purchased a 33 1/3% interest in the equity of
Mitteldeutsche Braunkohlengesellschaft mbH ("MIBRAG") in 1994 for $10.6 million.
MIBRAG owns coal mining, power generation and associated operations, all of
which are located south of Leipzig, Germany. MIBRAG was formed by the German
government following the reunification of East and West Germany to hold two
open-cast brown coal (lignite) mining operations, a lease on an additional mine,
three lignite-fired industrial cogeneration facilities and briquette
manufacturing and coal dust plants, all located in the former East Germany.
MIBRAG's cogeneration operations consist of the 110 MW Mumsdorf facility, the 86
MW Deuben facility and the 37 MW Wahlitz facility. These facilities provide
power and thermal energy for MIBRAG's coal mining operations and its briquette
manufacturing plants. All power not consumed by MIBRAG's internal operations is
sold under an eight-year power purchase agreement with Westsachsische Energie
Aktiengesellschaft, a recently privatized German electric utility. MIBRAG's
lignite mine

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operations include Profen, Zwenkau and Schleenhain with total estimated reserves
of 776 million metric tons, which are expected to last for more than 40 years.

A dispute has arisen as to coal transportation compensation payments to be
made to MIBRAG pursuant to the acquisition agreement by Bundesanstalt fur
vereinigungsbedingte Sonderaufgaben ("BvS"), a German governmental entity that
facilitated the privatization of MIBRAG. The size of the annual coal
transportation compensation payments fluctuates based on the volume of coal
transported to the Schkopau facility. The payment due for 1999 was approximately
50 million deutsche marks (approximately US$25 million) and has been received by
MIBRAG. However, BvS disputes its obligation to make any future compensation
payments. MIBRAG and BvS are engaged in active discussions to resolve this
disagreement. Although MIBRAG believes that a satisfactory resolution can be
negotiated, if that did not occur and BvS ceased to make any further annual
transportation compensation payments to MIBRAG, but MIBRAG were nevertheless
required to continue to transport coal to the Schkopau facility without the
benefit of these transportation compensation payments at the prices agreed in
1993 when the compensation and acquisition agreements were negotiated, it would
have a material adverse effect on MIBRAG.

Kladno Facilities. The Energy Center Kladno project, located in Kladno,
the Czech Republic, consists of two distinct phases. In 1994, we acquired an
interest in the existing coal-fired electricity and thermal energy facility that
can supply 28 MW of electrical energy and 150 MW equivalent of steam and heated
water. This facility historically supplied electrical energy to a nearby
industrial complex. The second phase was the expansion of the existing facility,
which was completed in January 2000, by the addition of 345 MW of new capacity,
271 MW of which is coal-fired and 74 MW of which is gas-fired. The original
project is owned by Energy Center Kladno, a Czech limited liability company in
which we own a 44.26% interest. The expansion project is held separately through
ECK Generating, a Czech limited liability company in which we own a 44.5%
interest.

LATIN AMERICA

We have pursued acquisition and development opportunities in Latin America
since the early 1990s. Initially, we participated as one of four original
sponsors of a private equity investment fund called Latin Power. More recently,
we acquired a 49% interest in the second largest generator of electricity in
Bolivia, Compania Boliviana de Energia Electrica S.A.-Bolivian Power Company
Limited ("COBEE"). We plan to selectively target new opportunities in Argentina,
Bolivia, Brazil, Chile and Peru, where we believe the more attractive
acquisition and greenfield opportunities exist in Latin America.

The following table summarizes our Latin American assets:

COBEE. In December 1996, we acquired for $81.8 million a 49% interest in
COBEE, the second largest generator of electricity in Bolivia. COBEE has entered
into contracts, which expire in 2008, with two Bolivian distribution companies
pursuant to which COBEE supplies electricity. All payments under these contracts
are made in United States dollars.

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COBEE operates its electric generation business under a 40-year concession
granted by the Bolivian government in 1990. Under this concession, COBEE is
entitled to earn a return of 9.0% on assets within its rate base. The Bolivian
Electricity Code also provides for the adjustment of rates to compensate COBEE
for any shortfall or to recapture any excess in COBEE's actual rate of return
during the previous year. COBEE periodically applies to the Superintendent of
Electricity for rate increases sufficient to provide its 9.0% rate of return
based on COBEE's current operating results and its projection of future revenues
and expenses. Under COBEE's concession, COBEE's assets are required to be
removed from the rate base in 2008.

Bulo Bulo Facility. We own a 30% interest in a Bolivian company that will
become the owner of the 87 MW gas-fired Bulo Bulo facility located in Carrasco,
Bolivia. The Bulo Bulo facility is under construction and is scheduled to enter
into commercial operations in mid-May 2000. The Bulo Bulo facility will operate
under a 30-year generation license and will sell its power to various customers
in Bolivia at market prices established under the rules of the Bolivian national
grid.

Latin Power Funds. The original Latin Power Fund was formed in 1993 as a
vehicle for making equity investments in independent power projects in Latin
America and the Caribbean. We invested $28 million in this original fund and
have committed $7 million to a similar fund, both of which are managed by
Scudder Kemper Investments. To date, these funds have committed a total of
approximately $169 million in investments, of which our share is approximately
$28 million.

INTERNATIONAL DEVELOPMENT

In 1999, we and our partners were selected as winning bidder for the 600 MW
Seyitomer Power Station and lignite mine in Kuthya, Turkey. Seyitomer is our
second successful bid in Turkey. In 1998, also with partners, we won a bid to
acquire the 450 MW coal-fired Kangal plant and lignite mine in central Turkey.
Our strategy is to build a long-term position in the high-growth energy market
in Turkey. In August 1999, the Turkish Parliament amended the Turkish
Constitution to allow international arbitration of disputes under concession
agreements. The lack of international arbitration for such contracts had been a
major stumbling block for many power projects in Turkey, including ours. The
Parliament passed additional enabling legislation in January 2000. As a result,
our projects, which were delayed pending resolution of this issue, are now
proceeding toward financial close, which may occur as early as the end of 2000.

In December 1996, we signed a development and cooperation agreement with
representatives of the Estonian Government and the state-owned utility. The
development and cooperation agreement defines the terms under which the parties
are to establish a plan to develop and refurbish the Balti and Eesti Power
Plants. Pursuant to the development and cooperation agreement, we submitted a
business plan to the Estonian government in which we have stated our willingness
to invest up to $67.25 million of equity into the project and to assist the
joint project in obtaining non-recourse debt to fund the required capital
improvements to the Balti and Eesti Power Plants, and we are continuing to
negotiate a detailed agreement. Because we have a policy of expensing all
development costs until there is a signed contract and board of directors'
approval, all such costs with respect to this project have been expensed.

We are currently evaluating additional development opportunities in
Australia, Turkey, Europe, and Latin America. In Australia, we are specifically
evaluating the privatization of South Australian power stations. In Europe, we
and our partners are investigating two projects in Poland.

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THERMAL ENERGY PRODUCTION AND TRANSMISSION FACILITIES; RESOURCE RECOVERY
FACILITIES; LANDFILL GAS FACILITIES

In the United States, our businesses in thermal heating and cooling,
landfill gas collection related generation and resource recovery continue to be
part of our diversified growth and operating strategies. These businesses give
us experience in non-traditional energy sources and in environmentally sound
energy alternatives.

<TABLE>
<CAPTION>
ACQUISITION OUR OWNERSHIP ENERGY PURCHASER/
NAME AND LOCATION OF FACILITY DATE CAPACITY(1) INTEREST MSW SUPPLIER
- ----------------------------- ----------- ------------------------------- ------------- ---------------------------
<S> <C> <C> <C> <C>
Thermal Energy Production and
Transmission Facilities
NRG Thermal, Inc.
Minneapolis Energy Center,
Minnesota............... 1993 Steam: 1,408 mmBtu/hr. (413 MW) 100.00% Approximately 90 commercial
Chilled water: 40,750 tons/hr. steam customers and 35
(143 MW) commercial chilled water
customers
Hennepin Co. Energy Center,
Minnesota............... (2) 290 mmBtu/hr (85 MW) (2) Various
San Francisco Thermal LLC,
California................ 1995 Steam; 490 mmBtu/hr. (143 MW) 100.00% Approximately 185 customers
(Purchased remaining 51%).. 1999
San Diego Power & Cooling,
California................ 1997 Chilled Water: 8,000 tons/hr. 100.00% Approximately 15 customers
(28 MW)
Pittsburgh Thermal LLC,
Pennsylvania.............. 1995 Steam; 240 mmBtu/hr. (70 MW) 100.00% Approximately 25 steam
customers and 25 chilled
water customers
(Purchased remaining
51%).................... 1999 Chilled Water; 10,180 tons/hr.
(36 MW)
Camas Power Boiler,
Washington................ 1997 200 mmBtu/hr. (59 MW) 100.00% Fort James Corp.
Grand Forks Air Force Base,
North Dakota.............. 1992 105 mmBtu/hr. (31 MW) 100.00% Grand Forks Air Force Base
Rock-Tenn, Minnesota........ 1992 Steam: 430 mmBtu/hr. (126 MW) 100.00% Rock-Tenn Company
Washco, Minnesota........... 1992 160 mmBtu/hr. (47 MW) 100.00% Andersen Corporation
Minnesota Correctional
Facility
Energy Center Kladno, Czech
Republic.................. 1994 512 mmBtu/hr. (150 MW) 44.26% City of Kladno
Resource Recovery Facilities
Newport, Minnesota.......... 1993 MSW: 1,500 tons/day 100.00% Ramsey and Washington
Counties
Elk River, Minnesota........ (3) MSW: 1,500 tons/day (3) Anoka, Hennepin, and
Sherburne Counties;
Tri-County Solid Waste
Management Commission
Penobscot Energy Recovery,
Maine..................... 1997 MSW: 800 tons/day 28.71% Bangor Hydroelectric
Company
Maine Energy Recovery,
Maine..................... 1997 MSW: 680 tons/day 16.25% Central Maine Power
NEO Corporation............. Various 175 MW 51.72% Various
</TABLE>

- ---------------

(1) Thermal production and transmission capacity is based on 1,000 Btus per
pound of steam production or transmission capacity. The unit mmBtu is equal
to one million Btus. Figures shown above are for 100% of each facility.

(2) We operate this facility on behalf of Hennepin County.

(3) We operate this facility on behalf of Northern States Power.

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NRG Thermal, Inc. NRG Thermal, Inc. owns the Minneapolis Energy Center and
operates the Hennepin County Energy Center. Minneapolis Energy Center provides
steam to approximately 90 customers and chilled water to approximately 35
customers in downtown Minneapolis, Minnesota pursuant to energy supply
agreements, which expire at varying dates from August 2000 to December 2019.
Historically, Minneapolis Energy Center has renewed its energy supply agreements
as they near expiration. With minor exceptions, these agreements are standard
form contracts providing for a uniform rate structure consisting of three
components: a demand charge designed to recover fixed capital costs, a
consumption charge designed to provide a per unit margin, and an operating
charge designed to pass through to customers all fuel, labor, maintenance,
electricity and other operating costs. The demand and consumption charges are
adjusted in accordance with the Consumer Price Index every five years.

North American Thermal Systems. We own 100% of North American Thermal
Systems LLC, which holds the operating assets of the San Francisco, California
and Pittsburgh, Pennsylvania district heating and cooling operations. The San
Francisco thermal system has approximately 185 customers. The Pittsburgh thermal
system has approximately 25 steam customers and 25 chilled water customers.

Rock-Tenn Facility. The Rock-Tenn process steam operation consists of a
five-mile closed-loop steam/condensate line that delivers steam to the Rock-Tenn
Company, a paper manufacturer in St. Paul, Minnesota. Rock-Tenn has a peak steam
capacity of 430 mmBtus per hour (126 MW equivalent). As a result of the
settlement of a 1987 dispute between the Rock-Tenn Company and a previous owner
of the steam operation, the Rock-Tenn Company prepaid revenues for future steam
service. As of December 31, 1999, deferred revenues remaining were approximately
$2.0 million.

NEO Corporation. NEO Corporation is a wholly-owned subsidiary of ours that
was formed to develop small power generation facilities, ranging in size from 1
to 50 MW, in the United States. NEO is currently focusing on the development and
acquisition of landfill gas projects and the acquisition of small hydroelectric
projects. NEO owns 30 landfill gas collection systems and has 55 MW of net
ownership interests in related electric generation facilities. As of March 31,
2000, NEO's investment in these projects totaled $73.3 million and loans to fund
development, construction and start-up amounted to $28.1 million. NEO also has
35 MW of net ownership interests in 18 small hydroelectric facilities. NEO
derives a substantial portion of its income as a result of the generation of
Section 29 tax credits, which for 1999 totaled $20.2 million. The existing tax
law authorizing these credits is scheduled to expire in 2007.

Resource Recovery Facilities. Our Newport, Minnesota resource recovery
facility can process over 1,500 tons of municipal solid waste per day, 90% of
which is used as fuel in power generation facilities in Red Wing and Mankato,
Minnesota. This facility, which was originally constructed and operated by
Northern States Power, was transferred to us in 1993. Pursuant to service
agreements with Ramsey and Washington Counties, which expire in 2007, we process
a minimum of 280,800 tons of municipal solid waste per year at the Newport
facility and receive service fees based on the amount of waste processed,
pass-through costs and certain other factors. We are also entitled to an
operation and maintenance fee, which is designed to recover fixed costs and to
provide us with a guaranteed amount for operating and maintaining the Newport
facility for the processing of 750 tons per day of municipal solid waste,
whether or not such waste is delivered for processing.

Since 1989, we have operated the Elk River resource recovery facility
located in Elk River, Minnesota, which can process over 1,500 tons of municipal
solid waste per day, 90% of which is recovered and used in power generation
facilities in Elk River and Mankato, Minnesota. Northern States Power owns 85%
of the Elk River facility and United Power Association owns the remaining 15%.
We also manage and operate an ash storage and disposal facility for the Elk
River facility at Northern States Power's Becker ash disposal facility, an
approved ash deposit site near Becker, Minnesota. We operate the Becker facility
on behalf of Northern States Power.

Resource recovery projects, such as our Newport facility and Northern
States Power's Elk River facility, historically were assured an adequate supply
of waste through state and local flow control legislation, which directed that
waste be disposed of in certain facilities. In 1994, the United States Supreme
Court held that such waste was a commodity in interstate commerce and,
accordingly, that flow

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control legislation that prohibited shipment of waste out of state was
unconstitutional. Since this ruling, resource recovery facilities have faced
increased competition from landfills in surrounding states in obtaining
municipal solid waste; however, this has not materially impacted our municipal
solid waste volumes to date.

COMPETITION

In addition, regulatory changes have also been proposed to increase access
to transmission grids by utility and non-utility purchasers and sellers of
electricity. The Energy Policy Act laid the ground work for a competitive
wholesale market for electricity. Among other things, the Energy Policy Act
expanded FERC's authority to order wholesale transmission, thus allowing QFs,
power marketers and EWGs to compete more effectively in the wholesale market. In
May 1996, FERC issued the first of the Open Access Rules, which requires
utilities to offer eligible wholesale transmission customers non-discriminatory
open access on utility transmission lines on a comparable basis to the
utilities' own use of the lines. In addition, the Open Access Rules direct the
regional power pools that control the major electric transmission networks to
file uniform, non-discriminatory open access tariffs. The Open Access Rules have
been the subject of rehearing at FERC and are now undergoing judicial review.
Over the past few years, Congress and the administration of President Clinton
have considered various pieces of legislation to restructure the electric
industry that would require, among other things, customer choice or repeal of
PUHCA. The debate is likely to continue and perhaps intensify. The effect of
enacting such legislation cannot be predicted with any degree of certainty.
Industry deregulation may encourage the disaggregation of vertically integrated
utilities into separate generation, transmission and distribution businesses. As
a result of these potential regulatory changes, significant additional
competitors could become active in the generation segment of our industry.

FINANCING

We fund our projects with a combination of non-recourse debt and equity
contributions. Historically, equity contributions infused into a project
consisted of cash from operations, corporate-level debt and capital
contributions from Northern States Power.

NON-RECOURSE FINANCING

As with our existing facilities, we expect to finance most of our future
projects with debt as well as equity. Leveraged financing permits the
development of projects with a limited equity base, but also increases the risk
that a reduction in revenues could adversely affect a particular project's
ability to meet its debt or lease obligations.

We have financed our principal power generation facilities primarily with
non-recourse debt that is repaid solely from the project's revenues and
generally is secured by the physical assets, major project contracts and
agreements, cash accounts and, in certain cases, our ownership interest, in that
project affiliate. This type of financing is referred to as "project financing."
True project financing is not available for all projects, including some assets
purchased out of bankruptcy, some merchant plants, some purchases of minority
stock positions in publicly traded companies and plants in certain countries
that lack a sufficiently well-developed legal system. Even in those instances,
however, we may still be able to finance a smaller portion of the total project
cost with project financing, with the remainder financed with debt that is
either raised or supported at the corporate rather than the project level.

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Project financing transactions generally are structured so that all
revenues of a project are deposited directly with a bank or other financial
institution acting as escrow or security deposit agent. These funds then are
payable in a specified order of priority set forth in the financing documents to
ensure that, to the extent available, they are used first to pay operating
expenses, senior debt service and taxes and to fund reserve accounts.
Thereafter, subject to satisfying debt service coverage ratios and certain other
conditions, available funds may be disbursed for management fees or dividends
or, where there are subordinated lenders, to the payment of subordinated debt
service.

In the event of a foreclosure after a default, our project affiliate owning
the facility would only retain an interest in the assets, if any, remaining
after all debts and obligations were paid. In addition, the debt of each
operating project may reduce the liquidity of our equity interest in that
project because the interest is typically subject both to a pledge securing the
project's debt and to transfer restrictions set forth in the relevant financing
agreements. Also, our ability to transfer or sell our interest in certain
projects is restricted by certain purchase options or rights of first refusal in
favor of our partners or the project's power and steam purchasers and certain
change of control restrictions in the project financing documents.

These project financing structures are designed to prevent the lenders from
looking to us or our other projects for repayment; that is, they are
"non-recourse" to us and our other project affiliates not involved in the
project, unless we or another project affiliate expressly agree to undertake
liability. We have agreed to undertake limited financial support for certain of
our project affiliates in the form of certain limited obligations and contingent
liabilities. These obligations and contingent liabilities take the form of
guarantees of certain specified obligations, indemnities, capital infusions and
agreements to pay certain debt service deficiencies. To the extent we become
liable under such guarantees and other agreements in respect of a particular
project, distributions received by us from other projects may be used by us to
satisfy these obligations. To the extent of these obligations, creditors of a
project financing may have recourse to us. See "Risk Factors -- We have
guaranteed obligations and liabilities of our project subsidiaries and
affiliates which would be difficult for us to satisfy if they all came due
simultaneously."

RECOURSE FINANCING

Recourse financing through corporate-level debt is provided in many
different forms. For instance, we have issued corporate-level debt and we
periodically provide corporate-level guarantees to various subsidiary
financings, mainly as an alternative to funding debt service reserve accounts
with project cash. Our goal is to have a recourse debt to recourse debt and
equity capitalization ratio of 40-50%. Our credit ratings are "Baa3" on review
for possible upgrade from Moody's Investors Service, Inc. and "BBB-" stable from
Standard & Poor's Ratings Services.

EXPOSURE TO CURRENCY FLUCTUATION

We seek to manage our exposure to changes in currency exchange rates by
matching the currency of revenues with the currency of expenses for each project
to create a natural hedge against fluctuations in the currency markets. At the
project level we typically sell power, buy fuel, and issue debt in the
functional currency of the project. At the corporate level, when a significant
source of operating cash is derived from a foreign investment, a portion of
corporate debt may be issued in that currency. A recent example of this was our
issuance in March 2000 of L160 million 7.97% Senior Reset Notes as a partial
hedge of our purchase of the Killingholme project in the United Kingdom.

After matching the currency of revenues and expenses, the remaining foreign
currency risk is hedged under the guidelines set forth in our foreign exchange
risk management policy. This policy requires us to hedge, when possible, all
known and highly probable cash flows over a twelve to eighteen month horizon
through the use of forward, swap and option contracts with highly rated
financial institutions as appropriate. We do not speculate on changes in foreign
exchange rates.

As part of our strategy, we hold assets and liabilities denominated in
foreign currencies. We adjust the value of these holdings quarterly to reflect
fluctuations in the values of their respective currencies. This can, and has,
generated non-cash income and losses.
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REGULATION

We are subject to a broad range of federal, state and local energy and
environmental laws and regulations applicable to the development, ownership and
operation of our United States and international projects. These laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before construction or operation of a power plant commences and
that, after completion, the facility operate in compliance with their
requirements. We strive to comply with the terms of all such laws, regulations,
permits and licenses and believe that all of our operating plants are in
material compliance with all such applicable requirements. We cannot assure you,
however, that in the future we will obtain all necessary permits and approvals
and that we will comply with all applicable statutes and regulations. In
addition, regulatory compliance for the construction of new facilities is a
costly and time-consuming process, and intricate and rapidly changing
environmental regulations may require major expenditures for permitting and
create the risk of expensive delays or material impairment of project value if
projects cannot function as planned due to changing regulatory requirements or
local opposition. Furthermore, we cannot assure you that existing regulations
will not be revised or that new regulations will not be adopted or become
applicable to us which could have an adverse impact on our operations.

In particular, the independent power markets in the United States, United
Kingdom, Australia and other countries are dependent on the existing regulatory
structure, and while we strive to take advantage of the opportunities created by
regulatory changes, it is impossible to predict the impact of regulatory changes
on our operations. Further, we believe that the level of environmental awareness
and enforcement is growing in most countries, including most of the countries in
which we intend to develop and operate new projects. Therefore, based on current
trends, we believe that the nature and level of environmental regulation to
which we are subject will become increasingly stringent. Our policy is therefore
to operate our projects in accordance with applicable local law or relevant
environmental guidelines adopted by the World Bank, whichever reflects the more
stringent level of control.

ENERGY REGULATION -- UNITED STATES

Federal Power Act. The Federal Power Act gives FERC exclusive rate-making
jurisdiction over wholesale sales of electricity and the transmission of
electricity in interstate commerce. Pursuant to the Federal Power Act, all
public utilities subject to FERC's jurisdiction are required to file rate
schedules with FERC prior to commencement of wholesale sales or interstate
transmission of electricity. Public utilities with cost-based rate schedules are
also subject to accounting, record-keeping and reporting requirements
administered by FERC.

PURPA and the Energy Policy Act. The enactment of PURPA in 1978 provided
incentives for the development of Qualifying Facilities or "QFs", which were
basically cogeneration facilities and small power production facilities that
utilized certain alternative or renewable fuels. QF status conveys two primary
benefits. First, regulations under PURPA exempt Qualifying Facilities from
PUHCA, most provisions of the Federal Power Act and the state laws concerning
rates, and financial and organizational regulations of electric utilities.
Second, FERC's regulations under PURPA require that (1) electric utilities
purchase electricity generated by QFs at a price based on the purchasing
utility's full avoided cost of producing power, (2) the electric utilities must
sell back-up, interruptible, maintenance and supplemental power to the QF on a
non-discriminatory basis, and (3) the electric utilities must interconnect with
any QF in its service territory, and, if required, transmit power if they do not
purchase it. We endeavor to acquire, develop and operate our QFs in a manner
that minimizes the risk of those plants losing their QF status. However, if a
facility were to lose QF status, we could attempt to avoid regulation under
PUHCA by qualifying the project as an EWG. The passage of the Energy Policy Act
in 1992 further encouraged independent power production by providing certain
exemptions from regulation for EWGs and FUCOs.

All of our subsidiaries that would otherwise be treated as public utilities
are currently QFs, EWGs or FUCOs. An EWG is an entity that is exclusively
engaged, directly or indirectly, in the business of owning or operating
facilities that are exclusively engaged in generation and selling electric
energy at wholesale.

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An EWG will not be regulated under PUHCA, but is subject to FERC and state
public utility commission regulatory reviews, including rate approval. EWGs do
not enjoy the same statutory and regulatory exemptions from state regulation as
are granted to QFs. In fact, however, since EWGs are only allowed to sell power
at wholesale, their rates must receive initial approval from FERC rather than
the states. All of our EWGs to date that have sought rate approval from FERC
have been granted market-based rate authority, which allows FERC to waive
certain accounting, record-keeping and reporting requirements imposed on public
utilities with cost-based rates. However, FERC customarily reserves the right to
suspend, upon complaint, market-based rate authority on a prospective basis if
it is subsequently determined that we or any of our EWGs exercised market power.
If FERC were to suspend market-based rate authority, it would most likely be
necessary to file, and obtain FERC acceptance of, cost-based rate schedules for
any of our EWGs. Also, the loss of market-based rate authority would subject the
EWGs to the accounting, record-keeping and reporting requirements that are
imposed on public utilities with cost-based rate schedules.

In addition, if there occurs a "material change" in facts that might affect
any of our subsidiaries' eligibility for EWG status, within 60 days of the
material change, the relevant EWG must (i) file a written explanation of why the
material change does not affect its EWG status, (ii) file a new application for
EWG status, or (iii) notify FERC that it no longer wishes to maintain EWG
status. If any of our subsidiaries were to lose EWG status, we, along with our
affiliates, would be subject to regulation under PUHCA as a public utility
company. Absent a substantial restructuring of our business, it would be
difficult for us to comply with PUHCA without a material adverse effect on our
business.

FUCOs are companies owning or operating PUHCA jurisdictional facilities not
located in the United States that derive no part of their income directly or
indirectly from United States public utility activities. FUCOs are exempted from
all provisions of PUHCA.

After the merger of Northern States Power and New Century Energies, our
shares of class A common stock will be owned by the surviving entity, Xcel
Energy. Xcel Energy will be subject to the provisions of various energy-related
laws and regulations, including regulation as a registered holding company under
PUHCA, and, in turn, we will be subject to regulations imposed by PUHCA. These
regulations include restrictions imposed upon aggregate investment by registered
holding companies in EWGs and FUCOs that are financed by contributions or
guarantees by the parent holding company. These investment restrictions, issued
pursuant to SEC regulations, limit registered holding company investment in
EWGs/FUCOs without prior SEC approval to 50% of the registered holding company's
consolidated retained earnings. The SEC has increased this "safe harbor"
investment cap to 100% of retained earnings for a number of registered holding
companies, and Xcel Energy has a pending request to raise its EWG/ FUCO
investment threshold to 100%.

The existence of this investment cap and the potential need to request SEC
waivers of or increases in the cap could delay or prevent any infusions of
capital from Xcel Energy that it may desire to make. This delay could be
increased by the fact that to obtain a waiver from the SEC typically would
require Xcel Energy to provide letters in support of such waiver from each state
public service commission which regulates Xcel Energy's utility business, which
could be time consuming and subject the waiver request to delays due to other
matters in dispute between Xcel Energy and any one of the 12 public service
commissions that are expected to regulate its utility business.

Another constraint is that we could be delayed in creating subsidiaries
that would not be involved in energy-related activities. We have created such
subsidiaries in the past to enable certain of our project subsidiaries to
acquire the status of an EWG, so any delay in this process could delay closings
on future transactions, which could in turn have an adverse impact on us.

Finally, transactions among us and our associate companies within the Xcel
system (including Xcel Energy) would need to be "at cost" unless they fit within
specified regulatory exceptions or were approved by the SEC. This constraint
could delay our execution of contracts between our subsidiaries and other
companies within the Xcel system, or limit terms to be contained in these
contracts, which could have an adverse impact on us.

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State Energy Regulation. In areas outside of wholesale rate regulation
(such as financial or organizational regulation), some state utility laws may
give their public utility commissions broad jurisdiction over steam sales or
EWGs that sell power in their service territories. The actual scope of that
jurisdiction over steam or independent power projects varies significantly from
state to state, depending on the law of that state.

ENVIRONMENTAL REGULATION -- UNITED STATES

The construction and operation of power projects are subject to extensive
environmental protection and land use regulation in the United States. These
laws and regulations often require a lengthy and complex process of obtaining
licenses, permits and approvals from federal, state and local agencies. If such
laws and regulations are changed and our facilities are not grandfathered,
extensive modifications to project technologies and facilities could be
required.

General. Based on current trends, we expect that environmental and land
use regulation will continue to be stringent. Accordingly, we plan to carefully
monitor and provide input on critical legislative initiatives that could impact
the operation of our facilities and to actively review proposed construction
projects that could subject us to stringent pollution controls imposed on "major
modifications" as defined under the Clean Air Act and changes in discharge
characteristics as defined under the Clean Water Act. The goal of these actions
will be to achieve compliance with applicable regulations, administrative
consent orders, and variances from applicable air-quality related regulations.

Clean Air Act. Most of our steam electric generating plants in the United
States are subject to Title IV of the Clean Air Act, which requires certain
fossil-fuel-fired combustion devices to hold sulphur dioxide "allowances" for
each ton of sulphur dioxide emitted. We plan to comply with the need for holding
the appropriate number of allowances by reducing sulphur dioxide emissions
through use of low sulphur fuels, installation of "back end" control technology,
and purchase of allowances on the open market. The costs of obtaining the
required number of allowances needed for future projects will be integrated into
our overall financial analysis of such projects.

Our plants are subject to a variety of regulations governing emissions of
nitrogen oxides ("NO(X)"). We are installing pollution control equipment at our
Somerset facility to implement an agreement between Montaup Electric Company and
the Attorney General for the Commonwealth of Massachusetts that requires the
Somerset facility to reduce NO(X) emissions by the year 2003. At the Encina
facility, we anticipate installing selective catalytic reduction devices on at
least two of the units in the next several years in order to meet mandated
pollution control requirements.

In addition to the above, our plants in the Northeast region are required
to hold NO(X) emissions allowances that equal, for each period from May 1 to
September 30, our NO(X) emissions from all of our facilities subject to the
program. Our facilities in El Segundo and Long Beach are subject to another
emissions trading program designed to control NO(X). We currently intend to
install selective catalytic reduction devices on one of the units at the El
Segundo facility in order to assist with our compliance with this program. As
for our facilities in the Northeast, other than Somerset, we intend to implement
a strategic plan for the purchase of NO(X) allowances and the reduction of NO(X)
emissions through the installation of pollution control equipment as
appropriate.

Title V of the Clean Air Act imposes federal requirements which dictate
that most of our fossil fuel-fired generation facilities must obtain operating
permits. All of our existing facilities subject to this requirement have
submitted timely Title V permit applications. However, most facilities have not
yet received final Title V permits. We do not anticipate that the costs of
obtaining final operating permits will be material.

In 1997, we were issued Administrative Orders and Notices of Civil
Administrative Penalty Assessments by the New Jersey Department of Environmental
Protection as a result of the

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operations of two cogeneration facilities that we operated. The Administrative
Orders and Notices of Civil Administrative Penalty Assessments resulted from
alleged air emissions in excess of permit limits that occurred prior to our
acquisition of these cogeneration facilities. Notwithstanding this fact, we
agreed to settle the outstanding administrative orders with the New Jersey
Department of Environmental Protection and executed an administrative consent
order with the New Jersey Department of Environmental Protection in March 2000.
The order requires us to pay a penalty in the amount of $102,500 within 60 days
of the execution of the order by both parties. To our knowledge, the New Jersey
Department of Environmental Protection has not yet executed the order.

As a result of alleged violations of visible emissions standards at the
Huntley, Dunkirk and Oswego facilities, the previous owner of these facilities
was in the process of negotiating a consent order with the New York Department
of Environmental Conservation to resolve such violations at the time we acquired
these facilities. Under the terms of our purchase agreements with the previous
owner, it will be responsible for any fines, penalties, assessments and related
losses resulting from its failure to comply with environmental laws and
regulations. We have agreed, in connection with our acquisition of these
facilities, to enter into separate consent orders for each of these facilities
to address on-going and potential future violations of visible emissions
standards. We believe that almost all of the visible emissions violations at the
Dunkirk and Oswego facilities are non-preventable events occurring as a result
of startups and shutdowns at those facilities that should not be subject to
penalties under the New York regulations. We are currently in discussions with
the New York Department of Environmental Conservation regarding this issue. We
are also currently in discussions with the New York Department of Environmental
Conservation regarding issues of alleged visible emissions violations at the
Huntley facility.

On October 14, 1999, Governor Pataki of New York announced that he was
ordering the New York Department of Environmental Conservation to require
further reductions of sulphur dioxide and nitrogen oxides emissions from New
York power plants, beyond that which is required under current federal and state
law. These reductions would be phased in between January 1, 2003 and January 1,
2007. Compliance with these emissions reductions requirements, if they become
effective, could have a material adverse impact on the operation of some of our
facilities located in the State of New York. In addition, the Connecticut
legislature has in the past considered, but rejected, legislation that would
require older electrical generation stations to comply with more stringent
pollution standards than are currently in effect in Connecticut for nitrogen
oxides and sulphur dioxide emissions. The legislation debated during the 2000
legislative session would have required our Connecticut facilities to rely on
more expensive fuels or install additional pollution control equipment. If such
legislation were to become law without reflecting the benefit of critical
elements of current federal emission reduction initiatives (e.g. market based
emissions trading between sources located across broad geographical regions),
our Connecticut facilities may be placed at a significant competitive
disadvantage.

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The Office of the Attorney General of the State of New York and the New
York Department of Environmental Conservation are investigating physical changes
made at the Huntley and Dunkirk facilities prior to our assumption of ownership.
The Attorney General has alleged that such changes represent major modifications
undertaken without obtaining the required permits. If these facilities did not
comply with the applicable permit programs, we could be required, among other
things, to install best available control technology to further reduce criteria
pollutant emissions from the Dunkirk and Huntley facilities, and we could become
subject to fines and penalties associated with the period of time we have
operated the facilities.

In addition, on November 3, 1999, the United States Department of Justice
filed suit against seven electric utilities for alleged violations of Clean Air
Act requirements related to modifications of existing sources at seventeen
utility generation stations located in the southern and midwestern regions of
the United States. The EPA also issued administrative notices of violation
alleging similar violations at eight other power plants owned by some of the
electric utilities named as defendants in the lawsuit, and also issued an
administrative order to the Tennessee Valley Authority for similar violations at
seven of its power plants. To date, no lawsuits or administrative actions have
been brought against us or any of our subsidiaries or affiliates or the former
owners of our facilities alleging similar violations, although Atlantic City
Electric Company, a subsidiary of Conectiv, has received information requests
from the EPA regarding the Deepwater and BL England facilities that we have
agreed to purchase. Lawsuits or administrative actions alleging similar
violations at our facilities could be filed in the future and, if successful,
could have a material adverse effect on our business.

Clean Water Act. Our existing facilities are also subject to a variety of
state and federal regulations governing existing and potential water/wastewater
discharges therefrom. Generally, such regulations are promulgated under
authority of the Clean Water Act and govern overall water/wastewater discharges,
through National Pollutant Discharge Elimination System ("NPDES") permits. Under
current provisions of the Clean Water Act, existing NPDES permits must be
renewed every five years, at which time permit limits are extensively reviewed
and can be modified to account for changes in regulations or program
initiatives. In addition, the permits have re-opener clauses which the federal
government can use to modify a permit at any time. Many of our existing
facilities have been operating under NPDES permits for a long time and have gone
through one or more NPDES permit renewal cycles and are currently in the process
of renewing their existing NPDES permits again. In addition, some facilities are
now lawfully operating under terms of an existing consent order.

We cannot assure you that existing laws and regulations will not be revised
or that new regulations will not be adopted or become applicable to us which
could have an adverse impact on our operations.

Site Remediation. Environmental site assessments have been prepared for
all of our recently acquired Northeast assets. The remediation activities at the
Arthur Kill facility, Astoria Gas Turbines and Somerset facility are still in
the study phase. As such, the remediation cost estimates are based on approaches
that have not been approved yet by the regulatory agencies involved.

For our Connecticut facilities, we are planning to conduct additional
studies to better quantify remedial need. Such studies include the preparation
of risk assessments to justify remedial actions proposed by us to the
Connecticut Department of Environmental Protection and the EPA.

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ENERGY REGULATION -- INTERNATIONAL

Most of the foreign countries in which we own or may acquire or develop
independent power projects have laws or regulations relating to the ownership or
operation of electric power generation facilities. These laws and regulations
are typically significant for independent power producers because they are still
changing and evolving in many countries. Although the type and nature of these
energy or electric laws vary widely from country to country, many of them
address some or all of the following issues:

- Establishment of an energy regulatory body;

- Financial or technical qualifications for independent power producers;

- Licensing requirements and procedures for independent power projects or
producers;

- Procedures for deciding whether the construction of new power plants
should be allowed;

- Procedures for selling or transferring existing generating facilities to
third parties;

- Price regulations; or

- Incentives for independent power developers or developers of new power
facilities.

We retain appropriate advisors in foreign countries and seek to design our
international development and acquisition strategy to comply with and take
advantage of opportunities presented by each country's energy laws and
regulations. There can be no assurance, however, that changes in such laws or
regulations could not adversely affect our international operations.

ENVIRONMENTAL REGULATIONS -- INTERNATIONAL

Although the type of environmental laws and regulations applicable to
independent power producers and developers varies widely from country to
country, many foreign countries have laws and regulations relating to the
protection of the environment and land use which are similar to those found in
the United States. Laws applicable to the construction and operation of electric
power generation facilities in foreign countries generally regulate discharges
and emissions into water and air, and also regulate noise levels. Air pollution
laws in foreign jurisdictions often limit the emissions of particles, dust,
smoke, carbon monoxide, sulfur dioxide, nitrogen oxides and other pollutants.
Water pollution laws in foreign countries generally limit wastewater discharges
into municipal sewer systems and require treatment of wastewater so that it
meets established standards. New projects and modifications to existing projects
are also subject, in many cases, to land use and zoning restrictions imposed in
the foreign country. In addition to the requirements currently imposed by a
particular country, most lenders to international development projects may
impose their own requirements relating to protection of the environment.

We believe that the level of environmental awareness and enforcement is
growing in most countries, including most of the countries in which we intend to
develop and operate new projects. Accordingly, based on current trends, we
believe that the nature and level of environmental regulation to which we are
subject will become increasingly stringent. Therefore, our policy is to operate
our projects in accordance with environmental guidelines adopted by the World
Bank or applicable local law, whichever reflects the more stringent level of
control.

OTHER PROPERTIES

In addition to the other properties discussed in this prospectus, we lease
approximately 60,000 square feet of office space at 1221 Nicollet Mall, Suite
700, Minneapolis, Minnesota 55403, under a five-year lease that expires in June
2002. We will be relocating our offices in the near future to approximately
100,000 square feet of office space in Minneapolis, Minnesota as to which we
have recently entered into a 10 year lease.

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We also own interests in the following power generation facilities that
have been idled: Madera, Chowchilla II and El Nido, San Joaquin Valley,
California; Jackson Valley Energy Partners, Ione, California; Artesia,
California; and Turners Falls, Massachusetts, which facilities represent an
aggregate equity generation capacity of 63 MW and a book value of $8.4 million.

EMPLOYEES

At December 31, 1999, we had 1,809 employees, approximately 400 of whom are
employed directly by us and approximately 1,409 of whom are employed by our
wholly-owned subsidiaries.

The majority of our domestic and international projects employ unionized
employees whose conditions of employment are covered by collective bargaining
agreements. We have experienced no significant labor stoppages or labor disputes
at our facilities.

LEGAL PROCEEDINGS

On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation,
filed a complaint in the Fourth Judicial District, Hennepin County, Minnesota
against us, asserting claims for injunctive relief and for damages as a result
of our alleged breach of a confidentiality letter agreement with Fortistar
relating to the Oswego facility. We disputed Fortistar's allegations and have
asserted numerous counterclaims. We have counterclaimed against Fortistar for
breach of contract, fraud and negligent misrepresentations and omissions,
tortuous interference with contract, prospective business opportunities and
prospective contractual relationships, unfair competition and breach of covenant
of good faith and fair dealing. We seek, among other things, dismissal of
Fortistar's complaint with prejudice and rescission of the letter agreement.

A temporary injunction hearing was held on September 27, 1999. The
acquisition of the Oswego facility was closed on October 22, 1999, following
notification to the court of our and Niagara Mohawk's intention to close on that
date. On January 14, 2000, the court denied Fortistar's request for a temporary
injunction. We intend to continue to vigorously defend the suit and believe
Fortistar's complaint to be without merit. No trial date has been set.

On October 12, 1999, we received a letter from the Office of the Attorney
General of the State of New York alleging that based on a preliminary analysis,
it believes that major modifications were made to our Huntley and Dunkirk
facilities during prior ownership of those facilities without the required
permits having been obtained. We believe that the Attorney General sent
identical letters to the owners and operators of all of the coal-fired utility
plants in New York. On January 12, 2000, we received a formal request from the
New York Department of Environmental Conservation seeking documents relating to
the matters covered by the Attorney General's letter. We understand that this
request supersedes the Attorney General's request. While we do not have
knowledge at this time that the previous owner of the Huntley and Dunkirk
facilities did not comply with the preconstruction permit requirement, we cannot
predict the outcome of the state's investigation, as we have only owned these
facilities since June 1999. Although we have a right to indemnification by the
previous owner for penalties resulting from the previous owner's failure to
comply with environmental laws and regulations, if these facilities did not
comply with the applicable permit requirements, we could be required, among
other things, to install specified pollution control technology to further
reduce pollutant emissions from the Dunkirk and Huntley facilities, and we could
become subject to fines and penalties associated with the period of time we have
operated the facilities.

The independent system operator for the New York Power Pool has recently
imposed price limitations on certain ancillary services sold in this market,
and, together with several New York utilities, has sought authority from FERC to
adjust the market-clearing prices for 10-minute reserve services on a
retroactive basis. We have joined several other independent power producers in
New York in filing a claim with FERC challenging these actions. If the
independent system operator prevails, our revenues from ancillary services sold
in the New York Power Pool could be substantially reduced. Although we would
attempt to adjust our business operations to mitigate the future impact of such
a ruling, the potential negative

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impact on our revenues for the first quarter of 2000 would include the potential
refund of approximately $8.0 million of revenues collected in February 2000 and
the inability to collect approximately $8.2 million included in revenues, but
not yet collected, for March 2000.

There are no other material legal proceedings pending, other than ordinary
routine litigation incidental to our business, to which we are a party. There
are no material legal proceedings to which an officer or director is a party or
has a material interest adverse us or our subsidiaries. There are no material
administrative or judicial proceedings arising under environmental quality or
civil rights statutes pending or known to be contemplated by governmental
agencies to which we are or would be a party.

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MANAGEMENT

The name, age and title of each of the directors and executive officers of
NRG as of March 31, 2000 are as set forth below:

<TABLE>
<CAPTION>
NAME AGE TITLE
- ---- --- -----
<S> <C> <C>
David H. Peterson.................... 58 Chairman of the Board, President, Chief Executive
Officer and Director
Gary R. Johnson...................... 53 Director
Cynthia L. Lesher.................... 51 Director
Edward J. McIntyre................... 49 Director
Leonard A. Bluhm..................... 54 Executive Vice President and Chief Financial Officer
Keith G. Hilless..................... 61 Senior Vice President, Asia Pacific
Craig A. Mataczynski................. 39 Senior Vice President, North America
John A. Noer......................... 53 Senior Vice President
Ronald J. Will....................... 59 Senior Vice President, Europe
James J. Bender...................... 43 Vice President, General Counsel and Corporate
Secretary
Brian B. Bird........................ 37 Vice President and Treasurer
Roy R. Hewitt........................ 54 Vice President, Administrative Services
Valorie A. Knudsen................... 43 Vice President, Corporate Strategy and Portfolio
Assessment
Louis P. Matis....................... 49 Vice President, Corporate Operating Services
David E. Ripka....................... 51 Vice President and Controller
</TABLE>

David H. Peterson has been Chairman of the Board of NRG since January 1994,
Chief Executive Officer since November 1993, President since 1989 and a Director
since 1989. Mr. Peterson was also Chief Operating Officer of NRG from June 1992
to November 1993. Prior to joining NRG, Mr. Peterson was Vice President,
Non-Regulated Generation for Northern States Power, and he has served in various
other management positions with Northern States Power during the last 20 years.
Mr. Peterson has also been a director of Northern States Power subsidiary Energy
Masters International, Inc. since November 1993.

Gary R. Johnson has been a Director of NRG since 1993 and Vice President
and General Counsel of Northern States Power since November 1991. Prior to
November 1991, Mr. Johnson was Vice President-Law of Northern States Power from
January 1989, acting Vice President from September 1988 and Director of Law from
February 1987, and he has served in various management positions with Northern
States Power during the last 20 years. Mr. Johnson has also been a director of
Northern States Power's subsidiaries Seren Innovations, Inc. since November 1996
and Viking Gas Transmission Company since March 1997.

Cynthia L. Lesher has been a Director of NRG since June 1996 and became
President of Northern States Power-Gas in July 1997. Prior to July 1997, Ms.
Lesher was Vice President-Human Resources of Northern States Power since March
1992 after serving as Director of Power Supply-Human Resources since 1991. Ms.
Lesher became Area Manager, Electric Utility Operations, in 1990, and previously
served as Manager, Metro Credit, and Manager, Occupational Health and Safety.
Prior to joining Northern States Power, Ms. Lesher was a training and
development consultant at the Center for Continuing Education in Minneapolis.
From 1970 to 1977, she held a variety of positions with Multi Resource Centers,
Inc., also in Minneapolis. Ms. Lesher has also been a director and Chairperson
of Northern States Power subsidiaries Black Mountain Gas Company since July
1999, Natrogas, Incorporated since December 1999 and Viking Gas Transmission
Company since July 1997, where she has served as Chairperson since June 1998.

Edward J. McIntyre has been a Director of NRG since 1993 and Vice President
and Chief Financial Officer of Northern States Power since January 1993. Mr.
McIntyre has also been a director of Northern States Power subsidiaries Eloigne
Company since April 1993 and Energy Masters International, Inc. since September
1994. Mr. McIntyre served as President and Chief Executive Officer of Northern
States Power-Wisconsin, a wholly-owned subsidiary of Northern States Power, from
July 1990 to December 1992, as
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Vice President Gas Utility from November 1985 to June 1990, and he has served in
various other management positions since joining Northern States Power in 1973.

Leonard A. Bluhm has been Executive Vice President and Chief Financial
Officer of NRG since January 1997. Immediately prior to that, he served as the
first President and Chief Executive Officer of Cogeneration Corporation of
America. Mr. Bluhm was Vice President, Finance of NRG from January 1993 through
April 1996. Mr. Bluhm was Chief Financial Officer of Cypress Energy Partners, a
wholly-owned project subsidiary of NRG, from April 1992 to January 1993, prior
to which he was Director, International Operations and Manager, Acquisitions and
Special Projects of NRG from 1991. Mr. Bluhm previously served for 20 years in
various financial positions with Northern States Power.

Keith G. Hilless has been Senior Vice President, Asia Pacific of NRG and
Managing Director of NRG Asia Pacific since July 1998, prior to which he was a
senior executive since August 1997. Prior to joining NRG, Mr. Hilless was Chief
Executive Officer of the Queensland Transmission and Supply Corporation where he
had served since January 1995. From 1993 to January 1995, Mr. Hilless served as
the Queensland Electricity Commissioner.

Craig A. Mataczynski has been Senior Vice President, North America of NRG
and President and Chief Executive Officer of NRG North America, since July 1998.
From December 1994 until July 1998, Mr. Mataczynski served as Vice President,
U.S. Business Development of NRG. From May 1993 to January 1995, Mr. Mataczynski
served as President of NEO Corporation, NRG's wholly-owned subsidiary that
develops small electric generation projects within the United States. Prior to
joining NRG, Mr. Mataczynski worked for Northern States Power from 1982 to 1994
in various positions, including Director, Strategy and Business Development and
Director, Power Supply Finance.

John A. Noer has been Senior Vice President of NRG and President of NRG
Worldwide Operations since January 1, 2000. Immediately prior to that he served
as President-NSP Combustion and Hydro Generation for Northern States Power
Company and as a director of NRG since June 1997. He was President and CEO of
Northern States Power Wisconsin, a wholly-owned subsidiary of Northern States
Power, since January 1993. Prior to joining Northern States Power Wisconsin, Mr.
Noer was President of Cypress Energy Partners, a project subsidiary of NRG, from
March 1992 to January 1993. Prior to joining Cypress Energy Partners, Mr. Noer
held various management positions with Northern States Power since joining the
company in September 1968.

Ronald J. Will has been Senior Vice President, Europe of NRG and President
and Chief Executive Officer of NRG Europe since July 1998. From March 1994 until
July 1998, Mr. Will served as Vice President, Operations and Engineering of NRG,
prior to which he served as Vice President, Operations from June 1992. Prior to
joining NRG, he served as President and Chief Executive Officer of NRG Thermal
from February 1991 to June 1993. Prior to February 1991, Mr. Will served in a
variety of positions with Norenco, a wholly-owned thermal services subsidiary of
NRG, including Vice President and General Manager from August 1989 to February
1991.

James J. Bender has been Vice President, General Counsel and Secretary of
NRG since June 1997. He served as the General Counsel of the Polymers Division
of Allied Signal Inc. from May 1996 until June 1997. From June 1994 to May 1996,
Mr. Bender was employed at NRG, acting as Senior Counsel until December 1994 and
as Assistant General Counsel and Corporate Secretary from December 1994 to May
1996.

Brian B. Bird has been Vice President and Treasurer of NRG since June 1999
and Treasurer since June 1997, prior to which he was Director of Corporate
Finance and Treasury for Deluxe Corporation in Shoreview, Minnesota from
September 1994 to May 1997. Mr. Bird was Manager of Finance for the Minnesota
Vikings professional football team from March 1993 to September 1994. Mr. Bird
held several financial management positions with Northwest Airlines in
Minneapolis, Minnesota from 1988 to March 1993.

Roy R. Hewitt has been Vice President, Administrative Services at NRG since
February 1999. He has nearly 30 years experience in the power industry including
24 years with Northern States Power and

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six years with NRG. Mr. Hewitt joined NRG in 1994 as a member of the senior
management team with NRG's Gladstone Power Station project in Queensland,
Australia. In 1996, he returned to NRG's corporate headquarters as Executive
Director, Human Resources. In 1997, Mr. Hewitt returned to Australia as Managing
Director of the Gladstone Project and later served as Executive Director,
Operations and Engineering for NRG's Asia-Pacific region headquartered in
Brisbane, Australia.

Valorie A. Knudsen has been Vice President, Corporate Strategy and
Portfolio Assessment since February 2000. She has served as Vice President,
Emerging Markets; Vice President, Finance and as Controller since joining NRG in
August 1993. Prior to joining NRG, Ms. Knudsen served in various managerial
accounting positions from November 1987 to July 1993 with Carlson Companies,
Inc. Before joining Carlson Companies, Ms. Knudsen practiced as a Certified
Public Accountant for seven years.

Louis P. Matis has been Vice President, Corporate Operating Services of NRG
since July 1998, prior to which he served in a variety of roles at Northern
States Power. Mr. Matis joined Northern States Power in 1983 as a civil engineer
and managed the construction and engineering of numerous projects. In 1990 he
joined Fuel Resources as Manager and then Director, managing a portfolio of
nuclear fuel, fossil fuel and transportation contracts as well as a nuclear fuel
design group for Northern States Power. In 1996, he became General Manager of
fossil fuel plants for Northern States Power. Upon closing of the pending merger
between Northern States Power and New Century Energies, Mr. Matis will become an
employee of Xcel Energy.

David E. Ripka has been Vice President and Controller of NRG since June
1999, and Controller since March 1997. Prior to joining NRG, Mr. Ripka held a
variety of positions with Northern States Power for over 20 years, including
Assistant Controller and General Manager of Accounting Operations and Director
of Audit Services. Upon closing of the pending merger between Northern States
Power and New Century Energies, Mr. Ripka will become an employee of Xcel
Energy.

BOARD OF DIRECTORS

Upon completion of this offering, our board of directors will consist of
six directors: Mr. Peterson and five employees of Northern States Power or New
Century Energies. We anticipate that shortly after the completion of this
offering, our board of directors will be expanded to consist of nine members. We
have agreed with the NYSE that we will appoint two independent directors within
90 days of the completion of this offering and a third independent director not
later than one year after the completion of this offering.

COMMITTEES OF THE BOARD OF DIRECTORS

Our board of directors will have a compensation committee and an audit
committee.

Compensation Committee. The compensation committee will consist of at
least two of the independent directors to be appointed after this offering. The
compensation committee will review and make recommendations to our board of
directors concerning salaries and incentive compensation for our officers and
employees. The compensation committee also will administer the NRG 2000
Long-Term Incentive Compensation Plan.

Audit Committee. The audit committee will consist entirely of independent
directors who are "financially literate," and possess "accounting or related
financial management expertise" as required under applicable regulations. The
audit committee will review and monitor our financial statements and accounting
practices, make recommendations to our board of directors regarding the
selection of independent auditors and review the results and scope of the audit
and other services provided by our independent auditors.

COMPENSATION OF DIRECTORS

Directors who are also employees of NRG or Northern States Power do not
receive any compensation for their services as directors. Directors who are not
employees of NRG or Northern States Power will receive an annual fee of $30,000
and a fee of $1,000 per meeting plus reasonable travel expenses. Non-
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employee directors are also entitled to participate in the NRG 2000 Long-Term
Incentive Compensation Plan, as described below. Following the offering we
expect to issue options to purchase 5,000 shares of our common stock to each of
our independent directors.

Each of our directors has an indemnification agreement that entitles them
to indemnification for claims asserted against them in their capacity as
directors to the fullest extent permitted by Delaware law.

COMPENSATION OF EXECUTIVE OFFICERS AND OTHER INFORMATION

The following table shows the cash compensation paid or to be paid by us or
any of our subsidiaries, as well as certain other compensation paid or accrued,
during the fiscal years indicated to our Chief Executive Officer and our four
next highest paid executive officers, which we refer to as our "Named
Executives," in all capacities in which they serve:

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
LONG-TERM
ANNUAL COMPENSATION COMPENSATION
--------------------------------------------------- ------------
OTHER ANNUAL LTIP ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) PAYOUTS COMPENSATION
- --------------------------- ---- -------- --------------- --------------- ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
David H. Peterson............................ 1999 $367,992 $192,970 $6,131 $155,995 $33,201(2)
Chairman, President and Chief Executive 1998 345,826 290,220 4,922 7,724 17,777
Officer 1997 300,000 127,000 3,272 0 15,517
Craig A. Mataczynski......................... 1999 246,250 150,000 4,706 15,533 15,251(3)
Senior Vice President, North America 1998 192,091 118,627 3,871 2,538 5,832
1997 163,336 60,804 1,347 0 39,962
Ronald J. Will............................... 1999 214,160 83,564 5,162 50,075 15,275(4)
Senior Vice President, 1998 188,640 107,341 4,130 3,182 5,597
Europe 1997 163,507 38,667 1,627 0 4,870
James J. Bender.............................. 1999 213,746 100,000 6,528 19,729 6,172(5)
Vice President, General Counsel and 1998 198,758 108,892 7,331 4,810 49,491
Corporate Secretary 1997 93,282 89,750(6) 6,239 0 42,391
Leonard A. Bluhm............................. 1999 194,590 72,150 5,265 50,489 12,814(7)
Executive Vice President 1998 189,174 66,500 5,156 3,172 5,060
and CFO 1997 179,586 48,190 2,462 0 4,581
</TABLE>

- ---------------

(1) Amounts reimbursed during the fiscal year for the payment of taxes on fringe
benefits.

(2) Includes a $15,481 excess vacation payout; $8,707 of Incentive Pension
Makeup Plan contributions; $7,000 of universal life insurance premiums;
$1,114 of Employee Stock Ownership Plan contributions; and $900 of 401(k)
Plan matching contributions.

(3) Includes a $9,308 excess vacation payout; $3,559 of Incentive Pension Makeup
Plan contributions; $1,114 of Employee Stock Ownership Plan contributions;
$900 of 401(k) Plan matching contributions; and $370 of term life insurance
premiums.

(4) Includes a $9,288 excess vacation payout; $3,220 of Incentive Pension Makeup
Plan contributions; $1,114 of Employee Stock Ownership Plan contributions;
$900 of 401(k) Plan matching contributions; and $752 of term life insurance
premiums.

(5) Includes $3,267 of Incentive Pension Makeup Plan contributions; $1,114 of
Employee Stock Ownership Plan contributions; $900 of 401(k) Plan matching
contributions; and $1,406 of term life insurance premiums.

(6) Includes $25,000 paid as a signing bonus.

(7) Includes a $7,399 excess vacation payout; $1,995 of Incentive Pension Makeup
Plan contributions; $1,114 of Employee Stock Ownership Plan contributions;
$900 of 401(k) Plan matching contributions; and $752 of term life insurance
premiums.

STOCK OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS

All of our stock is currently owned by Northern States Power and thus none
of our officers and directors owns any of our common stock.

The following table sets forth certain information with respect to the
beneficial ownership of Northern States Power's common stock by each director,
certain of our executive officers and all of our directors and

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<PAGE> 74

executive officers as a group. Except as otherwise indicated in the footnotes,
each individual has sole voting and investment power with respect to the shares
set forth in the following table.

<TABLE>
<CAPTION>
SHARES BENEFICIALLY OWNED INCLUDE
---------------------------------------------
SHARES
INDIVIDUALS HAVE
SHARES PERCENT RIGHTS TO ACQUIRE
BENEFICIALLY OF WITHIN
NAME OF BENEFICIAL OWNER OWNED(1) CLASS(2) 60 DAYS(3)
------------------------ ------------ -------- -----------------
<S> <C> <C> <C>
David H. Peterson............................ 23,664 * 8,839
Gary R. Johnson.............................. 81,493 * 69,245
Cynthia L. Lesher............................ 59,262 * 46,517
Edward J. McIntyre........................... 124,928 * 97,840
Leonard A. Bluhm............................. 10,859 * 5,679
Craig A. Mataczynski......................... 2,929 * 1,546
Ronald J. Will............................... 17,063(4) * 5,444
James J. Bender.............................. 211 * 0
All executive officers and directors as a
group (15 persons)......................... 434,379 * 314,534
</TABLE>

- ---------------

* Less than one percent of outstanding shares.

(1) Beneficial ownership means the sole or shared power to vote, or to direct
the voting of, a security, or investment power with respect to a security,
or any combination thereof.

(2) Based on 156,589,316 shares of Northern States Power common stock
outstanding on March 15, 2000.

(3) Indicates shares of the Northern States Power common stock that certain
executive officers have the right to acquire within 60 days. Shares
indicated are included in the Shares Beneficially Owned column.

(4) Includes 4,467 shares that are held solely by Mr. Will's spouse in which he
disclaims any interest.

STOCK OPTION HOLDINGS

The following table sets forth information concerning fiscal year-end value
of unexercised options held by the Named Executives under the Northern States
Power Executive Stock Option Program. Prior to the existence of the NRG Equity
Plan, NRG executives participated in the Northern States Power Executive Stock
Option Program.

AGGREGATED OPTION/SAR FISCAL YEAR-END VALUES

<TABLE>
<CAPTION>
NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED IN-THE-MONEY
UNEXERCISED OPTIONS/SARS AT FY-END(1) OPTIONS/SARS AT FY-END(2)
NAME EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
- ---- ------------------------------------- ---------------------------------
<S> <C> <C>
David H. Peterson............... 16,879/0 $29,583/$0
Leonard A. Bluhm................ 6,593/0 $ 8,992/$0
Craig A. Mataczynski............ 1,545/0 $ 959/$0
Ronald J. Will.................. 5,457/0 $ 8,846/$0
James J. Bender................. 0/0 $ 0/$0
</TABLE>

- ---------------

(1) These options to acquire Northern States Power Stock were granted to the
Named Executives for services rendered to NRG and its subsidiaries.

(2) Northern States Power's share price on December 31, 1999 was $19.50.

PENSION PLAN

We participate in Northern States Power's noncontributory, defined benefit
pension plan that covers substantially all of our employees. As of January 1,
1999, pension benefits were changed. Prior to

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<PAGE> 75

January 1, 1999, each nonbargaining employee was given an opportunity to choose
between two retirement programs, the traditional program and the pension equity
program.

Under the traditional program, the pension benefit is computed by taking
the highest average compensation multiplied by credited years of service with a
50% offset for social security benefits. The annual compensation used to
calculate the average compensation uses base salary for the year and bonus
compensation paid in that same year. After an employee has reached 30 years of
service, no additional years of service are used in determining the pension
benefit under the traditional program. The benefit amounts under the traditional
program are computed in the form of a straight-line annuity.

Under the pension equity program, the annual compensation used to calculate
average compensation uses base salary for the year and bonus compensation paid
in that same year, with no maximum on the number of years used to determine the
pension benefit. The benefit amounts under the pension equity program are
computed in the form of a lump sum. The formula for determining the lump sum is
average compensation multiplied by credited years of service times 10% with a
50% offset for social security. The benefit amounts can be paid in a lump sump
or in the form of a straight-line annuity, at the option of the employee.

Both programs feature a cash balance side account, which credits $1,400
annually, plus interest each year. The opening balance as of January 1, 1999 is
$1,400 times years of service.

The following table illustrates the approximate retirement benefits payable
to employees retiring at the normal retirement age of 65 years under the
traditional program:

<TABLE>
<CAPTION>
ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED
------------------------------------------------------------
YEARS OF SERVICE
------------------------------------------------------------
AVERAGE COMPENSATION (LAST 4 YEARS) 5 10 15 20 25 30
- ----------------------------------- ------- ------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
50,000........................... $ 3,500 $ 7,000 $10,500 $ 14,000 $ 18,000 $ 21,500
100,000........................... 7,500 15,500 23,000 30,500 38,000 46,000
150,000........................... 11,500 23,500 35,000 47,000 58,500 70,500
200,000........................... 16,000 31,500 47,500 63,000 79,000 95,000
250,000........................... 20,000 40,000 59,500 79,500 99,500 119,500
300,000........................... 24,000 48,000 72,000 96,000 120,000 144,000
350,000........................... 28,000 56,000 84,000 112,500 140,500 168,500
400,000........................... 32,000 64,500 96,500 128,500 160,500 193,000
450,000........................... 36,000 72,500 108,500 144,500 181,000 217,000
500,000........................... 40,500 80,500 121,000 161,000 201,500 241,500
550,000........................... 44,500 88,500 133,000 177,500 221,500 266,000
600,000........................... 48,500 97,000 145,500 193,500 242,000 290,500
650,000........................... 52,500 105,000 157,500 210,000 262,500 315,000
700,000........................... 56,500 113,000 170,000 226,500 283,000 339,500
750,000........................... 60,500 121,500 182,000 242,500 303,500 364,000
</TABLE>

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<PAGE> 76

The following table illustrates the approximate retirement benefits payable
to employees retiring at the normal retirement age of 65 years under the pension
equity program if paid in the form of a straight-line annuity:

<TABLE>
<CAPTION>
ESTIMATED ANNUAL BENEFITS FOR YEARS OF SERVICE INDICATED
------------------------------------------------------------
YEARS OF SERVICE
------------------------------------------------------------
AVERAGE COMPENSATION (LAST 4 YEARS) 5 10 15 20 25 30
- ----------------------------------- ------- ------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
50,000........................... $ 3,500 $ 7,000 $11,000 $ 15,500 $ 20,500 $ 26,500
100,000........................... 6,000 12,000 18,500 25,500 33,000 41,500
150,000........................... 8,500 17,000 26,000 35,500 46,000 57,000
200,000........................... 11,000 22,000 33,500 45,500 58,500 72,000
250,000........................... 13,500 27,000 41,500 56,000 71,000 87,000
300,000........................... 16,000 32,500 49,000 66,000 83,500 102,500
350,000........................... 18,500 37,500 56,500 76,000 96,500 117,500
400,000........................... 21,000 42,500 64,000 86,000 109,000 133,000
450,000........................... 23,500 47,500 71,500 96,500 121,500 148,000
500,000........................... 26,000 52,500 79,500 106,500 134,500 163,000
550,000........................... 28,500 57,500 87,000 116,500 147,000 178,500
600,000........................... 31,000 62,500 94,500 127,000 159,500 193,500
650,000........................... 33,500 67,500 102,000 137,000 172,500 208,500
700,000........................... 36,000 73,000 109,500 147,000 185,000 224,000
750,000........................... 39,000 78,000 117,000 157,000 197,500 239,000
</TABLE>

As of March 31, 2000, each of the Named Executives had the following
credited service: Mr. Peterson, 36 years, Mr. Bluhm, 29 years, Mr. Mataczynski,
18 years, Mr. Will, 40 years, and Mr. Bender, 5 years. Mr. Mataczynski and Mr.
Bender have selected the pension equity program; all other Named Executives have
selected the traditional program.

LONG-TERM INCENTIVE PLAN COMPENSATION

The following table sets forth information concerning awards during fiscal
1999 to each of the Named Executives under the NRG Equity Plan, described below.

LONG-TERM INCENTIVE PLAN AWARDS IN LAST FISCAL YEAR

<TABLE>
<CAPTION>
PERFORMANCE OR OTHER PERIOD
UNTIL MATURATION
NAME UNITS OR OTHER RIGHTS (#) OR PAYOUT
- ---- ------------------------- ---------------------------
<S> <C> <C>
David H. Peterson.............................. 41,080 8 years
Leonard A. Bluhm............................... 9,070 8 years
Craig A. Mataczynski........................... 12,100 8 years
Ronald J. Will................................. 10,000 8 years
James J. Bender................................ 10,000 8 years
</TABLE>

NRG EQUITY PLAN

Prior to the offering, our officers and other selected employees
participated in the NRG Equity Plan. This discretionary plan was established in
1993 to promote the achievement of long-term financial objectives by linking the
long-term incentive compensation of our employees to the achievement of value
creation; to attract and retain employees of outstanding competence; to
encourage teamwork among employees; and to provide employees with an opportunity
for long-term capital accumulation. The plan provided grants of "equity units"
that were intended to simulate stock options. Grant size was based on the
participant's position in the company and base salary. The Compensation
Committee of the board of directors administered the plan for our officers. The
Chief Executive Officer administered the plan for other employees.

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<PAGE> 77

Equity grants were generally made annually at the discretion of the board
of directors with the grant price consistent with the most recent valuation of
equity units. Equity unit valuations were performed annually by a nationally
recognized outside valuation firm selected by the board of directors. The value
of an equity unit is the approximate value per share of our stockholder equity
as of the valuation date, less the value of Northern States Power equity
investments. The accrued value of each participant's award is equal to the
current value of the equity unit minus the grant price. Equity units are paid
out in cash over a five-year period (twenty percent per year) following a
three-year vesting period. In the event of termination of employment by a
participant due to death or disability, outstanding equity units become fully
vested and are fully paid in the following year. In the event of termination of
employment due to retirement, outstanding equity units become fully vested and
are paid out pro rata over the five plan years following termination.
Termination of a participant for any other reason results in forfeiture of all
unvested equity units, unless otherwise approved.

Following the offering we do not plan to make any additional grants under
this plan. Currently there are approximately 1,525,000 equity units outstanding.
Of that amount, approximately 639,000 equity units are held by our officers.
Approximately 886,000 equity units are held by other employees. No non-employee
directors have participated in this plan.

With the establishment of the NRG 2000 Long-Term Incentive Compensation
Plan, the NRG Equity Plan will be discontinued. All outstanding, non-vested
equity units for active employee participants will be terminated, and a
comparable stock option grant issued in replacement of the unvested equity unit
grant. Options for approximately 4,400,000 shares of common stock will be issued
under the new plan for this purpose. Messrs. Peterson, Bluhm, Mataczynski, Will
and Bender and all executive officers as a group will be granted such options in
replacement of equity units for approximately 755,000; 215,000; 150,000;
215,000; 140,000 and 1,750,000 shares, respectively, under this Plan at the
consummation of this offering.

Following the offering, equity units held by retired, terminated and
transferred participants will be valued on the basis of the fair market value of
our common stock and payouts will occur upon vesting as provided in the existing
Equity Plan. Final payouts under this plan to non-employee participants should
occur no later than 2006.

NRG 2000 LONG-TERM INCENTIVE COMPENSATION PLAN

Prior to the completion of the offering, we expect to adopt a new incentive
compensation plan that will replace the NRG Equity Plan. The board of directors
or a committee appointed by the board of directors will administer the incentive
plan. The incentive plan will provide for awards in the form of stock options,
stock appreciation rights, restricted stock, performance units, performance
shares or cash based awards as determined by the board of directors. All
officers, certain other employees and non-employee directors will be eligible to
participate in the incentive plan. The total number of shares of common stock to
be authorized for issuance under the incentive plan is 9,000,000 shares.

Initially, as of the completion of this offering, only stock option grants
will be made to certain officers and employees under the incentive plan. The
initial options will have an exercise price equal to the initial public offering
price. The vesting period for the initial awards will be 5 years with 25%
vesting in each of the years two through five. Subsequent awards, expected to be
issued annually, will have an option price at least equal to the market price of
our common stock on the date of grant. Options will vest over a four-year period
from the date of grant, 25 percent each year. Each option granted will expire at
such time as the board of directors determines at the time of grant; provided,
however, that no option that is intended to qualify as an "Incentive Stock
Option" within the meaning of Section 422 of the Internal Revenue Code shall be
exercisable later than the tenth (10th) anniversary date of its grant. The total
number of shares of common stock covered by the initial grant is expected to be
approximately 1,300,000 shares. Messrs. Peterson, Bluhm, Mataczynski, Will and
Bender and all executive officers as a group will be granted initial options for
120,000; 60,000; 60,000; 60,000; 60,000; and 600,000 shares, respectively.

In addition, non-vested equity units outstanding under the NRG Equity Plan
will be converted into stock options with an exercise price corresponding to the
original equity plan grant price. Vesting and all

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<PAGE> 78

other material terms of the equity plan shall continue as the terms of these
options. Once vested, the awards shall remain exercisable for up to 10 years
from date of the grant under the equity plan, except that the January 1993 and
January 1994 grants shall terminate 90 days following the end of the original 10
year vesting period.

To the extent issuance of equity compensation under the incentive plan
would cause Northern States Power to cease to own at least 80% of the value of
our outstanding capital stock, Northern States Power may purchase shares of
common stock in the open market to ensure that such minimum value is maintained.

EMPLOYMENT CONTRACTS

David H. Peterson. We have entered into an employment agreement with Mr.
Peterson providing that Mr. Peterson will be employed as our highest level
executive officer. The term of the agreement expires June 27, 2004. During the
term of the agreement, Mr. Peterson's base salary will be reviewed at least
annually by the Compensation Committee of the board of directors for possible
increase. The agreement provides that Mr. Peterson will receive retirement and
welfare benefits no less favorable than those provided to any of our other
officers. In addition, the employment agreement provides for participation in a
supplemental executive retirement plan such that the aggregate value of the
retirement benefits that Mr. Peterson and his spouse will receive at the end of
the term of the agreement under all of our defined benefit pension plans and
those of our affiliates will not be less than the aggregate value of the
benefits he would have received had he continued, through the end of the term of
the agreement, to participate in the Northern States Power's Deferred
Compensation Plan, the Northern States Power Excess Benefit Plan and the
Northern States Power Pension Plan, including amounts to compensate Mr. Peterson
for the monthly defined benefit payments he would have received during the term
of the employment agreement and prior to the date of his termination of
employment if monthly benefit payments had commenced following the month in
which he first became eligible for early retirement under the Northern States
Power Pension Plan.

The employment agreement also provides for certain additional benefits to
be paid upon Mr. Peterson's death. If Mr. Peterson's employment is terminated by
us without cause or by Mr. Peterson with good reason, in each case as defined in
the employment agreement, Mr. Peterson will continue to receive his salary,
bonus at the greater of target bonus and actual bonus for the last plan year
prior to termination, incentive compensation with cash replacing equity based
awards and benefits under the agreement as if he had remained employed until the
end of the term of the employment agreement and then retired, at which time he
will be treated as eligible for retiree welfare benefits and other benefits
provided to the retired senior executives. However, if the termination of
employment is a result of a change of control, as defined in the NRG Equity
Plan, the compensation and benefits will be continued for the longer of 30
months or through the end of the employment period. In accordance with the terms
of the employment agreement, Mr. Peterson has agreed not to compete with our
business during the period of his employment and for one year after his
termination or resignation. Mr. Peterson has also agreed not to solicit any of
our customers for any business purpose that competes with our business during
the period of his employment or two years after his termination or resignation.
Finally, during the period of his employment and for two years after his
termination or resignation, Mr. Peterson has agreed not to disclose any of our
confidential information to any person not authorized by us to receive it.

Leonard A. Bluhm, Craig A. Mataczynski, Ronald J. Will and James J.
Bender. On April 15, 1998, we entered into employment agreements with each of
Messrs. Bluhm, Mataczynski, Will and Bender. The term of each of these
agreements is for a rolling three year period unless either party to the
agreement notifies the other in advance of any annual anniversary date of the
agreement that the agreement will expire two years from the annual anniversary
date. These agreements expire on April 15, 2001. If the employment of any of
Messrs. Bluhm, Mataczynski, Will and Bender is terminated due to his death,
disability or for cause, or if any of them voluntarily resigns without good
cause, he will receive his base salary excluding incentives and employee
benefits through the date of termination or resignation. However, if any of the
executives is terminated for any reason other than death, disability or cause,
or if any of them

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<PAGE> 79

voluntarily resigns for good cause, we will be obligated to continue to pay his
then current total compensation, including base salary, anticipated incentives
and all employee benefits for a period of three years following the date of
termination or resignation. Under the terms of the employment agreements, each
of the executives has agreed not to compete with our business during the course
of his employment and for one year after his resignation or termination. In
addition, each of the executives has agreed not to disclose any of our
confidential information or trade secrets or use the information for his or a
third party's benefit. The employment agreement with Mr. Will also provides that
upon Mr. Will's termination of employment for any reason or his voluntary
resignation with or without good cause, in addition to all other items of
compensation, we will pay the sum of $100,000 as a retainer in exchange for Mr.
Will's agreement to make himself available at our request to provide consulting
services for one year following his termination or resignation.

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<PAGE> 80

OWNERSHIP OF CAPITAL STOCK

Prior to the completion of this offering, Northern States Power Company,
414 Nicollet Mall, Minneapolis, Minnesota 55401, owned all of our outstanding
capital stock.

Upon completion of this offering, Northern States Power will own
147,604,500 shares of class A common stock. Upon completion of this offering,
class A common stock will constitute approximately 84% of our total outstanding
common equity and approximately 98% of our total voting power. Upon completion
of this offering, common stock will constitute approximately 16% of our total
outstanding stock and approximately 2% of our total voting power.

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<PAGE> 81

RELATIONSHIPS AND RELATED TRANSACTIONS

The transactions described or referred to below were entered into between
related parties prior to the offering of our common stock and were not the
result of arms-length negotiations.

Northern States Power has the power, and will continue to have the power
following this offering, to control the election of the directors and all other
matters submitted for stockholder approval and may be deemed to have control
over our management and affairs. Northern States Power has policies in place,
pursuant to applicable law, to ensure that its ratepayers are protected from
affiliate transactions that may be adverse to the ratepayers' interests. Unless
otherwise noted below, the agreements described below will continue in effect
after this offering.

OPERATING AGREEMENTS

We have two agreements with Northern States Power for the purchase of
thermal energy. Under the terms of the agreements, Northern States Power charges
us for certain incremental costs, including fuel, labor, plant maintenance and
auxiliary power, incurred by Northern States Power to produce the thermal
energy. We paid Northern States Power $4.6 million in 1997, $5.1 million in 1998
and $4.4 million in 1999 under these agreements; we have paid $1.4 million under
them in the first three months of 2000. One of the agreements expires on
December 31, 2002 and the other one expires on December 31, 2006.

We have a renewable 10-year agreement with Northern States Power, expiring
on December 31, 2001, whereby Northern States Power agrees to purchase
refuse-derived fuel for use in certain of its boilers and we agree to pay
Northern States Power an incentive fee to use refuse-derived fuel. Under this
agreement, we received from Northern States Power $1.3 million in 1997, $1.4
million in 1998 and $1.4 million in 1999; we paid to Northern States Power $2.8
million in 1997, $3.1 million in 1998 and $2.7 million in 1999 under this
agreement. Through March 31, 2000, we received $0.6 million and paid $0.5
million.

We have entered into an operation and maintenance agreement with Northern
States Power with respect to the Elk River and Becker facilities, under which we
receive a base management fee and are reimbursed for costs we have incurred. The
operation and maintenance agreement also provides for a management incentive fee
payable to us, based upon the financial performance of the facilities. We earned
a total management fee of $1.1 million, in addition to reimbursed expenses, in
1997, $1.7 million in 1998 and $1.9 million in 1999. Management fees for the
three months ended March 31, 2000, totaled $0.6 million. This agreement expires
on December 31, 2003.

ADMINISTRATIVE SERVICES AGREEMENT

We have entered into an agreement with Northern States Power to provide for
the reimbursement of actual administrative services provided to each other on an
at-cost basis plus a 1% fee to cover handling costs, working capital
requirements and other miscellaneous costs. Services provided by Northern States
Power to us are principally for cash management, accounting, employee relations,
governmental affairs and engineering. In addition, our employees participate in
certain employee benefit plans of Northern States Power. We paid Northern States
Power $0.7 million in 1997, $5.2 million in 1998 and $6.4 million in 1999, as
reimbursement for the cost of services provided. Through March 31, 2000, we have
paid $2.0 million.

TAX SHARING AGREEMENT

We are included in the consolidated federal income tax and state franchise
tax returns of Northern States Power. We calculate our tax position on a
separate company basis under a tax sharing agreement with Northern States Power
and receive payment from Northern States Power for tax benefits they receive by
our inclusion on their tax returns and pay Northern States Power for tax
liabilities created by such inclusion.

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<PAGE> 82

LONG-TERM DEBT

The construction cost of the Newport facilities was financed through tax
exempt variable rate resource recovery revenue bonds issued by the two Minnesota
counties served by the facilities, which have subsequently been converted to
fixed rate resource recovery revenue bonds with an effective interest rate of
6.57% per annum and annual maturities each December through 2006. The proceeds
of such bond issuance were loaned by the counties to Northern States Power,
which agreed under a loan agreement to pay to the counties amounts sufficient to
pay debt service on the bonds. We issued a separate note to Northern States
Power in an original principal amount of approximately $10 million as part of
the consideration for the purchase of the facility from Northern States Power.

OPTION AGREEMENT

Before this offering is completed, we will enter into an option agreement
with Northern States Power under which we will grant to Northern States Power
and its affiliates a continuing option to purchase additional shares of common
stock. If we issue any additional equity securities after this offering,
Northern States Power and its affiliates may exercise this option to purchase
shares of common stock to the extent necessary for them to maintain their
then-existing percentage of the total voting power.

The purchase price of the shares of common stock will be the market price
of the common stock. The stock option expires if Northern States Power and its
affiliates beneficially own less than 30% of the outstanding common stock and
class A common stock on a combined basis.

REGISTRATION RIGHTS AGREEMENT

Prior to consummation of this offering, we will enter into a registration
rights agreement with Northern States Power, under which we will agree to
register the shares of common stock issuable upon conversion of shares of class
A common stock held by Northern States Power under the following circumstances:

- Demand Rights. Upon the written request of Northern States Power, we
will register shares of common stock held by Northern States Power
specified in its request for resale under an appropriate registration
statement filed and declared effective by the Securities and Exchange
Commission. Northern States Power may make a demand so long as:

- it requests registration of shares with an anticipated aggregate
offering price of at least $20 million;

- it has made no more than four such previous requests;

- we have not completed a registered offering of common stock within the
last 180 days; and

- our chief executive officer has not determined it advisable to delay
the offering for a period of up to 180 days, which determination may
only be made once every twelve months.

- Piggyback Rights. If at any time we register newly issued shares of
common stock, or register outstanding shares of common stock for resale
on behalf of any holder of our common stock, Northern States Power may
elect to include in such registration any shares of common stock it
holds. If the offering is an underwritten offering, the managing
underwriter may exclude all or a part of Northern States Power's shares
if market factors dictate, but only if Northern States Power is not
exercising a demand right, described above, and only if all other shares
being sold by other stockholders are excluded first.

- Lockup. In consideration for these registration rights, Northern States
Power has agreed not to sell shares of common stock for a period of 180
days following the date of this prospectus.

- Termination. The registration rights agreement will terminate upon the
earlier of seven years from the date of the agreement or the date on
which all remaining shares of common stock held by Northern States
Power, or issuable to Northern States Power upon conversion of class A
common stock, may be sold in any 90-day period in compliance with Rule
144 under the Securities Act.

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<PAGE> 83

DESCRIPTION OF CAPITAL STOCK

AUTHORIZED STOCK

The authorized capital stock of NRG consists of 550,000,000 shares of
common stock, $0.01 par value, 250,000,000 shares of class A common stock, $0.01
par value and 200,000,000 shares of preferred stock, $0.01 par value. All of the
issued and outstanding capital stock is fully paid and nonassessable. The
following summary of the shares of common stock, class A common stock and
preferred stock is qualified by reference to our certificate of incorporation, a
copy of which we will provide to you upon your request, and a copy of which is
filed as an exhibit to the registration statement to which this prospectus
relates.

COMPARISON OF OUR COMMON STOCK AND CLASS A COMMON STOCK

The following table compares our common stock and class A common stock.

<TABLE>
<CAPTION>
COMMON STOCK CLASS A COMMON STOCK
------------ --------------------
<S> <C> <C>
Public Market................... We have applied to have the None.
common stock listed on the NYSE,
subject to official notice of
issuance.
Voting Rights................... One vote per share on all Ten votes per share on all
matters voted upon by our matters voted upon by our
stockholders. stockholders.
Transfer Restrictions........... None. None, but will convert to common
stock on a share-for-share basis
upon certain transfers as
described below.
Conversion...................... Not convertible. Convertible at any time, in
whole or in part, into shares of
common stock on a
share-for-share basis.
Automatically converts into
common stock on a
share-for-share basis upon any
transfer to a non-affiliate of
Northern States Power (including
by way of merger, consolidation
or reorganization other than in
connection with the formation of
Xcel Energy) or if Northern
States Power or its affiliates
own less than 30% of the
outstanding shares of class A
common stock and common stock on
a combined basis.
Reissuance...................... Additional shares may be issued No additional shares may be
and redeemed shares may be issued, and shares redeemed or
reissued. repurchased will be canceled and
may not be reissued.
</TABLE>

PREFERRED STOCK

Our board of directors has the authority to issue shares of preferred stock
from time to time on terms that it may determine, to divide preferred stock into
one or more classes or series, and to fix the designations, voting powers,
preferences and relative participating, optional or other special rights of each
class or series, and the qualifications, limitations or restrictions of each
class or series, to the fullest extent permitted by Delaware law. The issuance
of preferred stock could have the effect of decreasing the market price of our
common stock, impeding or delaying a possible takeover and adversely affecting
the voting and other rights of the holders of common stock. Currently, there are
no shares of preferred stock outstanding and there are no shares of preferred
stock designated.

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<PAGE> 84

OTHER PROVISIONS RELATING TO COMMON STOCK AND CLASS A COMMON STOCK

If we in any manner split, subdivide or combine the outstanding shares of
common stock or class A common stock, the outstanding shares of the other class
of common stock will be proportionally subdivided or combined in the same manner
and on the same basis.

In all other respects, whether as to dividends, upon liquidation,
dissolution or winding up, or otherwise, the holders of record of common stock
and the holders of record of class A common stock have identical rights and
privileges on the basis of the number of shares held.

ADVANCE NOTICE REQUIREMENTS FOR STOCKHOLDER PROPOSALS

Our bylaws provide that stockholders seeking to bring business before an
annual meeting of stockholders must provide timely notice of their proposal in
writing to the corporate secretary. To be timely, a stockholder's notice must be
delivered or mailed and received at our principal executive offices not less
than 120 days in advance of the anniversary date of our proxy statement in
connection with our previous year's annual meeting. Our bylaws also specify
requirements as to the form and content of a stockholder's notice. These
provisions may impede stockholders' ability to bring matters before an annual
meeting of stockholders or make nominations for directors at an annual meeting
of stockholders. So long as Northern States Power or its successors by way of
merger or consolidation own at least 50% of the outstanding shares of common
stock and class A common stock on a combined basis, it will be exempt from these
provisions.

SPECIAL MEETINGS

Holders of our common stock may not call a special meeting of stockholders;
only our board of directors may call such a meeting.

BUSINESS COMBINATIONS WITH INTERESTED STOCKHOLDERS

We will not be subject to the business combination provisions of Section
203 of the Delaware General Corporation Law, but our certificate of
incorporation will contain provisions substantially similar to Section 203. In
general, these provisions will prohibit us from engaging in various business
combination transactions with any interested stockholder for a period of three
years after the date of the transaction in which the person became an interested
stockholder unless:

- the business combination transaction, or the transaction in which the
interested stockholder became an interested stockholder, is approved by
our board of directors prior to the date the interested stockholder
obtained this status,

- upon consummation of the transaction which resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at
least 85% or our common stock outstanding at the time the transaction
commenced, excluding for purposes of determining the number of shares
outstanding those shares owned by:

- persons who are directors and also officers; and

- employee stock plans in which employee participants do not have the
right to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer; or

- on or subsequent to this date the business combination is approved by our
board of directors and authorized at an annual or special meeting of
stockholders by the affirmative vote of at least 66 2/3% of our
outstanding common stock which is not owned by the interested
stockholder.

Under our certificate of incorporation, a business combination is defined
to include mergers, asset sales and other transactions resulting in financial
benefit to a stockholder. In general, an interested stockholder is a person who,
together with affiliates and associates, owns or, within three years, did own,

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15% or more of our common stock. Northern States Power and its affiliates,
including Xcel Energy upon the completion of Northern States Power's pending
merger, will be exempt from these provisions.

AMENDMENT

Our certificate of incorporation also provides that, after the first date
that Northern States Power or Xcel Energy, together with their respective
affiliates, ceases to beneficially own at least 25% of the outstanding shares of
common stock and class A common stock on a combined basis, the affirmative vote
of the holders of at least 80% of the outstanding shares of common stock and
class A common stock on a combined basis is required to amend the provisions of
our certificate of incorporation described above under "-- Advance Notice
Requirements for Stockholder Proposals," "-- Special Meetings," and "-- Business
Combinations with Interested Stockholders." Under our certificate of
incorporation and by-laws, our by-laws may only be amended:

- at any time by the affirmative vote of directors constituting not less
than a majority of the entire board of directors;

- prior to the first date that Northern States Power or Xcel Energy,
together with their respective affiliates, cease to beneficially own at
least 50% of the outstanding shares of the outstanding shares of common
stock and class A common stock on a combined basis, by the affirmative
vote of the holders of a majority of the outstanding shares of common
stock and class A common stock on a combined basis; or

- after that date, by the affirmative vote of the holders of a least 80% of
the outstanding shares of common stock and class A common stock on a
combined basis.

REGISTRATION RIGHTS

We have agreed to register shares of our common stock on behalf of Northern
States Power as described in "Relationships and Related Transactions --
Registration Rights Agreement."

LIMITATIONS ON LIABILITY AND INDEMNIFICATION OF OFFICERS AND DIRECTORS

The Delaware General Corporation Law authorizes corporations to limit or
eliminate the personal liability of directors to corporations and their
stockholders for monetary damages for breaches of directors' fiduciary duties.
Our certificate of incorporation includes a provision that eliminates the
personal liability of directors for monetary damages for actions taken as a
director, except for liability:

- for breach of duty of loyalty;

- for acts or omissions not in good faith or involving intentional
misconduct or knowing violation of law;

- under Section 174 of the Delaware General Corporation Law (unlawful
dividends); and

- for transactions from which the director derived improper personal
benefit.

Our bylaws provide that we must indemnify our directors and officers to the
fullest extent authorized by the Delaware General Corporation Law, subject to
very limited exceptions. We are also expressly authorized to carry directors'
and officers' insurance providing indemnification for our directors, officers
and certain employees for some liabilities. We believe that these
indemnification provisions and insurance are necessary to attract and retain
qualified directors and executive officers.

The limitation of liability and indemnification provisions in our
certificate of incorporation, bylaws and indemnification agreements may
discourage stockholders from bringing a lawsuit against directors for breach of
their fiduciary duty. These provisions may also have the effect of reducing the
likelihood of derivative litigation against directors and officers, even though
such an action, if successful, might otherwise benefit us and our stockholders.
In addition, your investment may be adversely affected to the

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extent we pay the costs of settlement and damage awards against directors and
officers pursuant to these indemnification provisions.

There is currently no pending litigation or proceeding involving any of our
directors, officers or employees for which indemnification is sought. We are
unaware of any pending or threatened litigation that may result in claims for
indemnification.

TRANSFER AGENT

Norwest Bank, N.A. will act as the transfer agent for the common stock.

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DESCRIPTION OF INDEBTEDNESS

$125 MILLION 7.625% SENIOR NOTES DUE 2006; $250 MILLION 7.5% SENIOR NOTES DUE
2007; AND $300 MILLION 7.5% SENIOR NOTES DUE 2009

In January 1996, we sold $125 million of 7.625% Senior Notes due 2006 in a
transaction exempt from registration under the Securities Act. All of the 7.625%
Senior Notes due 2006 are still outstanding.

In June 1997, we sold $250 million of 7.5% Senior Notes due 2007 in a
transaction exempt from registration under the Securities Act. On January 20,
1998, we issued in an offering registered under the Securities Act an aggregate
principal amount of $250 million of 7.5% Senior Notes due 2007 in exchange for
all the unregistered 7.5% Senior Notes due 2007 issued on June 17, 1997. All of
the 7.5% Senior Notes due 2007 are still outstanding.

In May 1999, we sold $300 million of 7.5% Senior Notes due 2009 in an
offering registered under the Securities Act. All of the 7.5% Senior Notes due
2009 are still outstanding.

Each of the 7.625% Senior Notes due 2006, the 7.5% Senior Notes due 2007
and the 7.5% Senior Notes due 2009 are governed by the terms of an indenture.
The material terms of the indentures are described below. As a summary, the
following discussion necessarily omits many of the details of the indentures. A
copy of each of the indentures has been filed as an exhibit to the registration
statement of which this prospectus is a part.

Interest on the 7.625% Senior Notes due 2006 is payable semiannually in
arrears on each February 1 and August 1. Interest on the 7.5% Senior Notes due
2007 is payable semiannually in arrears on each June 15 and December 15.
Interest on the 7.5% Senior Notes due 2009 is payable semiannually in arrears on
each June 1 and December 1.

OPTIONAL REDEMPTION

The 7.625% Senior Notes due 2006 are redeemable, in whole or in part, at
any time after February 1, 2001, and the 7.5% Senior Notes due 2007 and the 7.5%
Senior Notes due 2009 are redeemable, in whole or in part, at any time. In each
case, the redemption price to be repaid is the greater of:

- 100% of principal amount of the senior notes, plus accrued interest on
the principal amount, if any, to the redemption date; or

- a discounted sum of the present values of all of the remaining scheduled
payments of principal and interest from the redemption date to maturity
on the senior notes.

CHANGE OF CONTROL

If a change of control occurs (as defined in the relevant indenture), we
must make an offer to purchase all outstanding 7.625% Senior Notes due 2006,
7.5% Senior Notes due 2007 and 7.5% Senior Notes due 2009 at a purchase price
equal to 101% of their principal amount plus accrued and unpaid interest. This
requirement could deter a change of control transaction in which stockholders
could receive a premium. However, no change of control will be deemed to have
occurred if the rating remains investment grade.

COVENANTS RESTRICTING OUR ACTIONS

Each of the indentures contains covenants which generally prohibit or
restrict our ability to pledge, mortgage, hypothecate or permit to exist any
lien upon our property to secure any indebtedness for borrowed money unless the
senior notes are equally and ratably secured. In addition, the indenture for the
7.625% Senior Notes due 2006 requires us to maintain a tangible net worth of
greater than the sum of $175 million plus 25% of our consolidated net income for
the period from and including April 1, 1996 to the determination date of such
income.

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EVENTS OF DEFAULT

The following are "events of default" under each of the indentures:

- our failure to pay any interest on the senior notes when due, which
failure continues for 30 days;

- our failure to pay principal or premium (including in connection with a
change of control) on the senior notes when due;

- our failure to perform any other covenant relating to the senior notes
for a period of 30 days after the trustee gives us written notice or we
receive written notice by the holders of at least 25% in aggregate
principal amount of the senior notes;

- an event of default occurring under any of our instruments under which
there may be issued, or by which there may be secured or evidenced, any
indebtedness for money borrowed that has resulted in the acceleration of
the indebtedness, or any default occurring in payment of any
indebtedness at final maturity and after the expiration of any
applicable grace periods, other than:

- indebtedness that is payable solely out of the property or assets of a
partnership, joint venture or similar entity of which we or any of our
subsidiaries or affiliates is a participant, or that is secured by a
lien on the property or assets owned or held by that entity without
further recourse to us; or

- indebtedness not exceeding $20 million;

- one or more final judgments, decrees or orders for the payment of money
aggregating $20 million or more, either individually or in the
aggregate, shall be entered against us and shall remain undischarged,
unvacated and unstayed for more than 90 days, except while being
contested in good faith by appropriate proceedings; and

- a bankruptcy, insolvency, reorganization or receivership or similar
proceeding with respect to us.

$240 MILLION 8% REMARKETABLE OR REDEEMABLE SECURITIES ("ROARS") DUE 2013
(REMARKETING DATE NOVEMBER 1, 2003)

In November 1999, we sold $240 million of 8% ROARS due 2013 in an offering
registered under the Securities Act. All of the 8% ROARS due 2013 are still
outstanding and interest on them is payable semiannually in arrears on each
November 1 and May 1.

The ROARS are governed by the terms of an indenture. The material terms of
the indenture are described below. As a summary, the following discussion
necessarily omits many of the details of the indenture. A copy of the indenture
has been filed as an exhibit to the registration statement of which this
prospectus is a part.

CHANGE OF CONTROL

If a change of control (as defined in the indenture) occurs, we must make
an offer to purchase all outstanding ROARS then outstanding at a purchase price
equal to 101% of their principal amount plus accrued and unpaid interest. This
requirement could deter a change of control transaction in which stockholders
could receive a premium. However, no change of control will be deemed to have
occurred if the rating remains investment grade.

COVENANTS RESTRICTING OUR ACTIONS

The indenture for the ROARS contains covenants which generally prohibit or
restrict our ability to pledge, mortgage, hypothecate or permit to exist any
lien upon our property to secure any indebtedness for borrowed money unless the
senior notes are equally and ratably secured.

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EVENTS OF DEFAULT

The "events of default" under the indenture governing the ROARS are
substantially equivalent to those previously described with respect to the
senior notes.

MANDATORY TENDER

We have entered into a Remarketing Agreement with Credit Suisse Financial
Products pursuant to which Credit Suisse has the option to purchase all of the
ROARS on November 1, 2003 at a purchase price equal to 100% of the aggregate
principal amount outstanding. The ROARS will be remarketed at a fixed rate of
interest unless we have redeemed the ROARS or have exercised our option to have
the ROARS remarketed at a floating rate of interest for up to twelve months
following November 1, 2003. If we have elected to have the ROARS remarketed at a
floating rate of interest for up to twelve months, Credit Suisse will have the
option to purchase all of the ROARS at the end of the applicable floating rate
period at a discounted sum of the present values of all of the remaining
scheduled payments of principal and interest from the redemption date to
maturity on the ROARS.

OPTIONAL REDEMPTION

If Credit Suisse exercises its purchase option on November 1, 2003 or at
the end of the applicable floating rate period, if any, we have the option of
redeeming all of the ROARS at a discounted sum of the present values of all of
the remaining scheduled payments of principal and interest from the redemption
date to maturity on the ROARS.

MANDATORY REDEMPTION

We will be required to redeem the ROARS in whole on November 1, 2003 or at
the end of any floating rate period in the event that Credit Suisse elects not
to exercise its option to purchase the ROARS. If we are required to redeem the
ROARS, we will redeem them at a purchase price equal to:

- if redeemed on November 1, 2003, 100% of the aggregate principal amount
outstanding; or

- if redeemed at the end of any floating rate period, a discounted sum of
the present values of all of the remaining scheduled payments of
principal and interest from the redemption date to maturity on the
ROARS.

L160 MILLION 7.97% RESET SENIOR NOTES DUE 2020

In March 2000, we sold L160 million (approximately $250 million at the time
of issuance) of 7.97% Reset Senior Notes due 2020 in a transaction exempt from
registration under the Securities Act. All of the 7.97% Reset Senior Notes were
sold to the NRG Energy Pass-Through Trust 2000-1, a trust formed pursuant to a
trust agreement between us and The Bank of New York, as trustee. The trust
issued $250 million aggregate principal amount of certificates that represented
an undivided beneficial interest in the assets of the trust, which assets
consist principally of the 7.97% Reset Senior Notes. Interest on the 7.97% Reset
Senior Notes is payable semiannually in arrears on each September 15 and March
15.

The 7.97% Reset Senior Notes are governed by the terms of an indenture. The
material terms of the indenture are described below. As a summary, the following
discussion necessarily omits many of the details of the indenture. A copy of the
indenture has been filed as an exhibit to the registration statement of which
this prospectus is a part.

CHANGE OF CONTROL

If a change of control (as defined in the indenture) occurs on or before
March 15, 2005 we must make an offer to purchase all 7.97% Reset Senior Notes
then outstanding at a purchase price in pounds sterling equal to 100% of their
principal amount plus accrued and unpaid interest plus a payment in US dollars
equal to 1% of the principal amount of trust certificates to be redeemed by the
trust pursuant to a

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similar change of control offer under the trust agreement. If a change of
control occurs prior to March 15, 2005, but after an event of default that
results in the principal amount of the 7.97% Reset Senior Notes being due and
payable immediately, we may be required to purchase all or a part of the notes
at a price in US dollars equal to 101% of the principal amount plus accrued and
unpaid interest. If a change of control occurs after March 15, 2005, we must
make an offer to purchase all 7.97% Reset Senior Notes then outstanding at a
purchase price in pounds sterling equal to 101% of their principal amount plus
accrued and unpaid interest. This requirement could deter a change of control
transaction in which stockholders could receive a premium. However, no change of
control will be deemed to have occurred if the rating remains investment grade.

COVENANTS RESTRICTING OUR ACTIONS

The indenture for our 7.97% Reset Senior Notes contains covenants which
generally prohibit or restrict our ability to pledge, mortgage, hypothecate or
permit to exist any lien upon our property to secure any indebtedness for
borrowed money unless the reset senior notes are equally and ratably secured.

EVENTS OF DEFAULT

The "events of default" under the indenture governing the 7.97% Reset
Senior Notes are substantially equivalent to those previously described with
respect to the reset senior notes.

MANDATORY TENDER

We have entered into a Remarketing Agreement and a Call Agreement with
affiliates of Bank of America, N.A. pursuant to which Bank of America has the
option to purchase all of the 7.97% Reset Senior Notes on March 15, 2005 at a
purchase price equal to 100% of the aggregate principal amount outstanding. The
7.97% Reset Senior Notes will be remarketed at a fixed rate of interest unless
we have redeemed the 7.97% Reset Senior Notes or have exercised our option to
have the 7.97% Reset Senior Notes remarketed at a floating rate of interest for
up to twelve months following March 15, 2005. If we have elected to have the
7.97% Reset Senior Notes remarketed at a floating rate of interest for up to
twelve months, Bank of America will have the option to purchase all of the 7.97%
Reset Senior Notes at the end of the applicable floating rate period at a
discounted sum of the present values of all of the remaining scheduled payments
of principal and interest from the redemption date to maturity on the 7.97%
Reset Senior Notes.

OPTIONAL REDEMPTION

If Bank of America exercises its purchase option on March 15, 2005 or at
the end of the applicable floating rate period, if any, we have the option of
redeeming all of the 7.97% Reset Senior Notes at a discounted sum of the present
values of all of the remaining scheduled payments of principal and interest from
the redemption date to maturity on the 7.97% Reset Senior Notes.

MANDATORY REDEMPTION

We will be required to redeem the 7.97% Reset Senior Notes in whole on
March 15, 2005 or at the end any floating rate period in the event that Bank of
America elects not to exercise its option to purchase the 7.97% Reset Senior
Notes. If we are required to redeem the 7.97% Reset Senior Notes, we will redeem
them at a purchase price equal to:

- if redeemed on March 15, 2005, 100% of the aggregate principal amount
outstanding; or

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ABN AMRO REVOLVING CREDIT FACILITY

In March 2000, we entered into a $500 million revolving credit facility
with ABN AMRO Bank, N.V., as agent, and various lenders. The facility is
unsecured and provides for borrowings of "Base Rate Loans" and "Eurocurrency
Loans." The Base Rate Loans bear interest at the greater of ABN AMRO's prime
rate or the sum of the prevailing per annum rates for overnight funds plus 0.5%
per annum plus an additional 0.125% if we draw upon greater than one-third of
the facility amount and an additional 0.25% if we draw upon greater than
two-thirds of the facility amount. The Eurocurrency loans bear interest at an
adjusted rate based on LIBOR plus an adjustment percentage of from between 0.4%
to 1.8% per annum, depending on NRG's senior debt credit rating and the amount
outstanding under the facility. The facility terminates on March 9, 2001. The
facility contains covenants that restrict the incurrence of liens and require us
to maintain a net worth of at least $700 million plus 25% of our net income from
January 1, 2000 through the determination date. In addition, we must maintain a
debt to capitalization ratio of not more than 0.68 to 1.0 or not more than 0.72
to 1.0 for any consecutive two months in a six month period. An event of default
under the Standby Letter of Credit Facility (described below) is also an event
of default under this facility.

STANDBY LETTER OF CREDIT FACILITY

In November 1999, we entered into a $125 million standby letter of credit
facility with Australia and New Zealand Banking Group Limited, as administrative
agent. The facility is unsecured and provides for the issuances of letters of
credit for our account with respect to financial and performance guarantees that
we undertake. The facility terminates on November 30, 2002 unless extended in
accordance with the terms of the facility. The facility contains covenants that
restrict the incurrence of liens and require us to maintain a net worth to
capitalization ratio of 0.32 to 1.0 for each fiscal quarter. In addition, the
facility requires us to maintain a minimum net worth of at least $500 million
plus 25% of our net income for each fiscal quarter beginning with the fiscal
quarter ending September 30, 1999 for which net income is positive through the
fiscal quarter ending on or ending last prior to the determination date.

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SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has been no public market for the common
stock. We cannot provide any assurance that a significant public market for the
common stock will develop or be sustained after this offering. Future sales of
substantial amounts of common stock in the public market, or the possibility of
such sales occurring, could adversely affect prevailing market prices for the
common stock or our future ability to raise capital through an offering of
equity securities.

After this offering, we will have outstanding 28,170,000 shares of common
stock or 32,395,500 shares if the underwriters' over-allotment option is
exercised in full. All of these shares will be freely tradable in the public
market without restrictions under the Securities Act, except for any such shares
acquired by an "affiliate" of NRG as that term is defined in Rule 144 under the
Securities Act, which shares will remain subject to resale limitations of Rule
144.

Northern States Power will own 147,604,500 shares of class A common stock,
which will represent approximately 84% of the total number of both common stock
and class A common stock outstanding and which are immediately convertible into
an equal number of shares of common stock upon the election of Northern States
Power or upon a sale of shares of class A common stock to a third party. We have
agreed, if so requested by Northern States Power, to file registration
statements and take other steps to enable Northern States Power to sell shares
of common stock held by it, including but not limited to shares of common stock
acquired by conversion of shares of class A common stock. In addition, beginning
90 days after the date of this prospectus, Northern States Power will be
entitled to make sales under Rule 144 of limited quantities of common stock.
However, we and Northern States Power have agreed with the underwriters, subject
to certain exceptions, not to sell any shares of common stock for a period of
180 days following the date of this prospectus.

Generally, Rule 144 provides that an affiliate may sell on the open market
in brokers' transactions within any three month period a number of shares that
does not exceed the greater of:

- 1% of the then outstanding shares of common stock; and

- the average weekly trading volume in the common stock on the open market
during the four calendar weeks preceding the sale.

Sales under Rule 144 will also be subject to post-sale notice requirements
and the availability of current public information about NRG.

Shares properly sold in reliance upon Rule 144 to persons who are not
affiliates are freely tradable without restriction after the sale.

On January 1, 2001, the right to acquire approximately 940,000 shares of
common stock underlying stock option grants will vest.

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MATERIAL UNITED STATES TAX CONSEQUENCES
TO NON-UNITED STATES HOLDERS

The following discussion is a summary of the material United States federal
income and estate tax consequences of the ownership and disposition of our
common stock to beneficial owners that are Non-United States persons. This
discussion does not deal with all aspects of United States income and estate
taxation and does not deal with foreign, state and local tax consequences that
may be relevant to Non-United States persons in light of their personal
circumstances. Furthermore, this discussion is based on the Internal Revenue
Code of 1986, as amended, Treasury Department regulations, published positions
of the Internal Revenue Service and court decisions now in effect, all of which
are subject to change. YOU SHOULD CONSULT YOUR OWN TAX ADVISOR WITH REGARD TO
THE APPLICATION OF THE FEDERAL INCOME TAX LAWS, AS WELL AS TO THE APPLICABILITY
AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS TO WHICH YOU MAY BE SUBJECT.

Under the Code, a "Non-United States person" means a person that is not any
of the following:

- a citizen or resident of the United States;

- a corporation or partnership created or organized in or under the laws of
the United States or any political subdivision of the United States;

- an estate the income of which is subject to United States federal income
taxation regardless of its source; or

- a trust that:

- is subject to the supervision of a court within the United States and
the control of one or more United States persons; or

- has a valid election in effect under applicable United States Treasury
regulations to be treated as a United States person.

DIVIDENDS

Generally, any dividend paid to a Non-United States person will be subject
to United States withholding tax either at a rate of 30% of the gross amount of
the dividend or at a lesser applicable treaty rate. However, dividends that are
effectively connected with the conduct of a trade or business within the United
States and, where a tax treaty applies, that are attributable to a United States
permanent establishment are not subject to the withholding tax but instead are
subject to United States federal income tax on a net income basis at applicable
graduated individual or corporate rates.

Certain certification and disclosure requirements must be complied with in
order to be exempt from withholding under the effectively connected income
exemption. Any effectively connected dividends received by a foreign corporation
may, under certain circumstances, be subject to an additional "branch profits
tax" at a 30% rate or a lesser applicable treaty rate.

Until January 1, 2001, dividends paid to an address outside the United
States are presumed to be paid to a resident of that country, unless the payer
has knowledge to the contrary, for purposes of the withholding tax discussed
above and, under the current interpretation of the United States Treasury
regulations, for purposes of determining the applicability of a tax treaty rate.
However, under United States Treasury regulations, if you wish to claim the
benefit of an applicable treaty rate and avoid backup withholding, as discussed
below, for dividends paid after December 31, 2000, you will be required to
satisfy applicable certification and other requirements.

If you are eligible for a reduced treaty rate of United States withholding
tax pursuant to an income tax treaty, you may obtain a refund of any excess
amounts withheld by filing an appropriate claim for refund with the Internal
Revenue Service.

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GAIN ON DISPOSITION OF COMMON STOCK

If you are a Non-United States person, you will generally not be subject to
United States federal income tax with respect to gain recognized on a sale or
other disposition of our common stock unless:

- the gain is effectively connected with a trade or business in the United
States and, where a tax treaty provides, the gain is attributable to a
United States permanent establishment;

- if you are an individual and hold our common stock as a capital asset,
you are present in the United States for 183 or more days in the taxable
year of the sale or other disposition and certain other conditions are
met;

- you are subject to tax pursuant to the provisions of the Code regarding
taxation of certain U.S. expatriates; or

- we are or have been a "United States real property holding corporation"
for United States federal income tax purposes.

We believe that we are not, and do not anticipate becoming, a "United
States real property holding corporation" for United States federal income tax
purposes. If we were to become a United States real property holding
corporation, so long as our common stock continues to be regularly traded on an
established securities market, you would be subject to federal income tax on any
gain from the sale or other disposition of the stock only if you actually or
constructively owned, during the five-year period preceding the disposition,
more than 5% of our common stock.

Special rules may apply to certain Non-United States persons, such as
"controlled foreign corporations," "passive foreign investment companies,"
"foreign personal holding companies" and corporations that accumulate earnings
to avoid federal income tax, that are subject to special treatment under the
Code. These entities should consult their own tax advisors to determine the
United States federal, state, local and other tax consequences that may be
relevant to them.

BACKUP WITHHOLDING AND INFORMATION REPORTING

We must report annually to the Internal Revenue Service and to you the
amount of dividends paid to you and the tax withheld with respect to these
dividends, regardless of whether withholding was required. Copies of the
information returns reporting the dividends and withholding may also be made
available to the tax authorities in the country in which you reside under the
provisions of an applicable income tax treaty.

Under current law, backup withholding at the rate of 31% generally will not
apply to dividends paid to you at an address outside the United States, unless
the payer has knowledge that you are a United States person. Under the final
regulations effective December 31, 2000, however, you will be subject to backup
withholding unless applicable certification requirements are met.

Payment of the proceeds of a sale of our common stock within the United
States or conducted through certain U.S. related financial intermediaries is
subject to both backup withholding and information reporting unless you certify
under penalties of perjury that you are a Non-United States person, and the
payer does not have actual knowledge that you are a United States person, or you
otherwise establish an exemption.

Any amounts withheld under the backup withholding rules may be allowed as a
refund or a credit against your United States federal income tax liability
provided the required information is furnished to the Internal Revenue Service.

ESTATE TAX

Common stock held by an individual Non-United States person at the time of
death will be included in that holder's gross estate for United States federal
estate tax purposes, unless an applicable estate tax treaty provides otherwise.
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UNDERWRITING

Subject to the terms and conditions stated in the underwriting agreement
dated the date hereof, each underwriter named below has severally agreed to
purchase, and NRG Energy, Inc. has agreed to sell to such underwriter, the
number of shares set forth opposite the name of such underwriter.

<TABLE>
<CAPTION>
NUMBER
NAME OF SHARES
---- ----------
<S> <C>
Salomon Smith Barney Inc....................................
Credit Suisse First Boston Corporation......................
ABN AMRO Incorporated.......................................
Banc of America Securities LLC..............................
Goldman, Sachs & Co.........................................
Lehman Brothers Inc.........................................
Merrill Lynch, Pierce, Fenner & Smith
Incorporated...................................
Morgan Stanley & Co. Incorporated...........................
----------
Total..................................................... 28,170,000
==========
</TABLE>

The underwriting agreement provides that the obligations of the several
underwriters to purchase the shares included in this offering are subject to
approval of certain legal matters by counsel and to certain other conditions.
The underwriters are obligated to purchase all the shares (other than those
covered by the over-allotment option described below) if they purchase any of
the shares.

The underwriters, for whom Salomon Smith Barney Inc. and Credit Suisse
First Boston Corporation, ABN AMRO Incorporated, Banc of America Securities LLC,
Goldman, Sachs & Co., Lehman Brothers Inc., Merrill Lynch, Pierce Fenner & Smith
Incorporated and Morgan Stanley & Co. Incorporated are acting as
representatives, propose to offer some of the shares directly to the public at
the public offering price set forth on the cover page of this prospectus and
some of the shares to certain dealers at the public offering price less a
concession not in excess of $ per share. The underwriters may allow,
and such dealers may reallow, a concession not in excess of $ per share
on sales to certain other dealers. If all of the shares are not sold at the
initial offering price, the representatives may change the public offering price
and the other selling terms.

We have granted to the underwriters an option, exercisable for 30 days from
the date of this prospectus, to purchase up to 4,225,500 additional shares of
common stock at the public offering price less the underwriting discount. The
underwriters may exercise such option solely for the purpose of covering
over-allotments, if any, in connection with this offering. To the extent such
option is exercised, each underwriter will be obligated, subject to certain
conditions, to purchase a number of additional shares approximately
proportionate to such underwriter's initial purchase commitment.

We, our officers and directors, and Northern States Power have agreed that,
for a period of 180 days from the date of this prospectus, they will not,
without the prior written consent of Salomon Smith Barney Inc., dispose of or
hedge any shares of our common stock or any securities convertible into or
exchangeable for common stock. Salomon Smith Barney Inc. in its sole discretion
may release any of the securities subject to these lock-up agreements at any
time without notice.

Prior to this offering, there has been no public market for the common
stock. Consequently, the initial public offering price for the shares was
determined by negotiations among us and the representatives. Among the factors
considered in determining the initial public offering price were our record of
operations, our current financial condition, our future prospects, our markets,
the economic conditions in and future prospects for the industry in which we
compete, our management, and currently prevailing general conditions in the
equity securities markets, including current market valuations of publicly
traded companies considered comparable to us. There can be no assurance,
however, that the prices at which the shares will sell in the public market
after this offering will not be lower than the price at which they are

91
<PAGE> 96

sold by the underwriters or that an active trading market in the common stock
will develop and continue after this offering.

We have applied to have the common stock listed on the NYSE under the
symbol "NRG".

The following table shows the underwriting discounts and commissions to be
paid to the underwriters by us in connection with this offering. These amounts
are shown assuming both no exercise and full exercise of the underwriters'
option to purchase additional shares of common stock.

<TABLE>
<CAPTION>
PAID BY NRG
----------------------------
NO EXERCISE FULL EXERCISE
----------- -------------
<S> <C> <C>
Per share................................................... $ $
Total....................................................... $ $
</TABLE>

In connection with the offering, Salomon Smith Barney Inc., on behalf of
the underwriters, may purchase and sell shares of common stock in the open
market. These transactions may include over-allotment, syndicate covering
transactions and stabilizing transactions. Over-allotment involves syndicate
sales of common stock in excess of the number of shares to be purchased by the
underwriters in the offering, which creates a syndicate short position.
Syndicate covering transactions involve purchases of the common stock in the
open market after the distribution has been completed in order to cover
syndicate short positions. Stabilizing transactions consist of certain bids or
purchases of common stock made for the purpose of preventing or retarding a
decline in the market price of the common stock while the offering is in
progress.

The underwriters also may impose a penalty bid. Penalty bids permit the
underwriters to reclaim a selling concession from a syndicate member when
Salomon Smith Barney Inc., in covering syndicate short positions or making
stabilizing purchases, repurchases shares originally sold by that syndicate
member.

Any of these activities may cause the price of the common stock to be
higher than the price that otherwise would exist in the open market in the
absence of such transactions. These transactions may be effected on the NYSE or
in the over-the-counter market, or otherwise and, if commenced, may be
discontinued at any time.

We estimate that the total expenses of this offering will be $1,075,000.

The representatives have performed certain investment banking and advisory
services for us from time to time for which they have received customary fees
and expenses. The representatives may, from time to time, engage in transactions
with and perform services for us in the ordinary course of their business.

We have agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933, or to contribute to
payments the underwriters may be required to make in respect of any of those
liabilities.

Because an affiliate of Salomon Smith Barney Inc. is a party to the $300
million Citicorp USA loan with us, which will be repaid with the proceeds of
this offering, this offering is being conducted in accordance with Rule 2720 of
the National Association of Securities Dealers, Inc. That rule requires that the
initial public offering price may be no higher than that recommended by a
"qualified independent underwriter", as defined by the NASD. Credit Suisse First
Boston Corporation is serving in that capacity and has conducted due diligence
and participated in the preparation of the registration statement of which this
prospectus forms a part. The initial public offering price will be no higher
than that recommended by Credit Suisse First Boston Corporation.

At our request, certain of the underwriters have reserved up to 5% of the
shares offered hereby (the "Directed Shares") for sale, at the initial public
offering price, to some of our directors, officers and employees who have
advised us of their desire to purchase such shares. The number of shares of our
common stock available for sale to the general public will be reduced to the
extent of sales of Directed

92
<PAGE> 97

Shares to any of the persons for whom they have been reserved. Any shares not so
purchased will be offered by the underwriters on the same basis as all other
shares of common stock offered hereby.

LEGAL MATTERS

The validity of the shares of common stock being offered will be passed on
for NRG by Gibson, Dunn & Crutcher LLP. Certain legal matters will be passed on
for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP. Skadden, Arps,
Slate, Meagher & Flom LLP has from time to time represented us and may in the
future, from time to time, represent us in connection with various matters.

EXPERTS

The consolidated financial statements of NRG Energy, Inc. and the carve-out
financial statements of Cajun Electric as of December 31, 1999 and 1998 and for
each of the three years in the period ended December 31, 1999 included in this
prospectus have been so included in reliance on the reports of
PricewaterhouseCoopers LLP, independent accountants, given on the authority of
said firm as experts in auditing and accounting.

AVAILABLE INFORMATION

We have filed with the United States Securities and Exchange Commission a
registration statement on Form S-1 under the Securities Act about the common
stock that we are offering. This prospectus does not contain all of the
information set forth in the registration statement and the exhibits and
schedules to it. In addition, we currently file, and after the offering we will
continue to file, annual, quarterly and special reports, proxy statements and
other information with the Commission. For further information with respect to
us, please refer to these documents on file, including the registration
statement, and the exhibits and schedules thereto, which may be inspected
without charge and copied at prescribed rates at the Commission's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may
obtain information on the operation of the Public Reference Room by calling the
Commission at 1-800-SEC-0330. The Commission maintains a website that contains
reports, proxy and information statements and other information filed
electronically with the Commission at http://www.sec.gov.

93
<PAGE> 98

INDEX TO NRG ENERGY, INC. FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS
Independent Accountant's Report........................... F-2
Consolidated Statement of Income.......................... F-3
Consolidated Statement of Cash Flows...................... F-4
Consolidated Balance Sheet................................ F-5
Consolidated Statement of Stockholder's Equity............ F-6
Notes to Consolidated Financial Statements................ F-7

INDEX TO PRO-FORMA FINANCIAL STATEMENTS

Introduction to Pro Forma Financial Statements.............. F-35
Pro Forma Income Statement for the three month period ended
March 31, 2000............................................ F-36
Pro Forma Balance Sheet..................................... F-37
Pro Forma Income Statement for the year ended December 31,
1999...................................................... F-39
</TABLE>

CAJUN ELECTRIC (CAJUN FACILITIES)

INDEX TO CARVE-OUT FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
Independent Accountant's Report............................. F-40
Carve-Out Statement of Net Assets........................... F-41
Carve-Out Statement of Certain Revenue and Expenses......... F-42
Notes to Financial Statements............................... F-43
</TABLE>

F-1
<PAGE> 99

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder
of NRG Energy, Inc.:

In our opinion, the accompanying consolidated balance sheet and the related
consolidated statement of income, of stockholder's equity and of cash flows
present fairly, in all material respects, the financial position of NRG Energy,
Inc. (a wholly-owned subsidiary of Northern States Power Company) and its
subsidiaries at December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999, in conformity with accounting principles generally accepted in the
United States. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these
statements in accordance with auditing standards generally accepted in the
United States, which 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, assessing the
accounting principles used and significant estimates made by management and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.

/s/ PRICEWATERHOUSECOOPERS LLP

March 17, 2000, except as to

Note 15 which is as of May 5, 2000.

F-2
<PAGE> 100

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME

<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
-------------------------------- --------------------
1997 1998 1999 1999 2000
---- ---- ---- ---- ----
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations... $ 92,052 $100,424 $432,518 $ 37,847 $332,671
Equity in earnings of unconsolidated
affiliates........................... 26,200 81,706 67,500 8,667 (9,644)
-------- -------- -------- -------- --------
Total operating revenues and equity
earnings........................... 118,252 182,130 500,018 46,514 323,027
-------- -------- -------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations......... 46,717 52,413 269,900 27,940 214,923
Depreciation and amortization........... 10,310 16,320 37,026 4,734 19,987
General, administrative and
development.......................... 43,116 56,385 83,572 15,985 25,180
-------- -------- -------- -------- --------
Total operating costs and expenses... 100,143 125,118 390,498 48,659 260,090
-------- -------- -------- -------- --------
OPERATING INCOME.......................... 18,109 57,012 109,520 (2,145) 62,937
-------- -------- -------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of
consolidated subsidiary.............. (131) (2,251) (2,456) (464) (1,798)
Gain on sale of interest in projects.... 8,702 29,950 10,994 -- --
Write-off of project investments........ (8,964) (26,740) -- -- --
Other income, net....................... 11,764 8,420 6,432 734 1,531
Interest expense........................ (30,989) (50,313) (93,376) (11,059) (52,317)
-------- -------- -------- -------- --------
Total other expense.................. (19,618) (40,934) (78,406) (10,789) (52,584)
-------- -------- -------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES......... (1,509) 16,078 31,114 (12,934) 10,353
INCOME TAX (BENEFIT) EXPENSE.............. (23,491) (25,654) (26,081) (11,994) 1,607
-------- -------- -------- -------- --------
NET INCOME................................ $ 21,982 $ 41,732 $ 57,195 $ (940) $ 8,746
======== ======== ======== ======== ========
Earnings (loss) per share -- basic and
diluted................................. $ .15 $ .28 $ .39 $ (.01) $ .06
======== ======== ======== ======== ========
Weighted Average shares
outstanding -- basic and diluted........ 147,605 147,605 147,605 147,605 147,605
======== ======== ======== ======== ========
</TABLE>

See notes to consolidated financial statements.

F-3
<PAGE> 101

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS

<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED DECEMBER 31, ENDED MARCH 31,
----------------------------------- ----------------------
1997 1998 1999 1999 2000
---- ---- ---- ---- ----
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................... $ 21,982 $ 41,732 $ 57,195 $ (940) $ 8,746
Adjustments to reconcile net income to net
cash provided by operating activities
Undistributed equity in earnings of
unconsolidated affiliates................ 6,481 (23,391) (27,181) 2,427 17,145
Depreciation and amortization.............. 10,310 16,320 37,026 4,734 19,987
Deferred income taxes and investment tax
credits.................................. 3,107 7,618 (3,401) 463 10,906
Minority interest.......................... -- (5,019) 857 (534) (1,694)
Investment write-downs..................... 8,964 26,740 -- -- --
Gain on sale of investments................ (8,702) (29,950) (10,994) -- --
Cash provided (used) by changes in certain
working capital items, net of effects
from acquisitions and dispositions
Accounts receivable...................... (2,859) 297 (99,608) (1,645) 4,401
Accounts receivable-affiliates........... (19,963) 21,657 9,964 (11,282) --
Accrued income taxes..................... 1,762 (24,861) 25,834 13,564 (13,793)
Inventory................................ (307) (28) (17,287) (1,639) 10,450
Other current assets..................... 305 469 (13,433) 746 (2,652)
Accrued property and sales taxes......... 1,645 (553) 1,740 1,798 2,175
Accounts payable-trade................... 7,791 (8,082) 40,616 5,375 28,778
Accounts payable-affiliates.............. -- -- -- -- (3,202)
Accrued salaries, benefits, and related
costs................................. 3,826 4,735 1,955 (2,440) (4,106)
Accrued interest......................... 1,215 1,050 5,192 1,471 20,289
Other current liabilities................ 6,084 (2,219) (3,533) (2,800) (5,937)
Cash used by changes in other assets and
liabilities........................... (7,155) (4,517) (16,322) (1,641) 65,317
--------- --------- ----------- -------- -----------
NET CASH (USED) PROVIDED BY OPERATING
ACTIVITIES................................... 34,486 21,998 (11,380) 7,657 156,810
--------- --------- ----------- -------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in projects.................... (318,149) (132,379) (107,260) (16,267) (17,933)
Acquisition, net of liabilities assumed.... (148,830) -- (1,519,365) -- (1,723,158)
Consolidation of equity subsidiaries....... -- -- 20,181 -- --
Cash from sale of project investment....... 19,158 18,053 43,500 -- --
Decrease (increase) in notes receivable.... (37,431) 16,858 58,331 18,438 293
Capital expenditures....................... (26,936) (31,719) (150,933) (6,331) (43,390)
(Increase) decrease in restricted cash..... 16,100 (2,433) (13,067) 1,884 2,456
Other, net................................. 10,114 -- -- -- --
--------- --------- ----------- -------- -----------
NET CASH USED BY INVESTING ACTIVITIES.......... (485,974) (131,620) (1,668,613) (2,276) (1,781,732)
--------- --------- ----------- -------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings under line of credit
agreement................................ 122,000 2,000 216,000 -- (36,000)
Capital contributions from parent.......... 80,900 100,000 250,000 100,000 --
Proceeds from issuance of long-term debt... 254,061 23,169 575,633 -- 2,482,853
Proceeds from issuance of note............. -- -- 682,096 -- --
Principal payments on long-term debt....... (5,925) (21,152) (18,634) (99,294) (715,491)
--------- --------- ----------- -------- -----------
NET CASH PROVIDED BY FINANCING ACTIVITIES...... 451,036 104,017 1,705,095 706 1,731,362
--------- --------- ----------- -------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................. (452) (5,605) 25,102 6,087 106,440
CASH AND CASH EQUIVALENTS AT BEGINNING OF
YEAR......................................... 12,438 11,986 6,381 6,381 31,483
========= ========= =========== ======== ===========
CASH AND CASH EQUIVALENTS AT END OF YEAR....... $ 11,986 $ 6,381 $ 31,483 $ 12,468 $ 137,923
========= ========= =========== ======== ===========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW
INFORMATION
Interest paid (net of amount
capitalized)............................. $ 30,890 $ 49,089 $ 82,891 $ 9,620 $ 32,028
Income taxes paid (benefits received),
net...................................... (24,577) (6,797) (54,384) (23,060) 5,954
</TABLE>

See notes to consolidated financial statements.
F-4
<PAGE> 102

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
----------------------- -----------
1998 1999 2000
---- ---- ----
(IN THOUSANDS)
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 6,381 $ 31,483 $ 137,923
Restricted cash........................................... 4,021 17,441 14,985
Accounts receivable-trade, less allowance for doubtful
accounts of $100, $186 and $1,392....................... 15,223 126,376 146,030
Accounts receivable-affiliates............................ 7,324 -- --
Taxes Receivable.......................................... 21,169 -- 7,819
Current portion of notes receivable -- affiliates......... 4,460 287 287
Current portion of notes receivable....................... 26,200 -- --
Inventory................................................. 2,647 119,181 165,501
Prepayments and other current assets...................... 4,533 29,202 31,854
---------- ---------- ----------
Total current assets.................................... 91,958 323,970 504,399
---------- ---------- ----------
PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST
In service................................................ 291,558 2,078,804 3,759,856
Under construction........................................ 5,352 53,448 86,681
---------- ---------- ----------
Total property, plant and equipment..................... 296,910 2,132,252 3,846,537
Less accumulated depreciation............................. (92,181) (156,849) (176,883)
---------- ---------- ----------
Net property, plant and equipment....................... 204,729 1,975,403 3,669,654
---------- ---------- ----------
OTHER ASSETS
Investments in projects................................... 800,924 932,591 893,303
Capitalized project costs................................. 13,685 2,592 12,558
Notes receivable, less current portion -- affiliates...... 101,887 65,494 65,193
Notes receivable, less current portion.................... 3,744 5,787 5,795
Intangible assets, net of accumulated amortization of
$2,984, 4,308 and 4,828................................. 22,507 55,586 56,072
Debt issuance costs, net of accumulated amortization of
$1,675, $6,640 and $10,093.............................. 7,276 20,081 36,260
Other assets, net of accumulated amortization of $7,350,
$8,909 and $9,444....................................... 46,716 50,180 50,574
---------- ---------- ----------
Total other assets...................................... 996,739 1,132,311 1,119,755
---------- ---------- ----------
TOTAL ASSETS................................................ $1,293,426 $3,431,684 5,293,808
---------- ---------- ----------
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Current portion of project level long-term debt........... $ 8,258 $ 30,462 24,789
Revolving line of credit.................................. -- 340,000 304,000
Consolidated project level, non-recourse debt............. -- 35,766 --
Corporate level, recourse debt............................ -- -- 300,000
Accounts payable-trade.................................... 7,371 61,211 115,837
Accounts payable-affiliate................................ -- 6,404 3,202
Accrued income taxes...................................... -- 4,730 --
Accrued property and sales taxes.......................... 3,251 4,998 7,173
Accrued salaries, benefits and related costs.............. 7,551 9,648 5,542
Accrued interest.......................................... 7,648 13,479 33,768
Other current liabilities................................. 8,289 17,657 12,996
---------- ---------- ----------
Total current liabilities............................... 42,368 524,355 807,307
OTHER LIABILITIES:
Minority interest......................................... 13,516 14,373 12,679
Consolidated project-level, long-term, non-recourse
debt.................................................... 113,437 1,026,398 2,300,888
Corporate level long-term debt, less current portion...... 504,781 915,000 1,169,608
Deferred Income Taxes..................................... 19,841 16,940 27,910
Deferred Investment Tax Credits........................... 1,343 1,088 1,024
Postretirement and other benefit obligations.............. 11,060 24,613 38,373
Other long-term obligations and deferred income........... 7,748 15,263 63,899
---------- ---------- ----------
Total liabilities....................................... 714,094 2,538,030 4,421,688
---------- ---------- ----------
STOCKHOLDER'S EQUITY
Class A common stock; $.01 par value; 250,000 shares
authorized; 147,605 shares issued and outstanding....... 1,476 1,476 1,476
Additional paid-in capital................................ 530,438 780,438 780,438
Retained earnings......................................... 130,015 187,210 195,956
Accumulated other comprehensive income (loss)............. (82,597) (75,470) (105,750)
---------- ---------- ----------
Total Stockholder's Equity.............................. 579,332 893,654 872,120
---------- ---------- ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................. $1,293,426 $3,431,684 $5,293,808
========== ========== ==========
</TABLE>

See notes to consolidated financial statements.
F-5
<PAGE> 103

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY

<TABLE>
<CAPTION>
ACCUMULATED
CLASS A ADDITIONAL OTHER TOTAL
COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDER'S
STOCK CAPITAL EARNINGS INCOME EQUITY
------- ---------- -------- ------------- -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCES AT DECEMBER 31, 1996.......... $1,476 $349,538 $ 66,301 $ 4,599 $421,914
====== ======== ======== ========= ========
Net Income............................. 21,982 21,982
Currency translation adjustments....... (74,098) (74,098)
--------
Comprehensive income for 1997.......... (52,116)
Capital contributions from parent...... 80,900 80,900
------ -------- -------- --------- --------
BALANCES AT DECEMBER 31, 1997.......... $1,476 $430,438 $ 88,283 $ (69,499) $450,698
====== ======== ======== ========= ========
Net Income............................. 41,732 41,732
Currency translation adjustments....... (13,098) (13,098)
--------
Comprehensive income for 1998.......... 28,634
Capital contributions from parent...... 100,000 100,000
------ -------- -------- --------- --------
BALANCES AT DECEMBER 31, 1998.......... $1,476 $530,438 $130,015 $ (82,597) $579,332
====== ======== ======== ========= ========
Net Income............................. 57,195 57,195
Currency translation adjustments....... 7,127 7,127
--------
Comprehensive income for 1999.......... 64,322
Capital contributions from parent...... 250,000 250,000
------ -------- -------- --------- --------
BALANCES AT DECEMBER 31, 1999.......... $1,476 $780,438 $187,210 $ (75,470) $893,654
====== ======== ======== ========= ========
Net Income (unaudited)................. 8,746 8,746
Currency translation adjustments
(unaudited).......................... (30,280) (30,280)
--------
Comprehensive income for 2000
(unaudited).......................... (21,534)
------ -------- -------- --------- --------
BALANCES AT MARCH 31, 2000
(UNAUDITED).......................... $1,476 $780,438 $195,956 $(105,750) $872,120
====== ======== ======== ========= ========
</TABLE>

Other comprehensive income is shown net of tax expenses (benefits) which
were $0 during the three months ended March 31, 2000 (unaudited) and $0 during
both 1999 and 1998 and $5.9 million in 1997.

See notes to consolidated financial statements.

F-6
<PAGE> 104

NOTE 1 -- ORGANIZATION

NRG Energy, Inc. (the Company), a Delaware Corporation, was incorporated on
May 29, 1992, as a wholly owned subsidiary of Northern States Power Company
(NSP). Beginning in 1989, the Company was doing business through its predecessor
companies, NRG Energy, Inc. and NRG Group, Inc., Minnesota corporations, which
were merged into the Company subsequent to its incorporation. The Company and
its subsidiaries and affiliates develop, build, acquire, own and operate
non-regulated energy-related businesses.

NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION AND BASIS OF PRESENTATION

The consolidated financial statements include the accounts of the Company
and its subsidiaries (referred to collectively herein as the Company). All
significant intercompany transactions and balances have been eliminated in
consolidation. Accounting policies for all of the Company's operations are in
accordance with accounting principles generally accepted in the United States.
As discussed in Note 5, the Company has investments in partnerships, joint
ventures and projects for which the equity method of accounting is applied.
Earnings from equity in international investments are recorded net of foreign
income taxes.

CASH EQUIVALENTS

Cash equivalents include highly liquid investments (primarily commercial
paper) with a remaining maturity of three months or less at the time of
purchase.

RESTRICTED CASH

Restricted cash consists primarily of cash collateral for letters of credit
issued in relation to project development activities and funds held in trust
accounts to satisfy the requirements of certain debt agreements.

INVENTORY

Inventory is valued at the lower of average cost or market and consists
principally of fuel oil, coal, spare parts and raw materials used to generate
steam.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are capitalized at original cost. Significant
additions or improvements extending asset lives are capitalized, while repairs
and maintenance are charged to expense as incurred. Depreciation is computed
using the straight-line method over the following estimated useful lives:

<TABLE>
<S> <C>
Facilities and improvements................................. 10-45 years
Machinery and equipment..................................... 7-30 years
Office furnishings and equipment............................ 3-5 years
</TABLE>

CAPITALIZED INTEREST

Interest incurred on funds borrowed to finance projects expected to require
more than three months to complete is capitalized. Capitalization of interest is
discontinued when the project is completed and considered operational.
Capitalized interest is amortized using the straight line method over the useful
life of the related project. Capitalized interest was $287,000 and $172,000 in
1999 and 1998, respectively.

DEVELOPMENT COSTS AND CAPITALIZED PROJECT COSTS

These costs include professional services, dedicated employee salaries,
permits, and other costs which are incurred incidental to a particular project.
Such costs are expensed as incurred until a sales agreement

F-7
<PAGE> 105

or letter of intent is signed, and the project has been approved by the
Company's Board of Directors. Additional costs incurred after this point are
capitalized. When project operations begin, previously capitalized project costs
are reclassified to investment in projects and amortized on a straight-line
basis over the lesser of the life of the project's related assets or revenue
contract period.

DEBT ISSUANCE COSTS

Costs to issue long-term debt have been capitalized and are being amortized
over the terms of the related debt.

INTANGIBLES

Intangibles consist principally of the excess of the cost of investment in
subsidiaries over the underlying fair value of the net assets acquired and are
being amortized using the straight-line method over 20 to 30 years. The Company
periodically evaluates the recovery of goodwill and other intangibles based on
an analysis of estimated undiscounted future cash flows.

OTHER LONG TERM ASSETS

Other long-term assets consist primarily of service agreements and
operating contracts. These assets are being amortized over the remaining terms
of the individual contracts, which range from seven to twenty-eight years.

INCOME TAXES

The Company is included in the consolidated tax returns of NSP. The Company
calculates its income tax provision on a separate return basis under a tax
sharing agreement with NSP as discussed in Note 9. Current federal and state
income taxes are payable to or receivable from NSP. The Company records income
taxes using the liability method. Income taxes are deferred on all temporary
differences between pretax financial and taxable income and between the book and
tax bases of assets and liabilities. Deferred taxes are recorded using the tax
rates scheduled by law to be in effect when the temporary differences reverse.
The Company's policy for income taxes related to international operations is
discussed in Note 9.

REVENUE RECOGNITION

Under fixed-price contracts, revenues are recognized as products or
services are delivered. Revenues and related costs under cost reimbursable
contract provisions are recorded as costs are incurred. Anticipated future
losses on contracts are charged against income when identified.

FOREIGN CURRENCY TRANSLATION

The local currencies are generally the functional currency of the Company's
foreign operations. Foreign currency denominated assets and liabilities are
translated at end-of-period rates of exchange. The resulting currency
adjustments are accumulated and reported as a separate component of
stockholder's equity. Income, expense, and cash flows are translated at
weighted-average rates of exchange for the period.

DERIVATIVE FINANCIAL INSTRUMENTS

To preserve the U.S. dollar value of projected foreign currency cash flows,
the Company hedges, or protects, those cash flows if appropriate foreign hedging
instruments are available. The gains and losses on those agreements offset the
effect of exchange rate fluctuations on the Company's known and anticipated cash
flows. The Company defers gains on agreements that hedge firm commitments of
cash flows, and accounts for them as part of the relevant foreign currency
transaction when the transaction occurs. The Company defers expected losses on
these agreements, unless it appears that the deferral would result in
recognizing a loss later.

F-8
<PAGE> 106

While the Company is not currently hedging investments involving foreign
currency, the Company will hedge such investments when it believes that
preserving the U.S. dollar value of the investment is appropriate. The Company
is not hedging currency translation adjustments related to future operating
results. The Company does not speculate in foreign currencies.

From time to time the Company also uses interest rate hedging instruments
to protect it from an increase in the cost of borrowing. Gains and losses on
interest rate hedging instruments are reported as part of the asset for
Investments In Projects when the hedging instrument relates to a project that
has financial statements that are not consolidated into the Company's financial
statements. Otherwise, they are reported as part of debt.

USE OF ESTIMATES

The preparation of financial statements in conformity with Generally
Accepted Accounting Principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period.

In recording transactions and balances resulting from business operations,
the Company uses estimates based on the best information available. Estimates
are used for such items as plant depreciable lives, tax provisions,
uncollectible accounts and actuarially determined benefit costs, among others.
As better information becomes available (or actual amounts are determinable),
the recorded estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates.

NEW ACCOUNTING PRONOUNCEMENTS

In June 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities,". This statement requires that
all derivatives be recognized at fair value in the balance sheet and that
changes in fair value be recognized either currently in earnings or deferred as
a component of Other Comprehensive Income, depending on the intended use of the
derivative, its resulting designation and its effectiveness. The Company plans
to adopt this standard in the first quarter of 2001, as required. The Company
has not determined the potential impact of implementing this statement.

RECLASSIFICATIONS

Certain prior-year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or stockholder's equity as
previously reported.

INTERIM RESULTS (UNAUDITED)

Information for the three months ended March 31, 2000 and 1999 is
unaudited. The information furnished in the unaudited March 31, 2000 and March
31, 1999 Statements of Income and Cash Flows include all adjustments, consisting
only of normal recurring accruals, which are, in the opinion of management,
necessary for a fair presentation of such financial statements. The data
disclosed in these notes to the financial statements for this period is also
unaudited.

NOTE 3 -- ASSET ACQUISITIONS AND DIVESTITURES

In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI)
the remaining 50.1% limited partnership interests held by TVI in San Francisco
Thermal Limited Partnership and Pittsburgh Thermal Limited Partnership for $12.3
million. In April 1999, NRG acquired TVI's 50% member interest in North American
Thermal Systems LLC (the entity holding the general partnership interest in the
San Francisco and Pittsburgh partnerships) for $500,000.

In 1994, the Company, through a wholly-owned subsidiary, purchased a 50%
ownership interest in Sunnyside Cogeneration Associates, a Utah joint venture,
which owns and operates a 58 MW waste coal plant in Utah. The waste coal plant
is currently being operated by a partnership that is 50% owned by a
F-9
<PAGE> 107

Company affiliate. In March 1999, the Company and its partner executed an
agreement to sell the Sunnyside project to an affiliate of Baltimore Gas &
Electric for a purchase price of $2.0 million. There was no gain or loss on the
sale which closed during the second quarter of 1999.

In April 1999, the Company completed the acquisition of the Somerset power
station for approximately $55 million from the Eastern Utilities Association
(EUA). The Somerset station, located in Somerset, Massachusetts, includes two
coal-fired generating facilities and two aeroderivative combustion turbine
peaking units with a capacity rating of 229 MW, of which 69 MW is on deactivated
reserve. In connection with this acquisition, the Company entered into a
Wholesale Standard Offer Service Agreement pursuant to which the Company is
obligated to provide approximately 30% of the energy and capacity requirements
of certain EUA affiliates (which is estimated to be approximately 275 MW at peak
requirement) until December 31, 2009.

In May 1999, the Company and Dynegy Power Corporation (Dynegy), through
West Coast Power LLC, completed the acquisition of the Encina generating station
and 17 combustion turbines for approximately $356 million from San Diego Gas &
Electric Company. The facilities, which have a combined capacity rating of 1,218
MW, are located near Carlsbad and San Diego, California. The Company and Dynegy
each own a 50% interest in these facilities.

In June 1999, the Company completed its acquisition of the Huntley and
Dunkirk generating stations from Niagara Mohawk Power Corporation (NIMO) for
approximately $355 million. The two coal-fired power generation facilities are
located near Buffalo, New York, and have a combined summer capacity rating of
1,360 MW. In connection with this acquisition, the Company entered into several
Transition Power Purchase Agreements and a related swap agreement with NIMO
pursuant to which NIMO purchases certain energy and capacity from these
facilities for a term of four years.

In June 1999, the Company completed its acquisition of the Arthur Kill
generating station and the Astoria gas turbine site from Consolidated Edison
Company of New York, Inc. (ConEd) for approximately $505 million. These
facilities, which are located in the New York City Area, have a combined
capacity rating of 1,456 MW. In connection with the acquisition of each
facility, the Company entered into (i) Transition Energy Sales Agreements
pursuant to which energy from each facility is sold to ConEd for a transition
period ending on the date on which the independent system operator in New York
State (NYISO) commences operation (which commencement date was November 18,
1999) of a spot market for energy and certain ancillary services, and (ii)
Transition Capacity Sales Agreements pursuant to which capacity from each
facility is sold to ConEd for a transition period ending on the later of (a) the
earlier of (i) December 31, 2002 or (ii) the date such facility receives notice
from the NYISO that none of the electric generating capacity of such facility is
required for meeting the installed capacity requirements in New York City, or
(b) the date the NYISO commences an auction for system capacity. Pursuant to the
Transition Energy Sales Agreements, the Company agreed to sell to ConEd at a
fixed price varying amounts of energy from the Arthur Kill generating facility
and the Astoria gas turbine generating facility, in each case in amounts to be
specified by ConEd, up to the full capability of each facility. Pursuant to the
Transition Capacity Sales Agreements, the Company agreed to sell to ConEd at a
fixed price, during certain periods, up to 100% of the capacity of the Arthur
Kill generating facility and up to 100% of the capacity of the Astoria gas
turbines facility.

In August 1999, the Company agreed to sell all but a 20 percent ownership
interest in Cogeneration Corporation of America (CogenAmerica) to Calpine
Corporation in connection with Calpine's acquisition of the remaining shares of
CogenAmerica. Prior to December 1999, the Company owned approximately 45% of
CogenAmerica. Upon closing of the transaction, all outstanding shares of
CogenAmerica common stock (other than those retained by the Company) were
acquired by Calpine for a cash purchase price of $25.00 per share. The
transaction closed during the fourth quarter of 1999 and the Company retained a
20% ownership interest in CogenAmerica.

In October 1999, the Company completed its acquisition of the Oswego
generating station from NIMO and Rochester Gas and Electric for approximately
$85 million. The oil and gas-fired power generating facility which has a
capacity rating of 1,700 MW, is located on a 93-acre site in Oswego, New
F-10
<PAGE> 108

York. This facility consists of two units each having a capacity rating of 850
MW. In connection with this acquisition, the Company entered into a Transition
Power Purchase Agreement with NIMO similar to those entered into in connection
with the acquisitions of the Dunkirk and Huntley facilities. Pursuant to this
agreement, the Company has agreed to sell 100% of the capacity of one unit, an
option for up to 40% of the capacity of the other unit. The Company has agreed
to sell NIMO an option to purchase a nominal amount of energy for a term of four
years.

In December 1999, the Company acquired four fossil fuel generating stations
and six remote gas turbines from CL&P for approximately $460 million, plus
adjustments for working capital. These facilities are located throughout
Connecticut and have a combined nominal capacity rating of 2,235 MW. The Company
entered into a Standard Offer Service Wholesale Sales Agreement with CL&P
pursuant to which the Company will supply CL&P with 35% of its standard offer
service load during 2000, 40% during 2001 and 2002, and 45% during 2003. The
Company estimates that 45% of CL&P's standard offer service load in 2003 will be
approximately 2,070 MW at peak requirement. The Agreement terminates on December
31, 2003.

In December 1999, the Company purchased a 50% interest in the Rocky Road
Power Plant, a 250 MW natural gas fired simple-cycle peaking facility in East
Dundee, IL from Dynegy Inc., for approximately $60 million. The power plant
began commercial operations on June 30, 1999 and received approval for the
installation of an additional 100 MW natural gas combustion turbine in October
1999, increasing the facilities generating capacity to a nominal 350 MW. The
expansion is expected to be in service before the start of the peak summer 2000
season.

Pro forma information has not been presented for the assets acquired in
1999 due to the fact that the assets acquired do not constitute businesses under
Rule 11-01(d) of Regulation S-X. Accordingly, historical financial information
does not exist for the assets acquired.

PRO FORMA RESULTS OF OPERATIONS -- CAJUN ACQUISITION (UNAUDITED)

During March 2000, the Company completed the acquisition of two fossil
fueled generating plants from Cajun Electric Power Cooperative, Inc. for
approximately $1.026 billion. The following information summarizes the pro forma
results of operations as if the acquisition had occurred as of the beginning of
the three-month period ended March 31, 2000. The pro forma information presented
is for informational purposes only and is not necessarily indicative of future
earnings or financial position or of what the earnings and financial position
would have been had the acquisition of the Cajun Electric Facilities been
consummated at the beginning of the respective periods or as of the date for
which pro forma financial information is presented.

<TABLE>
<CAPTION>
(Unaudited)
Pro Forma
3 Months Ended
March 31, 1999 March 31, 2000
(In Thousands) -------------- --------------
<S> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations..................... $116,450 $412,653
Equity in earnings of unconsolidated affiliates........... 8,667 (9,644)
-------- --------
TOTAL OPERATING REVENUES.................................... 125,117 403,009
Total operating costs and expenses.......................... 114,729 328,198
-------- --------
OPERATING INCOME............................................ 10,388 74,811
Other income (expense)...................................... (28,885) (70,375)
-------- --------
INCOME (LOSS) BEFORE INCOME TAXES........................... (18,497) 4,436
Income tax (benefit) expense................................ (14,296) (841)
-------- --------
NET INCOME (LOSS)........................................... $ (4,201) $ 5,277
======== ========
</TABLE>

F-11
<PAGE> 109

NOTE 4 -- PROPERTY, PLANT AND EQUIPMENT

The major classes of property, plant and equipment at December 31 and March
31 were as follows:

<TABLE>
<CAPTION>
MARCH 31,
1998 1999 2000
---- ---- ---------
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<S> <C> <C> <C>
Facilities and equipment, including
construction work in progress of $5,352,
$53,448 and $86,681..................... $280,876 $2,056,621 $3,738,636
Land and improvements..................... 10,397 64,330 79,606
Office furnishings and equipment.......... 5,637 11,301 28,295
-------- ---------- ----------
Total property, plant and
equipment.......................... 296,910 2,132,252 3,846,537
Accumulated depreciation.................. (92,181) (156,849) (176,883)
-------- ---------- ----------
Net property, plant and equipment......... $204,729 $1,975,403 $3,669,654
======== ========== ==========
</TABLE>

NOTE 5 -- INVESTMENTS ACCOUNTED FOR BY THE EQUITY METHOD

The Company has investments in various international and domestic energy
projects. The equity method of accounting is applied to such investments in
affiliates, which include joint ventures and partnerships, because the ownership
structure prevents the Company from exercising a controlling influence over
operating and financial policies of the projects. Under this method, equity in
pretax income or losses of domestic partnerships and, generally, in the net
income or losses of international projects are reflected as equity in earnings
of unconsolidated affiliates.

A summary of the Company's significant equity-method investments which were
in operation at December 31, 1999 is as follows:

<TABLE>
<CAPTION>
ECONOMIC PURCHASED OR
NAME GEOGRAPHIC AREA INTEREST PLACED IN SERVICE
---- --------------- -------- -----------------
<S> <C> <C> <C>
Loy Yang A................................... Australia 25.37% May 1997
Energy Developments Limited.................. Australia 29.14% February 1997
ECK Generating............................... Czech Republic 44.50% December 1994
MIBRAG mbH................................... Germany 33.33% January 1994
Gladstone Power Station...................... Australia 37.50% March 1994
Schkopau Power Station....................... Germany 20.95% January and July 1996
Scudder Latin American Projects.............. Latin America 6.63% June 1993
Long Beach Generating........................ USA 50.00% April 1998
El Segundo Power............................. USA 50.00% April 1998
Bolivian Power Company (Cobee)............... Bolivia 49.10% December 1996
Cogeneration Corp. of America................ USA 20.00% April 1996
Encina....................................... USA 50.00% May 1999
San Diego Combustion Turbines................ USA 50.00% May 1999
</TABLE>

Summarized financial information for investments in unconsolidated
affiliates accounted for under the equity method as of and for the year ended
December 31, is as follows:

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues....................................... $1,612,897 $1,491,197 $1,732,521
Costs and expenses....................................... 1,522,727 1,346,569 1,531,958
---------- ---------- ----------
Net income.......................................... $ 90,170 $ 144,628 $ 200,563
---------- ---------- ----------
</TABLE>

F-12
<PAGE> 110

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Current assets........................................... $ 713,390 $ 710,159 $ 742,674
Noncurrent assets........................................ 7,733,886 7,938,841 7,322,219
---------- ---------- ----------
Total assets........................................ $8,447,276 $8,649,000 $8,064,893
---------- ---------- ----------
Current liabilities...................................... $ 472,980 $ 527,196 $ 708,114
Noncurrent liabilities................................... 6,042,102 5,854,284 5,168,893
Equity................................................... 1,932,194 2,267,520 2,187,886
---------- ---------- ----------
Total liabilities and equity........................ $8,447,276 $8,649,000 $8,064,893
NRG's share of equity.................................... $ 694,655 $ 800,924 $ 932,591
NRG's share of income.................................... $ 26,200 $ 81,706 $ 67,500
</TABLE>

In accordance with FASB No. 121 "Accounting for Impairment of Long-lived
Assets and for Long-lived Assets to be Disposed of," the Company reviews long
lived assets, investments and certain intangibles for impairment whenever events
or circumstances indicate the carrying amounts of an asset may not be
recoverable. During 1998, the Company wrote down accumulated project development
expenditures of $26.7 million. The Company's West Java, Indonesia, project
totaling $22.0 million was written off due to the uncertainties surrounding
infrastructure projects in Indonesia. Also during 1998, the Company wrote off
its $1.9 million investment in the Sunnyside project and its $2.8 million
investment in Alto Cachopoal. The charge represents the difference between the
carrying amount of the investment and the fair value of the asset, determined
using a cash flow model. In December 1997, the Company reviewed the carrying
amount of the Sunnyside project that failed to restructure its debt and recorded
a charge of $8.9 million. The charge represents the difference between the
carrying amount of the investment and the fair value of the asset, determined
using a discounted cash flow model.

NOTE 6 -- RELATED PARTY TRANSACTIONS

SALE TO AFFILIATE

During October 1998, the Company sold its interest in the Mid-Continent
Power Corporation (MCPC) facility to CogenAmerica for a $2.1 million gain after
elimination of affiliate interest. The MCPC facility is a 110 MW, gas-fired
generation station located near Pryor, Oklahoma. The Company owns 20% of the
outstanding stock of CogenAmerica.

OPERATING AGREEMENTS

The Company has two agreements with NSP for the purchase of thermal energy.
Under the terms of the agreements, NSP charges the Company for certain costs
(fuel, labor, plant maintenance, and auxiliary power) incurred by NSP to produce
the thermal energy. The Company paid NSP $4.4 million in 1999 and $5.1 million
in 1998 under these agreements. For the three months ended March 31, 2000 and
1999, the Company paid NSP $1.4 million and $1.1 million, respectively under
these agreements (unaudited).

The Company has a renewable 10-year agreement with NSP, expiring on
December 31, 2001, whereby NSP agrees to purchase refuse-derived fuel for use in
certain of its boilers and the Company agrees to pay NSP a burn incentive. Under
this agreement, the Company received $1.4 million and $1.4 million from NSP, and
paid $2.7 million and $3.1 million to NSP in 1999 and 1998, respectively.

For the three months ended March 31, 2000 and 1999, the Company received
$0.6 million and $0.6 million from NSP, respectively. For the three months ended
March 31, 2000 and 1999, the Company paid $0.5 million and $0.5 million to NSP,
respectively (unaudited).

ADMINISTRATIVE SERVICES AND OTHER COSTS

The Company and NSP have entered into an agreement to provide for the
reimbursement of actual administrative services provided to each other, an
allocation of NSP administrative costs and a working capital fee. Services
provided by NSP to the Company are principally cash management, legal,
accounting,
F-13
<PAGE> 111

employee relations, benefits administration and engineering support. In
addition, the Company employees participate in certain employee benefit plans of
NSP as discussed in Note 10. During 1999 and 1998, the Company paid NSP $6.4
million and $5.2 million, respectively, as reimbursement under this agreement.
For the three months ended March 31, 2000 and 1999, the Company paid NSP $2.0
million and $2.2 million, respectively (unaudited).

In 1996, the Company and NSP entered into an agreement for the Company to
provide operations and maintenance services for NSP's Elk River resource
recovery facility and Becker ash landfill. During 1999 and 1998, NSP paid the
Company $1.9 million and $1.7 million, respectively, as compensation under this
agreement. For the three months ended March 31, 2000 and 1999, NSP paid the
Company $0.6 million and $0.6 million, respectively (unaudited).

NOTE 7 -- NOTES RECEIVABLE

Notes receivable consists primarily of fixed and variable rate notes
secured by equity interests in partnerships and joint ventures. The notes
receivable at December 31, and March 31 are as follows:

<TABLE>
<CAPTION>
MARCH 31,
1998 1999 2000
---- ---- ---------
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<S> <C> <C> <C>
COGENERATION CORPORATION OF AMERICA:
Note due 2001, 9.5%.................................... $ 2,539 $ -- $ --
Grays Ferry note due 2005, LIBOR plus 4.0%
(9.31%@12/98)....................................... 1,900 -- --
Morris note due 2004, prime +3.5% (11.25%@12/98)....... 12,027 -- --
MCPC note due 2004, prime +3.5% (11.25%@12/98)......... 23,947 -- --
El Paso note, due January 1999, non interest bearing..... 26,200 -- --
Thermal Ventures, Inc. note due 1999, 11%................ 1,500 -- --
TOSLI, various notes due 2000, LIBOR plus 4.0%
(10.0%@12/99).......................................... 132 207 207
Various secured notes due 2000 and later, non-interest
and interest bearing................................... 723 224 224
NEO notes to various affiliates due primarily 2012, prime
+2% to 12.5%........................................... 27,445 26,850 26,548
Southern MN Praireland Solid Waste, note due 2003, 7%.... 1,441 44 41
Pacific Generation, various notes, prime +2% to 12%...... 4,203 3,368 3,368
NRGenerating International BV notes to various
affiliates, non-interest bearing....................... 34,234 40,410 40,410
O'Brien Cogen II note, due 2008, non interest bearing.... -- 465 477
-------- ------- -------
Total............................................. $136,291 $71,568 $71,275
======== ======= =======
</TABLE>

F-14
<PAGE> 112

NOTE 8 -- LONG-TERM DEBT

Long-term debt consists of the following at December 31, and March 31:

<TABLE>
<CAPTION>
MARCH 31,
1998 1999 2000
---- ---- ---------
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<S> <C> <C> <C>
NEO Landfill Gas, Inc. term loan, due October 30,
2007, 9.35%........................................ $ 9,847 $ -- $ --
NEO Landfill Gas Inc. construction loan due October
30, 2007 LIBOR +1% (6.31% @ 12/98)................. 6,550 -- --
NEO Landfill Gas, Inc. City of L.A. term loan, due
December 2019 non-interest bearing................. 1,395 -- --
Revolving Line of Credit, due March 17, 2000,
5.85%.............................................. 124,000 -- --
COBEE, due April 21, 2000, 0%........................ -- 5,761 2,381
O'Brien Cogen II due August 31, 2000, 9.5%........... -- 2,893 2,893
NRG San Diego, Inc. promissory note, due June 25,
2003, 8.0%......................................... 2,141 1,729 1,621
Pittsburgh Thermal LP -- Credit Line, due 2004, LIBOR
+4.25%............................................. -- 1,100 1,100
San Francisco Thermal LP -- Credit Line, due 2004,
LIBOR +4.25%....................................... -- 900 900
Pittsburgh Thermal LP, due 2002-2004,
10.61%-10.73%...................................... -- 6,800 6,488
San Francisco Thermal LP, October 5, 2004, 10.61%.... -- 5,905 5,675
NRG Energy senior notes, due February 1, 2006,
7.625%............................................. 125,000 125,000 125,000
Note payable to NSP, due December 1, 1995-2006,
5.40%-6.75%........................................ 7,174 6,495 6,495
NRG Energy senior notes, due June 15, 2007, 7.50%.... 250,000 250,000 250,000
Camas Power Boiler LP, unsecured term loan, due June
30, 2007, 7.65%.................................... 17,576 17,087 15,726
Camas Power Boiler LP, revenue bonds, due August 1,
2007, 4.65%........................................ 11,010 9,130 9,625
Various NEO debt due 2005-2008, 9.35%................ -- 28,615 28,051
NRG Energy senior notes, due June 1, 2009, 7.50%..... -- 300,000 300,000
NRG Energy Center, Inc. senior secured notes due June
15, 2013, 7.31%.................................... 71,783 68,881 68,123
NRG Energy senior notes, due Nov. 1, 2013, 8.00%..... -- 240,000 240,000
Crockett Corp. LLP, due Dec. 31, 2014, 8.13%......... -- 255,000 252,643
NRG Northeast Generating debt........................ -- 646,564 --
NRG Northeast Generating LLC, senior bonds, due Dec.
15, 2004, 8.065%................................... -- -- 320,000
NRG Northeast Generating LLC, senior bonds, due June
15, 2015, 8.842%................................... -- -- 130,000
NRG Northeast Generating LLC, senior bonds, due Dec.
15, 2024, 9.292%................................... -- -- 300,000
NRG South Central Generating LLC, senior bonds, due
March 15, 2016, 8.962%............................. -- -- 500,000
NRG South Central Generating LLC, senior bonds, due
Sept. 15, 2024, 9.479%............................. -- -- 300,000
Sterling Luxembourg #3 Term Loan, due June 30, 2019,
7.86% -- Libor +1.31............................... -- -- 373,956
NRG Energy ROARS, due March 15, 2005, 7.97%.......... -- -- 254,608
---------- ---------- ----------
626,476 1,971,860 3,495,285
Less current maturities.............................. (8,258) (30,462) (24,789)
---------- ---------- ----------
Total......................................... $ 618,218 $1,941,398 $3,470,496
========== ========== ==========
</TABLE>

F-15
<PAGE> 113

The NRG Energy Center, Inc. notes are secured principally by long-term
assets of the Minneapolis Energy Center (MEC). In accordance with the terms of
the note agreement, MEC is required to maintain compliance with certain
financial covenants primarily related to incurring debt, disposing of MEC
assets, and affiliate transactions. MEC was in compliance with these covenants
at December 31, 1999.

The note payable to NSP relates to long-term debt assumed by the Company in
connection with the transfer of ownership of a Refuse Derived Fuel processing
plant by NSP to the Company in 1993.

The NRG Energy $125 million, $250 million, $300 million and $240 million
senior notes are unsecured and are used to support equity requirements for
projects acquired and in development. The interest is paid semi-annually and the
ten-year senior notes mature in February 2006, June 2007, and 2009. The fourteen
year notes mature in November 2013.

The $240 million of NRG Energy Senior notes due November 1, 2013 are
remarketable or redeemable Security (ROARS). November 1, 2003 is the first
remarketing date for these notes. Interest is payable semi-annually beginning
May 1, 2000 through November 1, 2003, and then at intervals and interest rates
as discussed in the indenture. On the remarketing date, the notes will either be
mandatorily tendered to and purchased by Credit Suisse Financial Products or
mandatorily redeemed by the Company at prices discussed in the indenture. The
notes are unsecured debt that rank senior to all of the Company's existing and
future subordinated indebtedness.

The NRG San Diego, Inc. promissory note is secured principally by long-term
assets of the San Diego Power & Cooling Company.

The various NEO notes are term loans. The loans are secured principally by
long-term assets of NEO Landfill Gas collection system. NEO Landfill Gas is
required to maintain compliance with certain covenants primarily related to
incurring debt, disposing of the NEO Landfill Gas assets, and affiliate
transactions.

The Camas Power Boiler LP notes are secured principally by long-term
assets. In accordance with the terms of the note agreements, Camas Power Boiler
LP is required to maintain compliance with certain financial covenants primarily
related to incurring debt, disposing of assets, and affiliate transactions.
Camas Power Boiler was in compliance with these covenants at December 31, 1999.

The Crockett Corporation term loan is secured by primarily the long-term
assets of the Crockett Cogeneration project.

The O'Brien Cogen II promissory note is payable on the earlier of the first
anniversary of the effective date (August 31, 1999) or upon the sale of the
assets at the O'Brien Cogen II facility. Full payment of the note is guaranteed
by the Company.

Annual maturities of long-term debt for the years ending after December 31,
1999 are as follows:

<TABLE>
<CAPTION>
(THOUSANDS OF DOLLARS)
----------------------
<S> <C>
2000...................................................... $ 30,462
2001...................................................... 23,637
2002...................................................... 26,104
2003...................................................... 27,610
2004...................................................... 31,594
Thereafter................................................ 1,832,453
----------
Total................................................ $1,971,860
==========
</TABLE>

The Company has $550 million in revolving credit facilities under a
commitment fee arrangement. These facilities provide short-term financing in the
form of bank loans and letters of credit. At December 31, 1999, the Company has
$340 million outstanding under its revolving credit agreements.

The Company has a $500 million revolving credit facility under a commitment
fee arrangement that matures in March 9, 2001. This facility provides short-term
financing in the form of bank loans. At March 31, 2000, the Company had $304
million outstanding under this facility (Unaudited).

F-16
<PAGE> 114

The Company had $116 million and $33.6 million in outstanding letters of
credit as of December 31, 1999 and 1998, respectively.

In December 1999, the Company filed a shelf registration with the SEC to
issue up to $500 million of unsecured debt securities. The Company expects to
issue debt under this shelf during 2000 for general corporate purposes, which
may include financing, development and construction of new facilities, additions
to working capital and financing capital expenditures and pending or potential
acquisitions.

On February 22, 2000, NRG Northeast Generating issued $750 million of
senior secured bonds to refinance short-term project borrowings and for certain
other purposes. The bond offering included three tranches: $320 million with an
interest rate of 8.065 percent due in 2004, $130 million with an interest rate
of 8.842 percent due in 2015 and $300 million with an interest rate of 9.292
percent due in 2024. The Company used $647 million of the proceeds to repay
short-term borrowings outstanding at December 31, 1999; accordingly, $646.6
million of short term debt has been re-classified as long-term debt, based on
this refinancing.

In March 2000, the Company issued $250 million of 8.70% 20-year
remarketable or redeemable securities through an unconsolidated grantor trust.
The funds were subsequently converted to 160 million pound sterling and will be
used to finance the Company's investment in the Killingholme Power Station in
England.

In March 2000, the Company issued L160 million (approximately $250 million
at the time of issuance) of 7.97% reset senior notes due 2020, principally to
finance our equity investment in the Killingholme facility. On March 15, 2005,
these senior notes may be remarketed by Bank of America, N.A. at a fixed rate of
interest through the maturity date or, at a floating rate of interest for up to
one year and then at a fixed rate of interest through 2020. Interest is payable
semi-annually on these securities beginning September 15, 2000 through March 15,
2005, and then at intervals and interest rates established in the remarketing
possess (Unaudited).

In March 2000, three of the Company's foreign subsidiaries entered into a
L335 million ($533 million) secured borrowing facility agreement with Bank of
America International Limited, as arranger. Under this facility, the financial
institutions have made available to our subsidiaries various term loans totaling
L235 million ($374 million) for purposes of financing the acquisition of the
Killingholme facility and L100 million ($159 million) of revolving credit and
letter of credit facilities to provide working capital for operating the
Killingholme facility. The final maturity date of the facility is the earlier of
June 30, 2019, or the date on which all borrowings and commitments under the
largest tranche of the term facility have been repaid or cancelled (Unaudited).

In March 2000, NRG South Central Generating LLC, a subsidiary of the
Company, issued $800 million of senior secured bonds in a two tranches. The
first tranche was for $500 million with a coupon of 8.962% and a maturity of
2016. The second tranche was for $300 million with a coupon of 9.479% and a
maturity of 2024. During March 2000, the proceeds were used to finance the
Company's investment in the Cajun generating facilities (unaudited).

GUARANTEES

The Company may be directly liable for the obligations of certain of its
project affiliates and other subsidiaries pursuant to guarantees relating to
certain of their indebtedness, equity and operating obligations. One example is
the Company's guarantee of the obligations of its project subsidiary that
operates the Gladstone facility for up to AUS$25 million, indexed to the
Australian consumer price index, under the project subsidiary's operating and
maintenance agreement with the owners of the facility. In addition, in
connection with the purchase and sale of fuel, emission credits and power
generation products to and from third parties with respect to the operation of
some of the Company's generation facilities in the United States, the Company
may be required to guarantee a portion of the obligations of certain of its
subsidiaries. As of December 31, 1999, the Company's obligations pursuant to its
guarantees of the performance, equity and indebtedness obligations of its
subsidiaries totaled approximately $416.4 million.

F-17
<PAGE> 115

As of March 31, 2000, the Company's obligations pursuant to its guarantees of
the performance, equity and indebtedness obligations of its subsidiaries totaled
approximately $504 million (unaudited).

NOTE 9 -- INCOME TAXES

The Company and its parent, NSP, have entered into a federal and state
income tax sharing agreement relative to the filing of consolidated federal and
state income tax returns. The agreement provides, among other things, that (1)
if the Company, along with its subsidiaries, is in a taxable income position,
the Company will be currently charged with an amount equivalent to its federal
and state income tax computed as if the group had actually filed separate
federal and state returns, and (2) if the Company, along with its subsidiaries,
is in a tax loss position, the Company will be currently reimbursed to the
extent its combined losses are utilized in a consolidated return, and (3) if the
Company, along with its subsidiaries, generates tax credits, the Company will be
currently reimbursed to the extent its tax credits are utilized in a
consolidated return. The provision for income taxes consists of the following:

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Current
Federal................................................ $ (8,516) $(10,773) $ 3,620
State.................................................. (1,274) (3,940) 1,041
Foreign................................................ 236 2,358 4,040
-------- -------- --------
(9,554) (12,355) 8,701
Deferred
Foreign................................................ (2,703) (7,736) (7,668)
Federal................................................ (958) 8,828 (2,792)
State.................................................. (439) 1,541 (3,901)
-------- -------- --------
(4,100) 2,633 (14,361)
Tax credits recognized................................... (9,837) (15,932) (20,421)
-------- -------- --------
Total income tax (benefit).......................... $(23,491) $(25,654) $(26,081)
======== ======== ========
Effective tax rate....................................... (1,557)% (160)% (84)%
</TABLE>

The components of the net deferred income tax liability at December 31
were:

<TABLE>
<CAPTION>
1998 1999
---- ----
(THOUSANDS OF
DOLLARS)
<S> <C> <C>
Deferred tax liabilities
Differences between book and tax basis of property........ $29,712 $37,713
Investments in projects................................... 14,911 17,308
Goodwill.................................................. 978 1,117
Other..................................................... 6,212 5,544
------- -------
Total deferred tax liabilities............................ 51,813 61,682
Deferred tax assets
Deferred revenue.......................................... 1,402 841
Deferred compensation, accrued vacation and other
reserves............................................... 6,514 10,996
Development costs......................................... 9,241 6,768
Deferred investment tax credits........................... 661 450
Steam capacity rights..................................... 910 844
Foreign tax benefit....................................... 12,425 20,919
Other..................................................... 819 3,924
------- -------
Total deferred tax assets................................. 31,972 44,742
------- -------
Net deferred tax liability................................ $19,841 $16,940
======= =======
</TABLE>

F-18
<PAGE> 116

The effective income tax rate for the years 1999, 1998 and 1997 differs
from the statutory federal income tax rate of 35% primarily due to state tax,
foreign tax, and tax credits as shown above, income and expenses from foreign
operations not subject to U.S. taxes (as discussed below).

The Company intends to reinvest the earnings of foreign operations except
to the extent the earnings are subject to current U.S. income taxes.
Accordingly, U.S. income taxes and foreign withholding taxes have not been
provided on a cumulative amount of unremitted earnings of foreign subsidiaries
of approximately $195 million and $158 million at December 31, 1999 and 1998.
The additional U.S. income tax and foreign withholding tax on the unremitted
foreign earnings, if repatriated, would be offset in whole or in part by foreign
tax credits. Thus, it is not practicable to estimate the amount of tax that
might be payable.

NOTE 10 -- BENEFIT PLANS AND OTHER POSTRETIREMENT BENEFITS

PENSION BENEFITS

The Company participates in NSP's noncontributory, defined benefit pension
plan that covers substantially all employees, other then those employed as a
result of the NE Generating asset acquisitions. Benefits are based on a
combination of years of service, the employee's highest average pay for 48
consecutive months, and Social Security benefits. Plan assets principally
consist of the common stock of public companies, corporate bonds and U.S.
government securities. The Company's net annual periodic pension cost includes
the following components:

COMPONENTS OF NET PERIODIC BENEFIT COST

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Service cost benefits earned................................ $ 1,127 $ 1,303 $ 1,602
Interest cost on benefit obligation......................... 1,187 1,417 1,739
Expected return on plan assets.............................. (1,029) (2,226) (2,866)
Amortization of prior service cost.......................... 5 172 393
Recognized actuarial (gain) loss............................ (3) (1,878) (2,053)
------- ------- -------
Net periodic (benefit) cost............................... $ 1,287 $(1,212) $(1,185)
======= ======= =======
</TABLE>

The Company discontinued funding its pension costs in 1998 due to the
effects of funding limitations from employee benefit and tax laws on NSP's plan.
Plan assets consist principally of common stock of

F-19
<PAGE> 117

public companies, corporate bonds and U.S. government securities. The funded
status of the pension plan in which the Company employees participate is as
follows at December 31:

RECONCILIATION OF FUNDED STATUS

<TABLE>
<CAPTION>
1998 1999
------------------------- --------------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Benefit obligation at Jan. 1................. $1,048,251 $17,410 $ 1,143,464 $ 20,112
Service cost................................. 31,643 1,303 36,421 1,602
Interest cost................................ 78,839 1,417 86,429 1,739
Plan amendments.............................. 102,315 3,045 184,255 2,214
Actuarial gain............................... (41,635) (2,278) (105,634) (178)
Benefit payments............................. (75,949) (785) (97,086) (1,200)
---------- ------- ----------- --------
Benefit obligation at Dec. 31.............. $1,143,464 $20,112 $ 1,247,849 $ 24,289
========== ======= =========== ========
Fair value of plan assets at Jan. 1.......... $1,978,538 $18,795 $ 2,221,819 39,079
Actual return on plan assets................. 319,230 21,069 293,904 9,199
Benefit payments............................. (75,949) (785) (97,086) (1,200)
---------- ------- ----------- --------
Fair value of plan assets at Dec. 31....... $2,221,819 $39,079 $ 2,418,637 $ 47,078
========== ======= =========== ========
Funded status at Dec. 31 -- excess of assets
over obligation............................ $1,078,355 $18,967 $ 1,170,788 $ 22,789
Unrecognized transition (asset) obligation... (387) -- (311) --
Unrecognized prior service cost.............. 114,305 2,954 277,350 4,775
Unrecognized net gain........................ (1,167,340) (22,486) (1,381,889) (26,944)
---------- ------- ----------- --------
Accrued (prepaid) benefit obligation at Dec.
31......................................... $ 24,933 $ (565) $ 65,938 $ 620
========== ======= =========== ========
</TABLE>

AMOUNT RECOGNIZED IN THE BALANCE SHEET

<TABLE>
<CAPTION>
1998 1999
----------------------- -----------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Prepaid benefit cost............................. $24,933 $ -- $65,938 $ 868
Accrued benefit liability........................ -- (565) -- (248)
------- ----- ------- -----
Net amount recognized -- asset
(liability)............................... $24,933 $(565) $65,938 $ 620
======= ===== ======= =====
</TABLE>

The weighted average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.5% for December 31, 1999
and 6.5% for December 31, 1998. The rate of increase in future compensation
levels used in determining the actuarial present value of the projected
obligation was 4.5% in 1999 and 4.5% in 1998. The assumed long-term rate of
return on assets used for cost determinations was 8.5% for 1999 and 1998 and
9.0% for 1997.

Effective Jan. 1, 1998, NSP changed its method of accounting for subsidiary
pension costs under SFAS No. 87. The new method, which now allocates plan assets
based on subsidiary benefit obligations, was adopted to better match earnings on
total plan assets with the corresponding subsidiary benefit obligations. The
effect of this change decreased periodic pension costs by $2.9 million in 1998
from 1997 levels, including $1.3 million related to periods prior to the change.
The effects of this change have not been reported separately on the income
statement and prior periods have not been restated due to immateriality.

F-20
<PAGE> 118

NRG EQUITY PLAN

Employees are eligible to participate in the Company's Equity Plan (the
Plan). The Plan grants phantom equity units to employees based upon performance
and job grade. The Company's equity units are valued based upon the Company's
growth and financial performance. The primary financial measures used in
determining the equity units' value are revenue growth, return on investment and
cash flow from operations. The units are awarded to employees annually at the
respective year's calculated share price (grant price). The Plan provides
employees with a cash pay out for the unit's appreciation in value over the
vesting period. The Plan has a seven year vesting schedule with actual payments
beginning after the end of the third year and continuing at 20% each year for
the subsequent five years. During 1999 and 1998, the Company recorded
approximately $13 million and $2.6 million, respectively for the Plan. During
the three months ended March 31, 2000 and 1999, the Company recorded
approximately $3.6 million and $0.8 million, respectively for the Plan
(unaudited).

The Plan includes a change of control provision, which allow all shares to
vest if the ownership of the Company were to change.

POSTRETIREMENT HEALTH CARE

The Company participates in NSP's contributory health and welfare benefit
plan that provides health care and death benefits to substantially all employees
after their retirement. The plan, was terminated for nonbargaining employees
retiring after 1998 and for bargaining employees retiring after 1999. is
intended to provide for sharing of costs of retiree health care between the
Company and retirees. For covered retirees, the plan enables the Company to
share the cost of retiree health costs. Nonbargaining retirees pay 40 percent of
total health care costs. Cost-sharing for bargaining employees is governed by
the terms of the collective bargaining agreement.

Postretirement health care benefits for the Company are determined and
recorded under the provisions of SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." SFAS No. 106 requires the
actuarially determined obligation for postretirement health care and death
benefits to be fully accrued by the date employees attain full eligibility for
such benefits, which is generally when they reach retirement age.

The Company's net annual periodic benefit cost under SFAS No. 106 includes
the following components:

COMPONENTS OF NET PERIODIC BENEFIT COST

<TABLE>
<CAPTION>
1997 1998 1999
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Service cost benefits earned................................ $223 $165 $ 9
Interest cost on benefit obligation......................... 246 145 24
Amortization of transition asset............................ 70 17 --
Amortization of prior service cost.......................... -- (40) (104)
Recognized actuarial (gain) loss............................ -- 2 (34)
---- ---- -----
Net periodic (benefit) cost............................ $539 $289 $(105)
==== ==== =====
</TABLE>

Plan assets as of December 31, 1999 consisted of investments in equity
mutual funds and cash equivalents. The Company's funding policy is to contribute
to NSP benefits actually paid under the plan.

F-21
<PAGE> 119

The following table sets forth the funded status of the health care plan in
which the Company employees participate at December 31:

RECONCILIATION OF FUNDED STATUS

<TABLE>
<CAPTION>
1998 1999
------------------------ ------------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Benefit obligation at Jan. 1................... $ 279,230 $ 3,893 $ 219,762 $ 1,517
Service cost................................... 3,247 165 196 9
Interest cost.................................. 15,896 145 9,184 24
Plan amendments................................ (51,456) (1,872) (80,840) (770)
Actuarial gain loss............................ (9,732) (814) 8,269 (359)
Benefit payments............................... (17,423) -- (16,637) --
--------- ------- --------- -------
Benefit obligation at Dec. 31............. $ 219,762 $ 1,517 $ 139,934 $ 421
========= ======= ========= =======
Fair Value of plan assets at Jan. 1............ $ 19,783 $ -- $ 34,514 $ --
Actual return on plan assets................... 2,471 -- 3,982 --
Employer contributions......................... 29,683 -- 13,339 --
Benefit payments............................... (17,423) -- (16,637) --
--------- ------- --------- -------
Fair value of plan assets at Dec. 31...... $ 34,514 $ -- $ 35,198 $ --
========= ======= ========= =======
Funded status at Dec. 31 -- unfunded
obligation................................... $ 185,248 $ 1,517 $(104,736) $ (421)
Unrecognized transition obligation............. (104,482) -- 22,073 --
Unrecognized prior service cost................ 2,399 786 (2,926) (1,452)
Unrecognized net gain (loss)................... (3,790) 237 10,580 (562)
--------- ------- --------- -------
Accrued (liability) benefit recorded at Dec.
31........................................... $ 79,375 $ 2,540 $ (75,009) $(2,435)
========= ======= ========= =======
</TABLE>

The assumed health care cost trend rates used in measuring the accumulated
projected benefit obligation (APBO) at both December 31, 1999 and 1998, were
8.1% for those under age 65, and 6.1% for those over age 65. The assumed cost
trends are expected to decrease each year until they reach 5.0% for both age
groups in the year 2004, after which they are assumed to remain constant. A one
percent increase in the assumed health care cost trend rate would increase the
APBO by approximately $36 thousand as of December 31, 1999. Service and interest
cost components of the net periodic postretirement cost would increase by
approximately $2 thousand with a similar one percent increase in the assumed
health care cost trend rate. The assumed discount rate used in determining the
APBO was 6.5% for both December 31, 1999 and 1998, compounded annually. The
assumed long-term rate of return on assets used for cost determinations under
SFAS No. 106 was 8% for 1999, 1998 and 1997.

PENSION BENEFITS -- 1999 ACQUISITIONS

During 1999, the Company acquired several generating assets and assumed
benefit obligations for a number of employees associated with those
acquisitions. The plans assumed included noncontributory defined benefit pension
formulas, matched 401(k) savings plans, and contributory post-retirement welfare
plans. Approximately, 56% of the Company's benefit employees are represented by
eight local labor unions under collective bargaining agreements, which expire
between 2000 and 2003.

F-22
<PAGE> 120

The Company sponsors one noncontributory, defined benefit pension plan that
covers most of the employees associated with the 1999 acquisitions. Generally,
the benefits are based on a combination of years of service, the final average
pay and Social Security benefits.

COMPONENTS OF NET PERIODIC BENEFIT COST

<TABLE>
<CAPTION>
1999
----
(THOUSANDS OF DOLLARS)
<S> <C>
Service cost benefits earned................................ $ 968
Interest cost on benefit obligation......................... 1,115
Expected return on plan assets.............................. (1,193)
-------
Net periodic (benefit) cost............................ $ 890
=======
</TABLE>

RECONCILIATION OF FUNDED STATUS

<TABLE>
<CAPTION>
1999
----
(THOUSANDS OF DOLLARS)
<S> <C>
Benefit obligation at beginning of period................... $ 24,954
Additional Acquisitions during the Year..................... 27,330
Service cost................................................ 968
Interest cost............................................... 1,115
Plan amendments............................................. --
Actuarial gain.............................................. (1,098)
Benefit payments............................................ (403)
--------
Benefit obligation at Dec. 31.......................... $ 52,866
========
Fair value of plan assets at beginning of period............ $ 24,905
Additional assets transferred............................... 10,070
Actual return on plan assets................................ 3,091
Benefit payments............................................ (403)
--------
Fair value of plan assets at Dec. 31................... $ 37,663
========
Funded status at Dec. 31 -- excess of assets over
obligation................................................ $(15,203)
Unrecognized transition (asset) obligation.................. --
Unrecognized prior service cost............................. --
Unrecognized net gain....................................... (2,996)
--------
(Accrued) Prepaid benefit obligation at Dec. 31............. $(18,199)
========
</TABLE>

AMOUNT RECOGNIZED IN THE BALANCE SHEET

<TABLE>
<CAPTION>
1999
----------------------
(THOUSANDS OF DOLLARS)
<S> <C>
Prepaid benefit cost....................................... --
Accrued benefit liability.................................. $(18,199)
--------
Net amount recognized -- (liability)..................... $(18,199)
========
</TABLE>

The weighted average discount rate used in determining the actuarial
present value of the projected benefit obligation was 7.5% for December 31,
1999. The rate of increase in future compensation levels used in determining the
actuarial present value of the projected obligation was 4.5% for nonunion
employees and 3.50% for union employees. The assumed long-term rate of return on
assets used for cost determinations was 8.5% for 1999.

F-23
<PAGE> 121

POSTRETIREMENT HEALTH CARE

The Company has also assumed post retirement health care benefits for some
of the Company's employees associated with the 1999 acquisitions. The plan
enables the Company and the retirees to share the costs of retiree health care.
The cost sharing varies by acquisition group and collective bargaining
agreements. There are no existing Company retirees under these plans as of
December 31, 1999. Complete valuation data is not available for some of these
groups. The estimated net periodic postretirement benefit cost for 1999 is $0.85
million. The estimated accumulated post retirement benefit obligation is $12
million at December 31, 1999.

401(K) PLANS

The Company also assumed several contributory, defined contribution
employee savings plans as a result of its 1999 acquisition activity. These plans
comply with Section 401(k) of the Internal Revenue Code and cover substantially
all of the Company's employees who are not covered by NSP's 401(k) Plan. The
Company matches specified amounts of employee contributions to the plan.
Employer contributions made to the Company's plans were approximately $0.31
million in 1999.

NOTE 11 -- SALES TO SIGNIFICANT CUSTOMERS

During 1999, the Company's electric power generation operations located in
the northeastern part of the United States, NRG Northeastern Generating LLC,
accounted for approximately 60% of the Company's total revenues from wholly
owned operations. Sales to three customers accounted for 10.5%, 21.0% and 19.7%
of total revenues from wholly owned operations in 1999. During 1999, the Company
entered into transition agreements with these customers providing for the sale
of energy and other ancillary services generated from certain electric
generating facilities recently acquired from these customers and others. These
agreements generally range from four to ten years in duration.

The Company and the Ramsey/Washington Resource Recovery Project have a
service agreement for waste disposal, which expires in 2006. Approximately 26.5%
in 1998 of the Company's operating revenues were recognized under this contract.
In addition, sales to one thermal customer amounted to 10.3% of operating
revenues in 1998.

NOTE 12 -- FINANCIAL INSTRUMENTS

The estimated December 31 fair values of the Company's recorded financial
instruments are as follows:

<TABLE>
<CAPTION>
1998 1999
------------------- -----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Cash and cash equivalents.......................... $ 6,381 $ 6,381 $ 31,483 $ 31,483
Restricted cash.................................... 4,021 4,021 17,441 17,441
Notes receivable, including current portion........ 136,291 136,291 71,568 71,568
Long-term debt, including current portion.......... 502,476 519,418 1,971,860 1,931,969
</TABLE>

For cash, cash equivalents and restricted cash, the carrying amount
approximates fair value because of the short-term maturity of those instruments.
The fair value of notes receivable is based on expected future cash flows
discounted at market interest rates. The fair value of long-term debt is
estimated based on the quoted market prices for the same or similar issues.

DERIVATIVE FINANCIAL INSTRUMENTS

As of December 31, 1999, the Company had no contracts to hedge or protect
foreign currency denominated future cash flows. One contract that was executed
during 1999 had no material effect on earnings.

F-24
<PAGE> 122

During the third quarter of 1999, NRG Northeast, a wholly owned subsidiary
of the Company entered into $600 million of "treasury locks," at various
interest rates, which expired in February 2000. These treasury locks were an
interest rate hedge for an NRG Northeast bond offering that was completed on
February 22, 2000. The proceeds of this bond offering were used to pay down
borrowings under a NRG Northeast's existing short-term credit facility.

As of December 31, 1999, the Company had three interest rate swap
agreements with notional amounts totaling approximately $393 million. The
contracts are used to manage the Company's exposure to changes in interest
rates. If the swaps had been discontinued on December 31, 1999, the Company
would have owed the counterparties approximately $3 million. Management believes
that the Company's exposure to credit risk due to nonperformance by the
counterparties to its hedging contracts is insignificant, based on the
investment grade rating of the counterparties. As of March 31, 2000, the Company
had four interest rate swap agreements with notional amounts totaling
approximately $692 million. If the swaps had been discontinued on March 31,
2000, the Company could have owed the Counterparties approximately $2 million
(unaudited).

- In September 1999, the Company entered into a $200 million swap agreement
effectively converting the 7.5 percent fixed rate on its senior notes to
a variable rate based on the London Interbank Offered Rate. The swap
expires on June 1, 2009.

- A second swap effectively converts a $16 million issue of variable rate
debt into a fixed rate debt. The swap expires on September 30, 2002.

- A third swap converts $177 million of variable rate debt into fixed rate
debt. The swap expires on December 17, 2014.

- A fourth swap converts L188 million of non-recourse variable rate debt
into fixed rate debt. The swap expires on June 30, 2019 and is secured by
the Killingholme assets (unaudited).

The Company's Power Marketing subsidiary uses energy forward contracts
along with physical supply, to hedge market risk in the energy market. At
December 31, 1999, the notional amount of energy forward contracts was
approximately $207 million.

If the contracts had been terminated at December 31, 1999, the Company
would have received approximately $12.0 million based on price fluctuations to
date. Management believes the risk of counterparty nonperformance with regard to
any of the Company's hedging transactions is not significant.

NOTE 13 -- COMMITMENTS AND CONTINGENCIES

OPERATING LEASE COMMITMENTS

The Company leases certain of its facilities and equipment under operating
leases, some of which include escalation clauses, expiring on various dates
through 2010. Rental expense under these operating leases was $5.4 million in
1999 and $1.7 million in 1998. Future minimum lease commitments under these
leases for the years ending after December 31, 1999 are as follows:

<TABLE>
<CAPTION>
(THOUSANDS OF
DOLLARS)
-------------
<S> <C>
2000........................................................ $ 5,518
2001........................................................ 5,223
2002........................................................ 4,614
2003........................................................ 4,161
2004........................................................ 4,094
Thereafter.................................................. 35,293
-------
Total..................................................... $58,903
=======
</TABLE>

F-25
<PAGE> 123

CAPITAL COMMITMENTS

The Company expects to invest approximately $2.7 billion in 2000, for
nonregulated projects and property, including Cajun, Killingholme A and the
Conectiv fossil assets.

CAPITAL COMMITMENTS -- INTERNATIONAL

In November 1999, the Company agreed to purchase the 665 MW Killingholme A
station from National Power plc. Killingholme A was commissioned in 1994 and is
a combined-cycle, gas-turbine power station located in England. The purchase
price for the station will be approximately 410 million pounds sterling
(approximately $662 million U.S. at end of year exchange rates), subject to
commercial adjustments. The purchase price includes L20 million sterling
(approximately $32 million U.S. at end of year exchange rates) that is
contingent upon the successful completion of negotiations regarding NRG's
purchase of National Power's Blyth generating facilities. The Blyth assets
consist of two coal-fired stations totaling 1,140 MW of generation capacity
located in England.

CAPITAL COMMITMENTS -- DOMESTIC

The Company, together with its partner and the creditors's committee filed
a plan with the United States Bankruptcy Court for the Middle District of
Louisiana to acquire 1,708 MW of fossil generating assets from Cajun Electric
Power Cooperative of Baton Rouge, Louisiana (Cajun) for approximately $1.0
billion The consortium has the support of the Chapter 11 trustee and Cajun's
secured creditors. During the third quarter of 1999, the U.S. Bankruptcy Judge
confirmed the creditors plan of reorganization and the Company exercised an
option to purchase its partner's 50% interest in the project. The Company
expects to close the acquisition of the Cajun assets during the first quarter of
2000.

In January 2000, the Company agreed to purchase 1,875 MW of fossil-fueled
electric generating capacity and other assets from Conectiv of Wilmington,
Delaware for $800 million. The fossil-fueled generating facilities consist of
Conectiv's wholly owned BL England, Deepwater, Indian River and Vienna steam
stations plus Conectiv's interest in the Conemaugh and Keystone steam stations.
Other assets in the purchase are the 241-acre Dorchester site located in
Dorchester County, Maryland, certain Merrill Creek Reservoir entitlements in
Harmony Township, New Jersey and certain excess emission allowances.

In January 2000, the Company executed a memorandum of understanding with GE
Power Systems, a division of General Electric Company, to purchase 11 gas
turbine generators and five steam turbine generators. The purchase will take
place over the next five years and is valued at approximately $500 million with
an option to purchase additional units. The 16 turbines have an equivalent
generation output of 3,000 MW and will be installed at the Company's existing
North American plant sites.

In March 2000, the Company entered into an agreement with Great River
Energy under which Great River assigned to the Company all of its rights and
obligations with respect to two 135 MW turbines being built for it by Siemens
Westinghouse. Our total cost for the turbines, which are scheduled for delivery
in the first or second quarter of 2001, will be $43 million. The Company expects
to install these turbines at either existing plant sites in the United States or
new greenfield sites (unaudited).

In April 2000, the Company announced an agreement with Statoil Energy, Inc.
to acquire Harrisburg Steam Works and Statoil Energy Power/Paxton L.P. (Statoil)
located in Harrisburg, Pennsylvania for approximately $11 million. Harrisburg
Steam Works provides steam to more than 300 residential, commercial and
industrial customers, including the City of Harrisburg and the Commonwealth of
Pennsylvania. Statoil is a cogeneration facility capable of supplying nearly 30%
of the steam requirements for Harrisburg Steam Works and a chiller plant that
serves the Harrisburg hospital. Statoil also operates a nationwide diesel engine
service business (unaudited).

The Company has contractually agreed to the monetization of certain tax
credits generated from landfill gas sales through the year 2007.

F-26
<PAGE> 124

SOURCE OF CAPITAL

The Company anticipates funding its ongoing capital commitments through the
issuance of debt, additional equity from NSP, and operating cash flows. In
addition, the Company may issue a limited amount of equity financing to third
parties for funding a portion of the capital requirements.

CONTINGENT REVENUES

During 1999, the first year of deregulation in the state of New York power
industry, the Company has claims related to certain revenues earned during the
period April 27, 1999 to December 31, 1999. The Company is actively pursuing
resolution and/or collection of these amounts, which totaled approximately $8.9
million as of December 31, 1999. These amounts have not been recorded in the
financial statements and will not be recognized as income until disputes are
resolved and collection is assured. The contingent revenues relate to
interpretation of certain transition power sales agreements and to sales to the
NYPP and NEPOOL, conflicting meter readings, pricing of firm sales and other
power pool reporting issues.

RETROACTIVE MARKET CAP (UNAUDITED)

On March 30, 2000 the Company received notification from the New York
Independent System Operator (NYISO) of their petition to the Federal Energy
Regulatory Commission (FERC) to place a $2.52 per megawatt hour market cap on
ancillary service revenues. The NYISO also requested authority to impose this
cap on a retroactive basis to March 1, 2000.

Noting that FERC orders have not, to date, adjusted rates retroactively to
address market operations or market power concerns, in the context of an ISO or
otherwise, our internal legal counsel have no reason to believe that NRG will
not ultimately collect all of the amounts due from the NYISO for ancillary
services provided in March 2000.

If the FERC authorizes the NYISO to impose the market cap on a retroactive
basis, the Company would record a $8.2 million pretax reduction in earnings.

CONTRACTUAL COMMITMENTS

Arthur Kill Power and Astoria Power have entered into agreements with ConEd
that obligate them to maintain the electric generating capability and
availability of their respective facilities at specified levels for the terms of
these agreements, and whereby during certain periods, ConEd will purchase
specified amounts of capacity, as long as the capacity is counted in the
installed capacity requirement for New York City. The capacity must satisfy all
criteria, standards and requirements applicable to providers of installed
capacity established by the New York State Reliability Counsel ("NYSRC"), the
Northwest Power Coordinating Council ("NPCC"), the North American Electric
Reliability Council ("NERC"), the New York Power Pool (NYPP) or the NYISO.
Should the capacity of the facility drop below the minimum level required, the
subsidiary owning the facility will pay to ConEd a deficiency charge. The
sellers may use electric capacity other than that generated by their own plants
to satisfy ConEd's demands.

The respective subsidiary will bill ConEd for the electricity capacity sold
and ConEd will bill that subsidiary for any capacity deficiency payments on a
monthly basis. Any amount unpaid after it is due will accrue interest. Any
dispute on the amount payable will first be settled by good faith negotiation
among the parties.

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<PAGE> 125

For the next four years, the Company estimates that a significant portion
of the total revenues from the Dunkirk and Huntley facilities will be derived
from four-year transition contracts for capacity and energy. All forward
capacity is sold to NIMO during the transition period, with the remainder of
energy sold to the NYISO. Each of the following agreements was executed on June
11, 1999 and extends for a term of four years.

To hedge its transition to market rates, NIMO has required NRG Power
Marketing to enter into an International Swap Dealers Association (ISDA) Master
Agreement (together with the Schedule, the Confirmation and the Guarantee
Agreement, the "Swap Agreement"). Under the Swap Agreement, NIMO will pay to NRG
Power Marketing a fixed monthly price for the Dunkirk (units 1, 2, 3 and 4) and
Huntley (units 67 and 68 only) facilities' capacity and ancillary services and
NRG Power Marketing will pay to NIMO the market rates for the related capacity
and ancillary services. The swap is only a financial contract and it
incorporates the terms of the ISDA Master Agreement.

NIMO will have the right from time to time to exercise a call option for an
additional swap pursuant to which, within a certain limit consistent with
outages and availability requirements, NIMO will nominate certain amounts of
energy from the Dunkirk and Huntley facilities and will pay to NRG Power
Marketing an amount for such energy determined in accordance with the heat rate
curve representing the nominated unit. NRG Power Marketing will pay to NIMO the
market rates for such energy at the time that the energy was nominated. However,
NRG Power Marketing may refuse the call option for either of the facilities if a
facility is unexpectedly forced off-line or derated sufficiently to be unable to
fulfill the portion of the specified quantity of power in the option. Any such
refusal of the call option will be limited to the Decline Quantity Cap, which is
calculated based upon the capacity of the relevant facility for the prior six
months. NIMO will be entitled to make up for any refused call option in the
future by delivering reasonable notice to NRG Power Marketing.

In addition to the Swap Agreement, Huntley Power has entered into an
agreement with NIMO that gives NIMO the option to purchase from the Huntley
facility certain quantities of electricity generated by Huntley units 65 and 66,
during the summer and winter months, up to a specified maximum limit for the
term of this agreement. If Huntley Power is selling the electrical output
generated by units 65 and 66 to a third party, Huntley Power may refuse to
deliver such output to NIMO. Furthermore, if unit 65 or 66 is generating for
NIMO, Huntley Power has the right to "recall" the unit(s) in order to facilitate
a sale to a third party. If Huntley Power fails to meet NIMO's quantity request
for electricity output, it will compensate NIMO. NIMO will pay Huntley Power
according to the amount of electricity output delivered to NIMO, on a monthly
basis. Control and title pass at the point of delivery of the energy and each
party agrees to indemnify the other against any claims arising out of any act or
incident occurring during the period when control and title of the electricity
is vested in the indemnifying party.

Huntley Power has also entered into an agreement with NIMO that gives NIMO
the option to purchase from Huntley Power certain quantities of electricity
generated by Huntley units 67 or 68 (during peak and off-peak summer hours),
within a specified range of MW per hour, not to exceed 189 MW for any one hour
during the peak hours, for the term of the agreement. If Huntley Power fails to
meet NIMO's quantity request for electricity, Huntley Power will compensate NIMO
for quantities not provided. NIMO will pay Huntley Power according to the amount
of power delivered to NIMO, on a monthly basis. Control and title passes at the
point of delivery of the energy and each party shall indemnify the other party
from any claims arising out of any act or incident occurring during the period
when control and title of the electricity is vested in the indemnifying party.

Oswego Power has entered into a four-year transition power sales contract
with NIMO in order to hedge its transition to market rates. Under the agreement,
NIMO will pay to Oswego Power a fixed monthly price plus start up fees for the
right, but not the obligation, to claim, at a specified delivery point or
points, the installed capacity of unit 5 of the Oswego facility, and for the
right to exercise, at a specified price, an option for an additional 350 MW of
installed capacity. The total amount of energy which Oswego Power must supply
under the call option is limited to a nominal amount of energy per year. Oswego
Power may refuse such option if the facility is unexpectedly unavailable or
derated sufficiently to be unable to fulfill the option, as long as Oswego Power
uses "good utility practice" to maintain the power stations.

F-28
<PAGE> 126

Oswego Power may also choose to supply the energy required from another source
as long as adjustment is made for any difference in value between the agreed
upon delivery point and the actual point of delivery. In the event that Oswego
Power is unable to provide from its own sources installed capacity of unit 5 in
the amount claimed by NIMO, Oswego Power must procure the capacity from the
market and provide it to NIMO at no additional cost or else suffer a penalty.

NRG Power Marketing has entered into a Wholesale Standard Offer Service
Agreement, dated October 13, 1998 and amended as of January 15, 1999 (the "WSO
Agreement"), with Blackstone Valley Electric Company, Eastern Edison Company,
and Newport Electric Corporation (collectively the "EUA Companies"), which
obligates NRG Power Marketing to provide each of the EUA Companies with firm
all-requirements electric service, including capacity, energy, reserves, losses
and related services necessary to serve a specified share of the EUA Companies'
aggregate load attributable to retail customers taking standard offer service.
NRG Power Marketing assumes all expenses, liabilities and losses, regulatory or
economical, related to such service. NRG Power Marketing may supply the power to
the EUA Companies at any point on the New England Power Pool transmission
facilities system or on the EUA Companies' system.

The price for each unit of electricity is a combination of a fixed price
plus a fuel adjustment factor. The EUA Companies will calculate the estimated
power supplied each month and pay to NRG Power Marketing the price for such
electricity before the end of the next month. Any amounts unpaid by the due date
will accrue interest. The EUA Companies may make retroactive adjustments to the
bills for up to one year after the date of the original billing. NRG Power
Marketing must meet certain creditworthiness criteria for the term of the
agreement, or must provide a guaranty from an entity which meets the
creditworthiness criteria. The term extends from April 26, 1999, the closing
date of the asset purchase agreement until December 31, 2009. The agreement may
also be terminated in the case of an event of default or if the facility's
electric service requirement is less than 1 MW/hr for two consecutive months.

In 1999, the Company entered into a Standard Offer Service Wholesale Sales
Agreement with CL&P. The Company will supply CL&P with 35 percent of its
standard offer service load during 2000, 40 percent during 2001 and 2002, and 45
percent during 2003. The four year contract is valued at $1.7 billion. The
Company will serve the load with a combination of existing generation and power
purchases.

ENVIRONMENTAL REGULATIONS

Environmental controls at the federal, state, regional and local levels
have a substantial impact on the Company's operations due to the cost of
installation and operation of equipment required for compliance.

AIR

On October 12, 1999, the Company received a letter from the Office of the
Attorney General of the State of New York speculating that based on a
preliminary analysis, it believes that significant modifications were made to
the Huntley and Dunkirk facilities during NIMO's ownership of these facilities
without obtaining Prevention of Significant Deterioration (PSD) and/or New
Source Review (NSR) permits. The letter requested documents related to historic
maintenance, repair, and replacement work at the facilities, as well as other
data related to operations and emissions from these facilities. On January 12,
2000, the Company received a formal request from the New York Department of
Environmental Conservation (NYDEC) seeking essentially the same documents
covered by the Attorney General's letter. The Company understands that the NYDEC
request supercedes the Attorney General's request. Although the Company does not
have knowledge that NIMO failed to comply with the preconstruction permit
requirements at the Huntley and Dunkirk facilities, the Company has only
recently initiated steps to investigate more fully allegations to the contrary.
If it is determined that these facilities did not comply with the PSD or NSR
permit programs, the Company could be required among other things, to install
pollution control technology to further control the emissions of nitrogen oxide
(NO(X)) and sulfur dioxide (SO(2)) from the Huntley and Dunkirk facilities. By
virtue of conditions imposed under the

F-29
<PAGE> 127

asset sale agreement between the Company and NIMO (the Company's rights and
obligations under the asset sale agreement were substantially assigned to
Huntley Power LLC and Dunkirk Power LLC), NIMO remains responsible for "any
fines, penalties and assessments imposed by a governmental entity with respect
to violation or alleged violation of Environmental Law which occurred prior to
the Closing Date." Even so, the Company could become subject to fines and/or
penalties associated with the period of time it has operated the facilities.

On October 14, 1999, Governor Pataki of New York directed the Commissioner
of the NYDEC to require further reductions of SO(2) emissions and NO(X)
emissions from New York power plants, beyond that which is required under
current federal and state law. Under Governor Pataki's directive NO(X) emissions
during the "non-ozone" season would be reduced to levels consistent with those
currently mandated for the "ozone" season under the Ozone Transport Commission's
Memorandum of Understanding. This additional reduction requirement would be
phased in between January 1, 2003 and January 2, 2007. In addition, Governor
Pataki announced that he is ordering a reduction of SO(2) emissions by 50%
beyond the requirements of the Federal Acid Rain Program. These reductions would
also be phased in between January 1, 2003 and January 1, 2007. Compliance with
these emission reduction requirements, if they become effective, could have a
material impact on the operation of the Company's facilities located in the
State of New York.

On November 3, 1999, in the southern and mid-western regions of the United
States, the United States Department of Justice (DOJ) filed suit against seven
electric utilities for alleged violations of the Federal Clean Air Act (the
Clean Air Act) NSR and PSD permit requirements at seventeen utility generating
stations located in the southern and mid-western regions of the United States.
In addition, the United States Environmental Protection Agency (U.S. EPA) issued
administrative notices of violation alleging similar violations at eight other
power plants owned by certain of the electric utilities named as defendants in
the DOJ lawsuit, and also issued an administrative order to the Tennessee Valley
Authority for similar violations at seven of its power plants. The DOJ lawsuit
alleges that the defendants, over a period of twenty years, undertook
modifications at their generating stations that resulted in increased air
emissions without complying with stringent regulatory requirements governing
such modifications. Subsequent to the DOJ lawsuit, New York, Connecticut and New
Jersey have brought their own lawsuits against American Electric Power, an Ohio
based utility holding company, and have sought to intervene in the DOJ lawsuit.
To date, no lawsuits or administrative actions have been brought against the
Company or the former owners of the facilities alleging violations of the NSR or
PSD requirements, although Atlantic City Electric Company has received
information requests from the EPA regarding the Deepwater and B.L. England
facilities. However, there is a likelihood that future lawsuits alleging similar
violations may be filed against additional electric utility generating stations.
The Company can provide no assurance that lawsuits or administrative actions
alleging violations of PSD and NSR requirements will not be filed in the future.

The State of Connecticut has in the past considered, but rejected,
legislation that would require older electrical generating stations to comply
with more stringent pollution standards for NO(X) and SO(2) emissions.
Currently, legislation is being debated in the Connecticut legislature that
could require the Company's Connecticut facilities to rely on more expensive
fuels or install additional air pollution control equipment. If such legislation
were to become law without reflecting the benefit of critical elements of
current federal emission reduction initiatives, such as market based emission
trading between sources located across broad geographic regions, the Company's
Connecticut facilities may be placed at a significant competitive disadvantage.

SITE CONTAMINATION/REMEDIATION

With the acquisition of the NRG Northeast assets, the Company assumed
certain liabilities for existing environmental conditions at the sites with the
exception of off-site liabilities associated with the disposal of hazardous
materials and certain other environmental liabilities. The Company has not
assumed responsibility for any contamination resulting from the September 7,
1998 explosion and subsequent fire involving a transformer containing PCBs at
the Arthur Kill Station. The transformer explosion, fire and
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<PAGE> 128

subsequent oil spill resulted in the release of PCB's to the environment.
Consolidated Edison Company of New York, Inc. maintains responsibility for the
remediation of the PCB and other contamination associated with this event.

Environmental site assessments have been prepared for all of the recently
acquired NRG Northeast assets. The remediation activities at the Arthur Kill,
Astoria Gas Turbine and Somerset facilities are still in the study phase. As
such, the remediation cost estimates are based on approaches that have not been
approved yet by the regulatory agencies involved. Data from additional
investigations performed at the Astoria Gas Turbines and the approach being
taken at the Somerset Station may result in less costly remediation efforts than
originally estimated.

For the Connecticut facilities, the Company is planning to conduct
additional studies to better quantify remedial need. Such studies include the
preparation of risk assessments to justify remedial actions proposed by the
Company to the Connecticut Department of Environmental Protection and U.S. EPA.

COSTS

The Company has recorded approximately $5.8 million for expected
environmental costs related to site remediation issues at the Arthur Kill,
Astoria facilities and Somerset facilities. These amounts are based on the
environmental assessments for these sites.

The Company has budgeted approximately $44 million for capital expenditures
between 2000 and 2004 for environmental compliance, which includes the above
remedial investigations, the installation of NO(X) control technology at the
Somerset facility, intake screens at the Dunkirk facility, the resolution of
consent orders for remediation at the Arthur Kill and Astoria facilities and the
resolution of a consent order for water intake at the Arthur Kill facility.

CLAIMS AND LITIGATION

On or about July 12, 1999, Fortistar Capital Inc., a Delaware Corporation
(Fortistar), filed a complaint in District Court (Fourth Judicial District,
Hennepin County) in Minnesota against the Company, asserting claims for
injunctive relief and for damages as a result of the Company's alleged breach of
a confidentiality letter agreement with Fortistar relating to the Oswego
facility (Letter Agreement).

The Company disputes Fortistar's allegations and has asserted numerous
counterclaims.

A temporary injunction hearing was held on September 27, 1999. The
acquisition of the Oswego facility was closed on October 22, 1999, following
notification to the Court of Oswego Power's intention to close on that date. On
January 14, 2000, the court denied Fortistar's request for a temporary
injunction. The Company intends to continue to vigorously defend the suit and
believes Fortistar's complaint to be without merit. No trial date has been set.

The Company is involved in various other litigation matters. The Company is
actively defending these matters and does not feel the outcome of such matters
would materially impact the Company's results of operations.

NOTE 14 -- SEGMENT REPORTING

The Company conducts its business within three segments: Independent Power
Generation, Alternative Energy (Resource Recovery and Landfill Gas) and Thermal
projects. These segments are distinct components of the Company with separate
operating results and management structures in place.

F-31
<PAGE> 129

The "Other" category includes operations that do not meet the threshold for
separate disclosure and corporate charges that have not been allocated to the
operating segments.

<TABLE>
<CAPTION>
INDEPENDENT
POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
----------- ----------- ------- ----- -----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
MARCH 31, 2000 (UNAUDITED)
OPERATING REVENUES
Revenues from wholly-owned operations............. $300,063 $ 7,017 $21,575 $ 3,716 $332,371
Intersegment Revenues............................. -- 300 -- -- 300
Equity in earnings of unconsolidated affiliates... (7,151) (2,498) 5 -- (9,644)
-------- -------- ------- -------- --------
Total operating revenues................... 292,912 4,819 21,580 3,716 323,027
-------- -------- ------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations................... 194,375 6,795 12,232 1,521 214,923
Depreciation and amortization..................... 15,300 1,710 2,865 112 19,987
General, administrative, and development.......... 21,908 1,573 973 726 25,180
-------- -------- ------- -------- --------
Total operating costs and expenses......... 231,583 10,078 16,070 2,359 260,090
-------- -------- ------- -------- --------
OPERATING INCOME (LOSS)............................. 61,329 (5,259) 5,510 1,357 62,937
-------- -------- ------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
subs............................................ (1,798) -- -- -- (1,798)
Other income, net................................. 1,597 836 16 (918) 1,531
Interest expense.................................. (29,797) (653) (2,105) (19,762) (52,317)
-------- -------- ------- -------- --------
Total other income (expense)............... (29,998) 183 (2,089) (20,680) (52,584)
-------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES................... 31,331 (5,076) 3,421 (19,323) 10,353
INCOME TAX (BENEFIT)................................ 5,651 (8,449) 1,418 2,987 1,607
-------- -------- ------- -------- --------
NET INCOME (LOSS)................................... $ 25,680 $ 3,373 $ 2,003 $(22,310) $ 8,746
MARCH 31, 1999 (UNAUDITED)
OPERATING REVENUES
Revenues from wholly-owned operations............. $ 13,064 $ 6,280 $15,145 $ 3,034 $ 37,523
Intersegment revenues............................. -- 324 -- -- 324
Equity in earnings of unconsolidated affiliates... 7,830 249 1,162 (574) 8,667
-------- -------- ------- -------- --------
Total operating revenues................... 20,894 6,853 16,307 2,460 46,514
-------- -------- ------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations................... 13,207 5,174 7,572 1,987 27,940
Depreciation and amortization..................... 651 1,601 2,373 109 4,734
General, administrative, and development.......... 12,737 1,399 688 1,161 15,985
-------- -------- ------- -------- --------
Total operating costs and expenses......... 26,595 8,174 10,633 3,257 48,659
-------- -------- ------- -------- --------
OPERATING INCOME (LOSS)............................. (5,701) (1,321) 5,674 (797) (2,145)
-------- -------- ------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
subs............................................ (464) -- -- -- (464)
Other income, net................................. 1,512 290 9 (1,077) 734
Interest expense.................................. (6,722) (488) (1,784) (2,065) (11,059)
-------- -------- ------- -------- --------
Total other income (expense)............... (5,674) (198) (1,775) (3,142) (10,789)
-------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES................... (11,375) (1,519) 3,899 (3,939) (12,934)
INCOME TAX (BENEFIT)................................ (12,324) (5,032) 1,736 3,626 (11,994)
-------- -------- ------- -------- --------
NET INCOME (LOSS)................................... $ 949 $ 3,513 $ 2,163 $ (7,565) $ (940)
</TABLE>

F-32
<PAGE> 130

<TABLE>
<CAPTION>
INDEPENDENT
POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
----------- ----------- ------- ----- -----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
1999
OPERATING REVENUES
Revenues from wholly-owned operations(a).......... $322,943 $ 26,934 $76,277 $ 5,401 $431,555
Intersegment revenues............................. -- 963 -- -- 963
Equity in earnings of unconsolidated
affiliates(b)................................... 69,686 (2,205) 19 -- 67,500
-------- -------- ------- -------- --------
Total operating revenues................... 392,629 25,692 76,296 5,401 500,018
-------- -------- ------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations................... 207,081 24,977 42,401 (4,559) 269,900
Depreciation and amortization..................... 17,153 6,126 6,280 7,467 37,026
General, administrative, and development.......... 33,783 7,876 8,869 33,044 83,572
-------- -------- ------- -------- --------
Total operating costs and expenses......... 258,017 38,979 57,550 35,952 390,498
-------- -------- ------- -------- --------
OPERATING INCOME (LOSS)............................. 134,612 (13,287) 18,746 (30,551) 109,520
-------- -------- ------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
Subsidiary...................................... (2,322) -- (134) -- (2,456)
Write-off of investment........................... -- -- -- -- --
Gain on sale of interest in projects.............. -- -- -- 10,994 10,994
Other income, net................................. 2,328 (4,281) 10 8,375 6,432
Interest expense.................................. (25,918) 169 (8,152) (59,475) (93,376)
-------- -------- ------- -------- --------
Total other income (expense)............... (25,912) (4,112) (8,276) (40,106) (78,406)
-------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES................... 108,700 (17,399) 10,470 (70,657) 31,114
INCOME TAX (BENEFIT)................................ 8,812 (27,642) 3,963 (11,214) (26,081)
-------- -------- ------- -------- --------
NET INCOME (LOSS)................................... $ 99,888 $ 10,243 $ 6,507 $(59,443) $ 57,195
1998
OPERATING REVENUES
Revenues from wholly-owned operations(a).......... $ 8,185 $ 30,143 $52,699 $ 7,660 $ 98,687
Intersegment revenues............................. -- 1,737 -- -- 1,737
Equity in earnings of unconsolidated
affiliates(b)................................... 81,948 (1,314) 1,215 (143) 81,706
-------- -------- ------- -------- --------
Total operating revenues................... 90,133 30,566 53,914 7,517 182,130
-------- -------- ------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations................... 7,097 20,980 24,665 (329) 52,413
Depreciation and amortization..................... 980 5,590 9,258 492 16,320
General, administrative, and development.......... (7,099) 7,776 3,298 52,410 56,385
-------- -------- ------- -------- --------
Total operating costs and expenses......... 978 34,346 37,221 52,573 125,118
-------- -------- ------- -------- --------
OPERATING INCOME (LOSS)............................. 89,155 (3,780) 16,693 (45,056) 57,012
-------- -------- ------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
Subsidiary........................................ (2,251) -- -- -- (2,251)
Write-off of investment........................... (26,740) -- -- -- (26,740)
Gain on sale of interest in projects.............. 29,950 -- -- -- 29,950
Other income, net................................. 2,482 2,683 118 3,137 8,420
Interest expense.................................. (586) (1,921) (7,359) (40,447) (50,313)
-------- -------- ------- -------- --------
Total other income (expense)............... 2,855 762 (7,241) (37,310) (40,934)
-------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES................... 92,010 (3,018) 9,452 (82,366) 16,078
INCOME TAX (BENEFIT)................................ 18,605 (16,445) 2,852 (30,666) (25,654)
-------- -------- ------- -------- --------
NET INCOME (LOSS)................................... $ 73,405 $ 13,427 $ 6,600 $(51,700) $ 41,732
</TABLE>

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<PAGE> 131

- ---------------
(a) Revenues from wholly-owned operations are from external customers located in
the United States.

(b) The Company has significant equity investments for non-regulated projects
outside of the United States. Equity earnings of unconsolidated affiliates,
primarily independent power projects, includes $33.5 million in 1999, $29.3
million in 1998 and $27.1 million in 1997 from non-regulated projects
located outside of the United States. The Company's equity investments in
projects outside of the United States were $602.4 million in 1999, $591
million in 1998 and $517 million in 1997.

NOTE 15 -- SUBSEQUENT EVENT

On May 5, 2000 the Board of Directors approved a conversion of the 1,000
shares of common stock outstanding into 147,604,500 shares of Class A common
stock, par value $.01. In addition, the Company authorized a total of
250,000,000 shares of Class A common stock, par value $.01, 550,000,000 shares
of common stock, par value $.01, and 200,000,000 shares of preferred stock.
Class A common stock has identical rights to common stock except it has ten
votes per share. All share and per share data included in the financial
statements have been restated to reflect this exchange and reclassification.

F-34
<PAGE> 132

NRG ENERGY, INC.

INTRODUCTION TO PRO FORMA FINANCIAL STATEMENTS

On March 31, 2000, Louisiana Generating LLC (Louisiana Generating), a
wholly-owned subsidiary of NRG Energy, Inc. (NRG) completed the purchase of
1,708 megawatts (MW) of fossil fuel generating assets from Cajun Electric Power
Cooperative, Inc. (Cajun) for approximately $1.026 billion. The purchase price
was funded through an $800 million bond offering and an equity contribution from
NRG.

The Cajun assets consist of two plants near New Roads, Louisiana, a
two-unit, 220 MW gas-turbine generating station and a three-unit 1,488 MW coal
fired generating station.

Louisiana Generating was formed for the purpose of facilitating the
acquisition of the Cajun facilities and will own, operate and maintain the Cajun
facilities.

The purchase price of $1.026 billion has been preliminarily allocated to
tangible assets, identifiable assets and intangible assets of Louisiana
Generating based on estimates of their respective values and an initial review
of an appraisal recently completed. This appraisal needs to be carefully
evaluated and will most likely be adjusted for other valuations and studies
currently underway. These evaluations and studies will be completed over the
next several months and, as such, final values may differ substantially from
those shown.

The pro forma combined financial statements should be read in conjunction
with NRG's and the Cajun Electric (carve-out) historical financial statements.
The following pro forma income statement for the three months ended March 31,
2000 and the year ended December 31, 1999 presents the combination of NRG and
the Cajun Electric facilities as if the acquisition occurred on January 1, 2000
and January 1, 1999, respectively. The pro forma balance sheet presents the
combination of NRG and the Cajun Electric facilities as if the acquisition
occurred on December 31, 1999. The pro forma information presented is for
informational purposes only and is not necessarily indicative of future earnings
or financial position or of what the earnings and financial position would have
been had the acquisition of the Cajun Electric facilities been consummated at
the beginning of the respective periods or as of the date for which pro forma
financial information is presented.

F-35
<PAGE> 133

NRG ENERGY, INC.

PRO FORMA INCOME STATEMENT

THREE MONTHS ENDED MARCH 31, 2000

(THOUSANDS OF DOLLARS)

(UNAUDITED)

<TABLE>
<CAPTION>
CAJUN ELECTRIC PRO FORMA NRG
NRG (CAJUN ADJUSTMENTS ENERGY, INC.
ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA
------------ -------------- ----- ------ ------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned
operations......................... $332,671 $79,982 $ -- $ -- $412,653
Equity in earnings of unconsolidated
affiliates......................... (9,644) (9,644)
-------- ------- ------- ------- --------
Total operating revenues........... 323,027 79,982 -- -- 403,009
-------- ------- ------- ------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations....... 214,923 58,628 273,551
Depreciation and amortization......... 19,987 9,647 2,590(1) 27,044
General, administrative and
development........................ 25,180 2,423 27,603
-------- ------- ------- ------- --------
Total Operating costs and
expenses......................... 260,090 70,698 -- 2,590 328,198
-------- ------- ------- ------- --------
OPERATING INCOME........................ 62,937 9,284 -- 2,590 74,811
-------- ------- ------- ------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of
consolidated subsidiary............ (1,798) (1,798)
Other income, net..................... 1,531 521 2,052
Interest expense...................... (52,317) 18,312(2) (70,629)
-------- ------- ------- ------- --------
Total other expense................ (52,584) 521 18,312 -- (70,375)
-------- ------- ------- ------- --------
INCOME (LOSS) BEFORE INCOME TAXES....... 10,353 9,805 18,312 2,590 4,436
INCOME TAX EXPENSE (BENEFIT)............ 1,607 -- -- (2,448)(3) (841)
-------- ------- ------- ------- --------
NET INCOME (LOSS)....................... $ 8,746 $ 9,805 $18,312 $ 5,038 $ 5,277
======== ======= ======= ======= ========
</TABLE>

- ---------------

(1) Reflects lower net depreciation/amortization resulting from assets and
capitalized costs being depreciated over a longer estimated useful life
based on engineering studies.

(2) Reflects accrued interest on $800 million principal amount for 3 months at a
rate of 9.156% per annum.

(3) Incremental tax expense (benefit) is shown based on a rate of 41.37%.

F-36
<PAGE> 134

NRG ENERGY, INC.

PRO FORMA BALANCE SHEET
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
(UNAUDITED)

<TABLE>
<CAPTION>
CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG
NRG (CAJUN ------------------------ ENERGY, INC.
ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA
------------ -------------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents...... $ 31,483 $ -- $ -- $ -- $ 31,483
Restricted cash................ 17,441 17,441
Accounts receivable-trade, less
allowance for doubtful
accounts of $186............ 126,376 33,842 160,218
Accounts
receivable-affiliates....... -- --
Taxes receivable............... -- --
Current portion of notes
receivable-affiliates....... 287 287
Current portion of notes
receivable.................. -- --
Inventory...................... 119,181 34,234 153,415
Prepayments and other current
assets...................... 29,202 1,600 30,802
---------- ---------- ---------- ---------- ----------
Total current assets........ 323,970 69,676 -- -- 393,646
---------- ---------- ---------- ---------- ----------
PROPERTY PLANT AND EQUIPMENT, AT
ORIGINAL COST
In service..................... 2,078,804 1,208,832 451,647(A) 3,739,283
Under construction............. 53,448 3,996 57,444
---------- ---------- ---------- ---------- ----------
Total property, plant and
equipment................. 2,132,252 1,212,828 451,647 -- 3,796,727
Less accumulated
depreciation................ (156,849) (632,899) (789,748)
---------- ---------- ---------- ---------- ----------
Net property, plant and
equipment................. 1,975,403 579,929 451,647 -- 3,006,979
---------- ---------- ---------- ---------- ----------
OTHER ASSETS
Investments in projects........ 932,591 932,591
Capitalized project costs...... 2,592 2,592
Notes receivable, less current
portion-affiliates.......... 65,494 65,494
Notes receivable, less current
portion..................... 5,787 5,787
Intangible assets, net of
accumulated amortization of
$4,308...................... 55,586 55,586
Debt issuance costs, net of
accumulated amortization of
$6,640...................... 20,081 20,081
Other assets, net of
accumulated amortization of
$8,909...................... 50,180 4,188 54,368
---------- ---------- ---------- ---------- ----------
Total other assets.......... 1,132,311 4,188 -- -- 1,136,499
---------- ---------- ---------- ---------- ----------
TOTAL ASSETS..................... $3,431,684 $ 653,793 $ 451,647 $ -- $4,537,124
========== ========== ========== ========== ==========
</TABLE>

F-37
<PAGE> 135

<TABLE>
<CAPTION>
CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG
NRG (CAJUN ------------------------ ENERGY, INC.
ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA
------------ -------------- ---------- ---------- ------------
<S> <C> <C> <C> <C> <C>
LIABILITIES AND STOCKHOLDER'S
EQUITY
CURRENT LIABILITIES
Current portion of project
level long-term debt........ $ 30,462 $ -- $ -- $ -- $ 30,462
Revolving line of credit and
other short term debt....... 340,000 288,000(D) 628,000
Consolidated project level, non
recourse debt............... 35,766 35,766
Accounts payable-trade......... 61,211 4,806 66,017
Accounts payable-affiliate..... 6,404 6,404
Accrued income taxes........... 4,730 4,730
Accrued property and sales
taxes....................... 4,998 150 5,148
Accrued salaries, benefits and
related costs............... 9,648 9,648
Accrued interest............... 13,479 13,479
Other current liabilities...... 17,657 8,966 26,623
---------- ---------- ---------- ---------- ----------
Total current liabilities... 524,355 13,922 -- 288,000 826,277
OTHER LIABILITIES
Minority Interest.............. 14,373 14,373
Consolidated project level,
long-term, non recourse
debt........................ 1,026,398 800,000(B) 1,826,398
Corporate level long-term debt,
less current portion........ 915,000 915,000
Deferred income taxes.......... 16,940 16,940
Deferred investment tax
credits..................... 1,088 1,088
Postretirement and other
benefit obligations......... 24,613 24,613
Other long-term obligations and
deferred income............. 15,263 3,518 18,781
---------- ---------- ---------- ---------- ----------
Total liabilities.............. 2,538,030 17,440 -- 1,088,000 3,643,470
---------- ---------- ---------- ---------- ----------
STOCKHOLDER'S EQUITY
Class A common stock; $.01 par
value; 250,000 shares
authorized; 147,605 shares
issued and outstanding...... 1,476 1,476
Additional paid-in capital..... 780,438 636,353 636,353(C) 780,438
Retained earnings.............. 187,210 187,210
Accumulated other comprehensive
income...................... (75,470) (75,470)
---------- ---------- ---------- ---------- ----------
Total Stockholder's
equity.................... 893,654 636,353 636,353 -- 893,654
---------- ---------- ---------- ---------- ----------
TOTAL LIABILITIES AND
STOCKHOLDER'S EQUITY........... $3,431,684 653,793 $ 636,353 $1,088,000 $4,537,124
========== ========== ========== ========== ==========
</TABLE>

FOOTNOTES

(A) Reflects increase in overall fixed asset balances resulting from purchase
accounting adjustments net of depreciation expense.

(B) Reflects $800 million debt from issuance of bonds.

(D) Reflects short-term borrowings used to fund the acquisition of the Cajun
facilities.

F-38
<PAGE> 136

NRG ENERGY, INC.

PRO FORMA INCOME STATEMENT
DECEMBER 31, 1999
(THOUSANDS OF DOLLARS)
(UNAUDITED)

<TABLE>
<CAPTION>
CAJUN ELECTRIC PRO FORMA ADJUSTMENTS NRG
NRG (CAJUN ---------------------- ENERGY, INC.
ENERGY, INC. FACILITIES) DEBIT CREDIT PRO FORMA
------------ -------------- --------- --------- ------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned
operations........................ $432,518 $368,562 $ -- $ -- $ 801,080
Equity in earnings of unconsolidated
affiliates........................ 67,500 67,500
-------- -------- ------- ------- ---------
Total operating revenues.......... 500,018 368,562 -- -- 868,580
-------- -------- ------- ------- ---------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations...... 269,900 244,044 513,944
Depreciation and amortization........ 37,026 37,930 10,361(1) 64,595
General, administrative and
development....................... 83,572 16,804 100,376
-------- -------- ------- ------- ---------
Total Operating costs and
expenses........................ 390,498 298,778 -- 10,361 678,915
-------- -------- ------- ------- ---------
OPERATING INCOME....................... 109,520 69,784 -- 10,361 189,665
-------- -------- ------- ------- ---------
OTHER INCOME (EXPENSE)
Minority interest in earnings of
consolidated subsidiary........... (2,456) (2,456)
Gain on sale of interest in
projects.......................... 10,994 10,994
Write-off of project investments..... -- (2,878) (2,878)
Other income, net.................... 6,432 1,008 7,440
Interest expense..................... (93,376) 73,248(2) (166,624)
-------- -------- ------- ------- ---------
Total other expense............... (78,406) (1,870) 73,248 -- (153,524)
-------- -------- ------- ------- ---------
INCOME (LOSS) BEFORE INCOME TAXES...... 31,114 67,914 73,248 10,361 36,141
INCOME TAX (BENEFIT) EXPENSE........... (26,081) -- 2,080(3) (24,001)
-------- -------- ------- ------- ---------
NET INCOME............................. $ 57,195 $ 67,914 $75,328 $10,361 $ 60,142
======== ======== ======= ======= =========
</TABLE>

FOOTNOTES

(1) Reflects lower net depreciation/amortization resulting from assets and
capitalized costs being depreciated over a longer estimated useful life
based on engineering studies.

(2) Reflects accrued interest on $800 million principal amount for 12 months at
a rate of 9.156% per annum.

(3) Incremental tax expense due to increased taxable income computed at 41.37%.

F-39
<PAGE> 137

REPORT OF INDEPENDENT ACCOUNTANTS

To the Management of
NRG South Central Generating LLC:

In our opinion, the accompanying carve-out statement of net assets and the
related carve-out statement of certain revenue and expenses present fairly, in
all material respects, the net assets of the Cajun Electric (Cajun Facilities)
business to be acquired by Louisiana Generating LLC at December 31, 1999 and
1998, and certain revenue and expenses of its operations for each of the three
years in the period ended December 31, 1999 in conformity with accounting
principles generally accepted in the United States. These financial statements
are the responsibility of NRG South Central Generating LLC's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, which require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. Our audit included
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for the opinion expressed above.

As described in Note 3, the accompanying carve-out financial statements were
prepared to present the net assets of the Cajun Electric (Cajun Facilities)
business to be acquired by Louisiana Generating LLC and the certain revenue and
expenses related to such business and are not intended to be a complete
presentation of the assets, liabilities, revenue, expenses and cash flows of
Cajun Electric Power Cooperative, Inc.

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
March 7, 2000

F-40
<PAGE> 138

CAJUN ELECTRIC (CAJUN FACILITIES)

CARVE-OUT STATEMENT OF NET ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1999 1998
---------- ----------
(IN THOUSANDS)
<S> <C> <C>
ASSETS
Utility plant
Electric plant in service................................. $1,198,928 $1,191,375
Less: Accumulated depreciation and amortization........... 632,899 594,539
---------- ----------
566,029 596,836
Construction work in progress............................. 3,996 1,455
Electric plant held for future use........................ 9,904 9,904
---------- ----------
579,929 608,195
---------- ----------
Other property and investments
Non-utility property...................................... 670 670
Decommissioning reserve fund.............................. 3,518 3,225
---------- ----------
4,188 3,895
---------- ----------
Current assets
Accounts receivable -- electric customers
Members................................................ 25,944 23,504
Nonmembers............................................. 6,220 4,725
Accounts receivable -- other.............................. 1,678 2,043
Fuel and supplies inventories............................. 34,234 40,578
Prepaids.................................................. 1,600 1,316
---------- ----------
69,676 72,166
---------- ----------
Total assets...................................... 653,793 684,256
---------- ----------
LIABILITIES
Current liabilities
Accounts payable.......................................... 4,806 2,114
Taxes other than income tax............................... 150 215
Other accrued expenses.................................... 8,966 13,904
---------- ----------
13,922 16,233
---------- ----------
Decommissioning............................................. 3,518 3,225
---------- ----------
Total liabilities...................................... 17,440 19,458
---------- ----------
Net assets........................................ $ 636,353 $ 664,798
========== ==========
</TABLE>

See accompanying notes to financial statements.
F-41
<PAGE> 139

CAJUN ELECTRIC (CAJUN FACILITIES)

CARVE-OUT STATEMENT OF CERTAIN REVENUE AND EXPENSES

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Operating revenue
Sales of electric energy
Members............................................... $292,090 $289,856 $280,109
Nonmembers............................................ 75,258 66,341 65,715
Other.................................................... 1,214 1,379 958
-------- -------- --------
368,562 357,576 346,782
-------- -------- --------
Operating expenses
Power production
Fuel.................................................. 165,597 154,964 154,257
Operations and maintenance............................ 36,673 37,405 37,236
Purchased power.......................................... 10,951 11,645 12,681
Other power supply expenses.............................. 577 592 578
Transmission............................................. 30,246 29,882 41,687
Administrative and general............................... 9,711 9,122 9,437
Depreciation and amortization............................ 37,930 38,117 39,537
Taxes, other than income................................. 7,093 7,629 8,575
-------- -------- --------
298,778 289,356 303,988
-------- -------- --------
Operating income........................................... 69,784 68,220 42,794
-------- -------- --------
Other income and expenses
Interest, rents and leases............................... 463 456 695
Other income............................................. 545 787 730
Loss on asset dispositions............................... (2,878) (5,900) (481)
-------- -------- --------
(1,870) (4,657) 944
-------- -------- --------
Revenues in excess of expenses............................. $ 67,914 $ 63,563 $ 43,738
======== ======== ========
</TABLE>

See accompanying notes to financial statements.
F-42
<PAGE> 140

CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS

1. BUSINESS DESCRIPTION

The accompanying "carve-out" financial statements present the net assets
and certain revenue and expenses of the non-nuclear electric power generating
business (herein named "Cajun Electric (Cajun Facilities)") of Cajun Electric
Power Cooperative, Inc. (the "Cooperative"). The Cooperative is a rural electric
generation and transmission cooperative wholly owned by 11 distribution
cooperatives (the "Members"). Pursuant to a competitive bidding process
following the Cooperative's Chapter 11 bankruptcy proceeding, Louisiana
Generating LLC has agreed to acquire the Cooperative's non-nuclear electric
power generating facilities (see Notes 2 and 3). Louisiana Generating LLC is a
wholly owned subsidiary of NRG South Central Generating LLC, which in turn is an
indirect wholly owned subsidiary of NRG Energy, Inc. NRG Energy, Inc. is a
wholly owned subsidiary of Northern States Power Company.

2. BANKRUPTCY PROCEEDING

Bankruptcy Filing

On December 21, 1994 (the "Petition Date"), the Cooperative filed a
Petition for Reorganization under Chapter 11 of the United States Bankruptcy
Code and began operating as debtor-in-possession under the supervision of the
United States Bankruptcy Court for the Middle District of Louisiana (the
"Bankruptcy Court"). In August 1995, the United States District Court for the
Middle District of Louisiana (the "Court") ordered the appointment of a trustee
(the "Trustee") to oversee the Cooperative's operations for the benefit of claim
holders and interest holders. All debts of the Cooperative as of the Petition
Date were stayed by the bankruptcy petition and subject to compromise pursuant
to such proceedings. The Cooperative operated its business and managed its
assets in the ordinary course as debtor-in-possession, and was required to
obtain Trustee approval for transactions outside the ordinary course of
business.

Plan of Reorganization and Acquisition

On January 22, 1996, the Court approved the Trustee's motion to establish
procedures for submission of proposals to purchase the Cooperative's assets. The
Trustee ultimately selected a bid by NRG Energy, Inc. to create a new limited
liability company (Louisiana Generating LLC) to purchase certain non-nuclear
assets of the Cooperative. In September 1999, the Bankruptcy Court approved the
Plan of Reorganization (the "Plan"), which incorporates the Acquisition
Agreement (see Note 3). The purchase price of the assets to be acquired by
Louisiana Generating LLC is $1,026 million, subject to adjustment for interest
rate fluctuations beyond specific levels. In addition, Louisiana Generating LLC
has agreed to reimburse the Members for up $14 million of the expenses that the
Members incurred in connection with the bankruptcy of the Cooperative. The
transaction is scheduled to close on March 31, 2000, subject to various
conditions.

The assets to be acquired by Louisiana Generating LLC include all
non-nuclear assets owned by the Cooperative, other than enumerated excluded
assets defined in the Acquisition Agreement. Generally, the assets to be
acquired consist of:

- Big Cajun I and Big Cajun II, Units 1 and 2;

- the Cooperative's 58% interest in Big Cajun II, Unit 3;

- an energy control center and headquarters building;

- approximately 4,200 acres of agricultural land near Coushatta, Louisiana;

- a 540 MW General Electric steam turbine generator;

F-43
<PAGE> 141
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

- a 17.5 mile gas pipeline system;

- 848 steel rotary dump railcars;

- approximately 38,000 annual sulfur dioxide allowances;

- all coal inventory, oil in storage, materials and supplies;

- the Big Cajun II solid waste closure investment fund; and

- certain transmission assets and all other substations.

Louisiana Generating LLC will not assume any liabilities of the
Cooperative, other than (i) obligations under any of the contracts that
Louisiana Generating LLC assumes in connection with the acquisition and which
arise on or after the closing date of the acquisition, (ii) contingent
liabilities related to certain tax benefit transfer agreements to which the
Cooperative was a party and (iii) environmental liabilities that may exist
related to the transferred property, including the obligation to rehabilitate
the Big Cajun II ash and wastewater impoundment areas (see Note 8).

3. BASIS OF PRESENTATION

The accompanying carve-out financial statements have been presented in
accordance with generally accepted accounting principles and were derived from
the historical accounting records of the Cooperative. The statements are
intended to present the net assets and certain revenue and expenses of the Cajun
Electric (Cajun Facilities) business to be acquired by Louisiana Generating LLC
pursuant to the Fifth Amended and Restated Asset Purchase and Reorganization
Agreement among Louisiana Generating LLC, Ralph R. Mabey, as Chapter 11 Trustee
of Cajun Electric Power Cooperative, Inc., and NRG Energy, Inc. (as to Sections
7.4, 9.13 and 9.14 of the agreement only) (the "Acquisition Agreement") and the
Cooperative's bankruptcy proceedings (see Note 2). Louisiana Generating LLC has
agreed to purchase substantially all of the Cooperative's non-nuclear electric
power generating facilities and related transmission assets, inventory and other
real and personal property. Louisiana Generating LLC will not acquire the
"Excluded Assets", as defined in the Acquisition Agreement, which generally
consist of the Cooperative's cash, receivables and investments, nor will it
assume any liabilities of the Cooperative, except as described in Note 2.
Accordingly, the carve-out financial statements do not include all assets,
liabilities, revenue and costs and expenses of the Cooperative as of and for the
periods presented.

Generally, the statements of net assets exclude the Cooperative's cash,
investments (except decommissioning trust fund investments), employee
post-retirement benefit obligation, liabilities subject to compromise in the
bankruptcy proceeding, income taxes and equity and margin accounts. The
statements of certain revenue and expenses exclude the Cooperative's investment
earnings (except earnings from the decommissioning trust fund investments),
bankruptcy reorganization costs, income taxes, and revenue, expenses and losses
related to the ownership, operation and disposal of its 30% interest in the
River Bend Nuclear Station in 1997. All long-term debt of the Cooperative is
subject to compromise in the bankruptcy proceeding and during the three years
ended December 31, 1999 the Cooperative did not record any interest expense
thereon in accordance with American Institute of Certified Public Accountants
Statement of Position No. 90-7, "Financial Reporting by Entities in
Reorganization Under the Bankruptcy Code." Therefore, the carve-out financial
statements do not include any long-term debt of the Cooperative or interest
expense thereon.

Although Louisiana Generating LLC will not purchase any receivables or
assume any liabilities of the Cooperative, except as described in Note 2, the
statements of net assets include receivables, accounts payable and accrued
expenses in order to present the historical net assets of the business operation
that will be acquired.

F-44
<PAGE> 142
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

The carve-out financial statements do not include a statement of cash flows
due to exclusion of cash from the statements of net assets. However, see Note 4
for a summary of cash provided by and used in Cajun Electric's (Cajun
Facilities) operating and investing activities.

4. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the amounts reported in the financial statements and
accompanying notes. Actual results could differ from those estimates.

Significant Customers and Concentrations of Credit Risk

During 1999 sales to two customers totaled 16.7% and 18.9%, respectively,
of total operating revenue (1998: 16.7% and 19.2%, respectively; 1997: 16.2% and
19.0%, respectively). No other customer accounted for more than 10% of total
operating revenue during the years ended December 31, 1999, 1998 and 1997.

Electric Plant in Service and Construction Work in Progress

Electric plant in service and construction work in progress are stated on
the basis of cost. Depreciation is computed using the straight-line method over
the expected useful lives of the related component assets. The net book value of
units of property replaced or retired, including costs of removal net of any
salvage value, is charged to operations.

Fuel and Supplies Inventories

Fuel and supplies inventories are stated on the basis of cost utilizing the
weighted-average cost method of inventory valuation.

Fair Values of Financial Instruments

Investments held in the decommissioning reserve fund are comprised of U.S.
government debt securities carried at amortized cost, which approximates fair
value.

F-45
<PAGE> 143
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

Summary of Cash Flows

Summarized cash flows from operating and investing activities were as
follows (in thousands):

<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Cash flows from operating activities:
Revenues in excess of expenses........................... $ 67,914 $ 63,563 $ 43,738
Adjustments to reconcile net margins to net cash:
Depreciation and amortization......................... 37,930 38,117 39,537
Asset dispositions.................................... 2,878 5,900 481
Changes in accounts receivable........................ (4,939) 5,988 (2,838)
Changes in fuel and prepayments....................... 6,060 (8,184) 5,315
Changes in accounts payable and accrued expenses...... (2,313) (4,333) (254)
-------- -------- --------
Net cash provided by operating activities........ 107,530 101,051 85,979
-------- -------- --------
Cash flows from (for) investing activities:
Capital expenditures..................................... (11,631) (9,999) (7,074)
-------- -------- --------
$ 95,899 $ 91,052 $ 78,905
======== ======== ========
</TABLE>

5. UTILITY PLANT

Electric plant in service is comprised of the following generating
facilities:

<TABLE>
<CAPTION>
CAPABLE LOUISIANA GENERATING
GENERATING -------------------------
GENERATING UNIT CAPACITY PERCENTAGE MEGAWATTS
- --------------- ----------- ---------- -----------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C>
Big Cajun II, Unit 1..................................... 575 100% 575
Big Cajun II, Unit 2..................................... 575 100% 575
Big Cajun II, Unit 3..................................... 575 58% 338
Big Cajun I, Unit 1...................................... 110 100% 110
Big Cajun I, Unit 2...................................... 110 100% 110
----- --- -----
1,945 1,708
===== =====
</TABLE>

Big Cajun II, Unit 3 is jointly owned by the Cooperative (58%) and Gulf
States Utilities (42%). The unit is operated by the Cooperative pursuant to a
Joint Ownership Participation and Operating Agreement, which governs the rights
and obligations to the ownership of the facility. Each owner is entitled to
their ownership percentage of the hourly net electrical output of the unit. All
fixed costs of operating the unit are shared in proportion to the respective
ownership interests and all variable costs are borne in proportion to the energy
delivered to either co-owner. The statements of certain revenue and expenses
include the Cooperative's share of all fixed and variable costs of operating the
unit. The Cooperative's 58% share of the original cost included in electric
plant in service at December 31, 1999 was $291.1 million ($290.9 million at
December 31, 1998). The corresponding accumulated depreciation and amortization
was $151.1 million ($141.9 million at December 31, 1998).

The Cooperative will assign the Joint Ownership Participation and Operating
Agreement to Louisiana Generating LLC upon closing of the acquisition.

F-46
<PAGE> 144
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

Electric plant in service balances at December 31 consisted of the
following (in thousands):

<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
Production:
Coal...................................................... $1,048,012 $1,041,741
Gas....................................................... 35,368 34,749
Transmission................................................ 94,393 94,320
General..................................................... 21,155 20,565
---------- ----------
$1,198,928 $1,191,375
========== ==========
</TABLE>

Construction work in progress consists of improvements and additions to
existing plants. The estimated cost to complete these projects at December 31,
1999 was approximately $10.8 million.

Electric plant held for future use of approximately $9.9 million at
December 31, 1999 and 1998 consists primarily of land, carried at its original
cost of $9.5 million, related to an abandoned lignite project that has been
retained as a possible site for a future generating facility.

The net change in accumulated depreciation and amortization for the years
ended December 31 was (in thousands):

<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
Charged to operating expenses............................... $ 37,930 $ 38,117
Charged to fuel inventories and other assets................ 1,192 1,197
---------- ----------
$ 39,122 $ 39,314
Less: Disposals and other adjustments....................... 762 1,435
---------- ----------
$ 38,360 $ 37,879
========== ==========
</TABLE>

Substantially all of the assets included in the carve-out statements of net
assets are pledged as collateral to the Cooperative's long-term debt payable to
the Rural Utilities Service. In addition, certain office facilities have been
separately pledged as collateral to the Cooperative's industrial revenue bonds.
These obligations are included in the Cooperative's pre-petition liabilities
subject to compromise, which have been excluded from the carve-out statement of
net assets. Upon execution of the Plan and closing of the acquisition, Louisiana
Generating LLC will acquire the assets free of such encumbrances.

6. EMPLOYEE BENEFIT PLANS

All of the Cooperative's employees participate in the National Rural
Electric Cooperatives Association (NRECA) Retirement and Security Program once
they have met minimum service requirements. The Cooperative makes annual
contributions to the plan equal to the amounts accrued for pension expense. In
this master multiple-employer defined benefit plan, which is available to all
member cooperatives of the NRECA, the accumulated benefits and plan assets are
not determined or allocated separately by individual employer. The Cooperative's
contributions to the plan and amounts included in the accompanying statements of
certain revenue and expenses of Cajun Electric (Cajun Facilities) totaled
approximately $1.7 million, $1.7 million and $1.3 million in 1999, 1998 and
1997, respectively.

The Cooperative also maintains a defined contribution pension plan, which
constitutes a cash or deferred arrangement under section 401(k) of the Internal
Revenue Code of 1986 (as amended). Once minimum service requirements are met,
all of the employees of the Cooperative are eligible to participate in the plan.
Under the terms of the plan, which is administered by the NRECA, the Cooperative
matches 50% of employee contributions up to a maximum of 4% of each
participating employee's base

F-47
<PAGE> 145
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

compensation. The Cooperative's contributions to the plan and amounts included
in the accompanying statement of certain revenue and expenses of Cajun Electric
(Cajun Facilities) totaled approximately $0.4 million, $0.3 million and $0.4
million in 1999, 1998 and 1997, respectively.

The Cooperative also makes medical benefits available to all retirees. For
those nonbargaining employees who retire at age 62 or thereafter and who have at
least 10 years of service, the Cooperative will pay a portion of the cost. All
other retirees are required to pay the full cost of benefits. Net periodic
postretirement benefit expense of approximately $0.8 million, $0.8 million and
$0.8 million in 1999, 1998 and 1997, respectively, is included in the
accompanying statement of certain revenue and expenses.

Upon the closing of the acquisition, all of the Cooperative's employee
benefit plans will be terminated, including the defined benefit pension plan,
the defined contribution (401(k)) pension plan and the post-retirement
healthcare plan and no liabilities related thereto will be assumed by Louisiana
Generating LLC.

7. RATES AND REGULATION

The electric rates charged by the Cooperative to its Members have been
subject to the jurisdiction of the Louisiana Public Service Commission ("LPSC").
For the three years ended December 31, 1999, the Cooperative provided capacity
and energy to its 11 Members pursuant to "all requirements" power supply
agreements. Generally, the all requirements power supply agreements obligated
the Cooperative to supply and required the Members to purchase all of the energy
and capacity required by the Members for service to its retail customers, with
limited exceptions. The Cooperative also provided capacity and energy to three
other customers under long-term power agreements and sold excess capacity and
energy on a merchant basis to other power suppliers and marketers.

Pursuant to the Acquisition Agreement and the Plan, all 11 Members have
elected to terminate, effective on the closing date, their existing all
requirements supply agreements with the Cooperative. Each of the 11 Members has
selected one of three alternative supply options offered by Louisiana Generating
LLC, to be effective immediately after the acquisition closes. Seven of the
Members have agreed to purchase power from Louisiana Generating LLC under
long-term "all requirements" power supply agreements with terms of 25 years
commencing on the acquisition closing. After the initial term, each agreement
will continue on a year to year basis unless either party gives the other five
years' notice of its intent to terminate the agreement. The remaining four
Members have agreed to purchase power from Louisiana Generating LLC under
short-term four-year transition power supply agreements. A Member may terminate
a short-term agreement upon two years advance notice.

The underlying terms and provisions of the long- and short-term power
supply agreements offered by Louisiana Generating LLC and selected by the
Members have been approved by the LPSC, which has regulatory authority over the
Members. Although the form of the agreements have been approved by the LPSC,
each Member must obtain approval from the LPSC of the supply alternative
selected. Such approval has been obtained by three of the Members that have
elected the long-term agreement. The remaining eight Members are expected to
request and receive LPSC approval of their decisions prior to the closing of the
acquisition.

Electric Utility Deregulation

On December 17, 1997, the LPSC accepted a staff report finding that
deregulation, or retail wheeling, may be in the public interest contingent upon
numerous issues being individually and adequately researched. During January
1998, the LPSC investigated the issues of tax implications; unbundling; market
structure; market power, reliability, Independent System Operators; stranded
costs and benefits; consumer protection, public policy programs and
environmental issues; and future regulatory structure and affiliate
relationships. In February of 1999, LPSC staff issued a report finding that
restructuring is not in the public

F-48
<PAGE> 146
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

interest and recommending that the LPSC defer making a final determination. At
its March 1999 Open Session, the LPSC adopted a new procedural schedule to
continue its investigation of competitive implications through August of 2000.
The effect of deregulation upon Cajun Electric (Cajun Facilities) cannot be
determined at this time.

8. OTHER COMMITMENTS AND CONTINGENCIES

Coal Supply and Transportation Agreements

Purchases under the terms of contracts for the acquisition and related
transportation of coal during 1999, 1998 and 1997 were approximately $129
million, $136 million and $127 million, respectively. Louisiana Generating LLC
will not assume any liabilities incurred by the Cooperative prior to the closing
of the acquisition related to the existing coal supply and transportation
agreements.

Louisiana Generating LLC has entered into a coal supply agreement under
which Triton Coal Company will sell to Louisiana Generating LLC sufficient
quantities of coal to satisfy the full coal requirements of the Cajun facilities
for a specified period.

Louisiana Generating LLC has entered into a coal transportation agreement
with Burlington Northern and Santa Fe Railway Company and American Commercial
Terminal LLC which agreement will be effective on the closing date of the
acquisition. Pursuant to the agreement, the railroad will transport the coal
from the Triton mines in Wyoming to St. Louis, Missouri, and American Commercial
Terminal will transport the coal down the Mississippi River from St. Louis to
the Cajun facilities.

Decommissioning

The Cooperative is required by the State of Louisiana Department of
Environmental Quality ("DEQ") to rehabilitate its Big Cajun II ash and
wastewater impoundment areas upon removal from service of the Big Cajun II
facilities. On July 1, 1989, the Cooperative established a guarantor trust (the
"Solid Waste Disposal Trust Fund") to accumulate the estimated funds necessary
for such purpose. The Cooperative deposited $1.06 million in the Solid Waste
Disposal Trust Fund in 1989, and has funded $116,000 annually thereafter, based
upon the Cooperative's estimated future rehabilitation cost (in 1989 dollars) of
approximately $3.5 million and the remaining estimated useful life of the Big
Cajun II facilities. Cumulative contributions to the Solid Waste Disposal Trust
Fund and earnings on the investments therein are accrued as a decommissioning
liability. At December 31, 1999 the carrying value of the trust fund investments
and the related accrued decommissioning liability was approximately $3.5
million. The trust fund investments are comprised of various debt securities of
the United States and are carried at amortized cost, which approximates their
fair value.

The Solid Waste Trust Fund is included in assets to be acquired by
Louisiana Generating LLC, which will also assume the obligation to rehabilitate
the Big Cajun II ash and wastewater impoundment areas.

Letters of Credit

The Cooperative has outstanding two letters of credit in the aggregate
amount of approximately $15 million as of December 31, 1999 supporting potential
indemnity payments related to certain tax benefit transfer agreements to which
the Cooperative was a party. The letters of credit will be terminated upon the
closing of the acquisition. However, as of the closing date, Louisiana
Generating LLC will assume the contingent liability related to the potential
indemnity payments.

F-49
<PAGE> 147
CAJUN ELECTRIC (CAJUN FACILITIES)

NOTES TO CARVE-OUT FINANCIAL STATEMENTS -- (CONTINUED)

Member Class Action Rate Litigation

On September 20, 1989, a class action petition was filed in the Tenth
Judicial District State Court in Natchitoches Parish, Louisiana, naming the
Cooperative's Members as defendants. The plaintiffs in this action seek a refund
of all rate increases enacted by the Cooperative's Members from 1978 until the
respective Member voted to be subject to the jurisdiction of the LPSC or was
placed under the jurisdiction of the LPSC by action of the State Supreme Court.
On October 17, 1989, the case was moved to the federal courts. On August 28,
1992, the District Court abstained from this matter in favor of proceedings at
the LPSC.

The LPSC currently has an open docket associated with this matter. On
August 19, 1994, the LPSC adopted the standards recommended by its Special
Counsel. Based on those standards, Special Counsel issued a report in August
1996 recommending that 23 of the 29 rate increases implemented during the period
of nonregulation be found presumptively not unreasonable and be eliminated from
further review. Special Counsel recommended that the remaining six rate
increases be further reviewed for reasonableness. On November 18, 1997, the LPSC
issued Order U-19943-B dismissing two more rate increases, finding all but the
four remaining increases presumptively not unreasonable. On August 19, 1998, the
LPSC dismissed two rate increases for Southwest Louisiana Electric Membership
Corporation leaving the final two rate increases to be reviewed for
reasonableness. A hearing was held on October 12, 1999, on the last two rate
increases. The LPSC staff is expected to issue a final report in time for the
LPSC to vote on the matter at its March 2000 Open Session. The timing or outcome
of this matter is uncertain and no provision for any liability that may result
has been made in the financial statements. However, each Member has entered into
a stipulation with the Trustee which releases the Bankruptcy Estate from claims
by the Members that might arise as a result of any refunds which the LPSC may
order. Further, Louisiana Generating LLC will not assume any liability that may
result from the outcome of this matter.

F-50
<PAGE> 148

INSIDE BACK COVER PAGE

NRG ENERGY, INC. SIGNIFICANT PROJECT LIST

<TABLE>
<CAPTION>
NET
CAPACITY OWNERSHIP INTEREST
LOCATION (MW) (MW)
- -------------------------------------------- -------- ------------------
<S> <C> <C>
NORTH AMERICA
NORTHEAST REGION
Oswego, Oswego, NY............................................................ 1,700.0 1,700.0
Middletown, Middletown, CT.................................................... 856.2 856.2
Arthur Kill, Staten Island, NY................................................ 842.0 842.0
Huntley, Tonawanda, NY........................................................ 760.0 760.0
Astoria Gas Turbines, Queens, NY.............................................. 614.0 614.0
Dunkirk, Dunkirk, NY.......................................................... 600.0 600.0
Montville, Uncasville, CT..................................................... 497.6 497.6
Devon, Milford, CT............................................................ 400.5 400.5
Norwalk Harbor, So. Norwalk, CT............................................... 353.0 353.0
Somerset Power, Somerset, MA*................................................. 229.0 229.0
Connecticut Turbines, Connecticut............................................. 127.4 127.4
Kingston Cogeneration, Kingston, Ontario, Canada.............................. 110.0 27.5
Parlin Cogen, Parlin, NJ...................................................... 122.0 24.4
Grays Ferry Cogen, Grays Ferry, PA............................................ 150.0 15.0

SOUTH CENTRAL REGION
Louisiana Generating LLC, Baton Rouge, LA..................................... 1,945.0 1,708.5
Rocky Road, East Dundee, IL................................................... 250.0 125.0
Rocky Road (Expansion), East Dundee, IL **.................................... 100.0 50.0
Morris Cogen, Morris, IL...................................................... 117.0 23.4
Pryor Cogen, Pryor, OK........................................................ 110.0 22.0
Power Smith Cogeneration, Oklahoma City, OK................................... 110.0 9.6

WESTERN REGION
El Segundo Power, El Segundo, CA.............................................. 1,020.0 510.0
Encina Power Station, Carlsbad, CA............................................ 965.0 482.5
Long Beach Generating, Long Beach, CA......................................... 530.0 265.0
Crockett Cogeneration, Crockett, CA........................................... 240.0 138.4
San Diego Turbines, San Diego, CA............................................. 253.0 126.5
Mt. Poso, Bakersfield, CA..................................................... 49.5 19.5

OTHER NORTH AMERICA
NEO, Various.................................................................. 174.5 90.3
Other, Various**.............................................................. 533.7 313.1
Energy Investors Fund, Various................................................ 999.0 10.0

TOTAL NORTH AMERICA........................................................... 14,759 10,940

INTERNATIONAL
EUROPE
Killingholme A, North Lincolnshire, England................................... 680.0 680.0
Schkopau, Halle, Germany...................................................... 960.0 200.0
ECK Generating, Kladno, Czech Republic........................................ 345.0 153.5
Enfield Energy Centre, London, England, UK.................................... 396.0 99.0
MIBRAG, Thiessen, Germany..................................................... 233.0 78.0
Energy Center Kladno, Kladno, Czech Republic.................................. 28.0 12.4

AUSTRALIA
Gladstone Power Station, Gladstone, Qld., Australia........................... 1,680.0 630.0
Loy Yang Power A, Traralgon, Vic., Australia.................................. 2,000.0 507.4
Collinsville, Collinsville, Qld., Australia................................... 192.0 96.0

Latin America
COBEE, Bolivia................................................................ 219.2 108.4
Bulo Bulo, Bolivia............................................................ 87.0 26.1

OTHER INTERNATIONAL
Energy Developments, Ltd., Various............................................ 274.0 79.1
Scudder Latin American Power, Various Locations............................... 772.0 51.2
Energy Investors Fund, Various................................................ 1,035.0 3.0

TOTAL INTERNATIONAL........................................................... 8,901 2,724

TOTAL WORLDWIDE............................................................... 23,660 13,664
======== ========
</TABLE>

- ---------------
* Includes 69 megawatts on deactivated reserve
** Includes facilities under construction or suspended operations.
<PAGE> 149

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

28,170,000 SHARES

NRG ENERGY, INC.

COMMON STOCK

NRG LOGO

------------------

PROSPECTUS

, 2000

------------------

SALOMON SMITH BARNEY

------------------

CREDIT SUISSE FIRST BOSTON

ABN AMRO ROTHSCHILD
A DIVISION OF ABN AMRO INCORPORATED

BANC OF AMERICA SECURITIES LLC
GOLDMAN, SACHS & CO.
LEHMAN BROTHERS
MERRILL LYNCH & CO.
MORGAN STANLEY DEAN WITTER

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
<PAGE> 150

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The registrant's expenses in connection with the Offering described in this
registration statement are set forth below. All amounts except the Securities
and Exchange Commission registration fee, the NASD filing fee and the listing
fee are estimated.

<TABLE>
<S> <C>
Securities and Exchange Commission registration fee......... 158,400
NASD filing fee............................................. 30,500
Printing and engraving expenses............................. 300,000
Accounting fees and expenses................................ 50,000
Legal fees and expenses..................................... 500,000
Fees and expenses (including legal fees) for qualification
under state securities laws............................... 1,000
Transfer agent's fees and expenses.......................... 10,000
Miscellaneous............................................... 25,100
---------
Total..................................................... 1,075,000
=========
</TABLE>

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS

Section 145(a) of the General Corporation Law of the State of Delaware (the
"DGCL") provides that a Delaware corporation may indemnify any person who was or
is a party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of the corporation) by
reason of the fact that such person is or was a director, officer, employee or
agent of the corporation or is or was serving at the request of the corporation
as a director, officer, employee or agent of another corporation or enterprise,
against expenses, judgments, fines and amounts paid in settlement actually and
reasonably incurred by such person in connection with such action, suit or
proceeding if he or she acted in good faith and in a manner he or she reasonably
believed to be in or not opposed to the best interests of the corporation, and,
with respect to any criminal action or proceeding, had no cause to believe his
or her conduct was unlawful.

Section 145(b) of the DGCL provides that a Delaware corporation may
indemnify any person who was or is a party or is threatened to be made a party
to any threatened, pending or completed action or suit by or in the right of
corporation to procure a judgment in its favor by reason of the fact that such
person acted in any of the capacities set forth above, against expenses actually
and reasonably incurred by such person in connection with the defense or
settlement of such action or suit if he or she acted under similar standards to
those set forth above, except that no indemnification may be made in respect to
any claim, issue or matter as to which such person shall have been adjudged to
be liable to the corporation unless and only to the extent that the court in
which such action or suit was brought shall determine that despite the
adjudication of liability, but in view of all the circumstances of the case,
such person is fairly and reasonably entitled to be indemnified for such
expenses which the court shall deem proper.

Section 145 of the DGCL further provides that to the extent a director or
officer of a corporation has been successful in the defense of any action, suit
or proceeding referred to in subsection (a) and (b) of Section 145 or in the
defense of any claim, issue or matter therein, he or she shall be indemnified
against expenses actually and reasonably incurred by him or her in connection
therewith; that indemnification provided for by Section 145 shall not be deemed
exclusive of any other rights to which the indemnified party may be entitled;
and that the corporation may purchase and maintain insurance on behalf of a
director or officer of the corporation against any liability asserted against
such officer or director and incurred by him or her in any such capacity or
arising out of his or her status as such, whether or not the corporation would
have the power to indemnify him or her against such liabilities under Section
145.
<PAGE> 151

As authorized by Section 145 of the DGCL, each director and officer of NRG
may be indemnified by NRG against expenses (including attorney's fees,
judgments, fines and amounts paid in settlement) actually and reasonably
incurred in connection with the defense or settlement of any threatened, pending
or completed legal proceedings in which he is involved by reason of the fact
that he is or was a director or officer of NRG if he acted in good faith and in
a manner that he reasonably believed to be in or not opposed to the best
interest of NRG and, with respect to any criminal action or proceeding, if he
had no reasonable cause to believe that his conduct was unlawful. However, if
the legal proceeding is by or in the right of NRG, the director or officer may
not be indemnified in respect of any claim, issue or matter as to which he shall
have been adjudged to be liable for negligence or misconduct in the performance
of his duty to NRG unless a court determines otherwise.

In addition, Article VI of NRG's By-Laws provides that NRG shall indemnify
and hold harmless, to the fullest extent permitted by applicable law, any person
who was or is made or is threatened to be made a party or is otherwise involved
in any action, suit or proceeding, whether civil, criminal, administrative or
investigative (a "Proceeding") by reason of the fact that he or she, or a person
for whom he or she is the legal representative, is or was a director, officer,
employee or agent of NRG or is or was serving at the request of NRG as a
director, officer, employee or agent of another company or of a partnership,
joint venture, trust, enterprise or non-profit entity, including service with
respect to employee benefit plans, against all liability and loss suffered and
expenses reasonably incurred by such person. NRG shall be required to indemnify
a person in connection with a Proceeding initiated by such person only if the
Proceeding was authorized by the Board of Directors of NRG.

All of NRG's directors will enter into indemnity agreements that obligate
NRG to indemnify such directors to the fullest extent permitted by the DGCL.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES

The following tables summarize securities issued or sold by us within the
past three years that were not sold pursuant to registered offerings:

<TABLE>
<CAPTION>
UNDERWRITER OR
SECURITY AND DATE SOLD CLASS OF PURCHASERS AMOUNT SOLD EXEMPTION RELIED UPON
- ---------------------- ----------------------- ----------------- ---------------------
<S> <C> <C> <C>
7.5% Senior Notes Due 2007
issued June 17, 1997.... Accredited investors: $250,000,000 Rule 144A; Regulation S
Salomon Brothers Inc. 0.650% discount
ABN AMRO
Chicago Corporation
Chase Securities Inc.
7.97% Reset Notes Due 2020
(Remarketing Date March
15, 2005) issued March
20, 2000................ NRG Energy Pass-Through L160,000,000 Section 4(2)
Trust 2000-1 no discount
</TABLE>

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

<PAGE> 152

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
4.3 Loan Agreement, dated June 4, 1999 between Northeast
Generating LLC,
Chase Manhattan Bank and Citibank, N.A.(b)
4.4 Indenture between the Company and Norwest Bank Minnesota,
National Association, as Trustee dated as of May 25,
1999.(c)
4.5 Indenture between the Company and NRG Northeast Generating
LLC and The Chase Manhattan Bank, as Trustee dated as of
February 22, 2000.(b)
4.6 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70%
Remarketable or Redeemable Securities ("ROARS") due March
15, 2005.(b)
4.7 Trust Agreement between NRG Energy Inc. and The Bank of New
York, as Trustee, dated March 20, 2000.(b)
4.8 Indenture between NRG Energy Inc. and the Bank of New York,
as Trustee dated March 20, 2000, 160,000,000 pounds sterling
Reset Senior Notes due March 15, 2000.(b)
4.9 Indenture between the Company and Norwest Bank Minnesota,
National Association as Trustee dated as of November 8,
1999.(d)
4.10 Indenture, dated as of January 31, 1996, between the Company
and Norwest Bank Minnesota, National Association, As
Trustee.(a)
5.1** Opinion and Consent of Gibson, Dunn & Crutcher LLP,
regarding validity of Common Stock.
10.1 Employment Contract, dated as of June 28, 1995, between the
Company and
David H. Peterson.(a)
10.2 Note Agreement, dated August 20, 1993, among the Company
Energy Center, Inc. and each of the purchasers named
therein.(a)
10.3 Master Shelf and Revolving Credit Agreement, dated August
20, 1993 among the Company Energy Center, Inc., The
Prudential Insurance Registrants of America and each
Prudential Affiliate which becomes party thereto.(a)
10.4 Energy Agreement, dated February 12, 1988 between the
Company formerly known as Norenco Corporation) and Waldorf
Corporation (the "Energy Agreement").(a)
10.5 First Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.6 Second Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.7 Third Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.8 Construction, Acquisition, and Term Loan Agreement, dated
September 2, 1997 by the among NEO Landfill Gas, Inc., as
Borrower, the lenders named on the signature pages, Credit
Lyonnais New York Branch, as Construction/Acquisition Agent
and Lyon Credit Corporation as Term Agent.(a)
10.9 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
10.10 Construction, Acquisition, and Term Loan Agreement, dated
September 2, 1997 by and among Minnesota Methane LLC, as
Borrower, the lenders named on the signature pages, Credit
Lyonnais New York Branch, as Construction/Acquisition Agent
and Lyon Credit Corporation as Term Agent.(a)
10.11 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
10.12 Non Operating Interest Acquisition Agreement dated as of
September 12, 1997,
by and among the Company and NEO Corporation.(a)
10.13 Employment Agreements between the Company and certain
officers dated as of April 15, 1998.(e)
</TABLE>

<PAGE> 153

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.14 Wholesale Standard Offer Service Agreement between
Blackstone Valley Electric Company, Eastern Edison Company,
Newport Electric Corporation and NRG Power Marketing, Inc.,
dated October 13, 1998.(b)
10.15 Asset Sales Agreement by and between Niagara Mohawk Power
Corporation and NRG Energy, Inc., dated December 23,
1998.(b)
10.16 First Amendment to Wholesale Standard Offer Service
Agreement between Blackstone Valley Electric Company,
Eastern Edison Company, Newport Electric Corporation and NRG
Power Marketing, Inc., dated January 15, 1999.(b)
10.17 Generating Plant and Gas Turbine Asset Purchase and Sale
Agreement for the Arthur Kill generating plants and Astoria
gas turbines by and between Consolidated Edison Company of
New York, Inc., and NRG Energy, Inc., dated January 27,
1999.(b)
10.18 Transition Energy Sales Agreement between Arthur Kill Power
LLC and Consolidated Edison Company of New York, Inc., dated
June 1, 1999.(b)
10.19 Transition Power Purchase Agreement between Astoria Gas
Turbine Power LlC and Consolidated Edison Company of New
York, Inc., dated June 1, 1999.(b)
10.20 Transition Power Purchase Agreement between Niagara Mohawk
Power Corporation and Huntley Power LLC, dated June 11,
1999.(b)
10.21 Transition Power Purchase Agreement between Niagara Mohawk
Power Company and Dunkirk Power LLC, dated June 11, 1999.(b)
10.22 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Dunkirk Power LLC, dated June 11, 1999.(b)
10.23 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Huntley Power LLC, dated June 11, 1999.(b)
10.24 Amendment to the Asset Sales Agreement by and between
Niagara Mohawk Power Corporation and NRG Energy, Inc., dated
June 11, 1999.(b)
10.25 Transition Capacity Agreement between Astoria Gas Turbine
Power LLC and Consolidated Edison Company of New York, Inc.,
dated June 25, 1999.(b)
10.26 Transition Capacity Agreement between Arthur Kill Power LLC
and Consolidated Edison Company of New York, Inc., dated
June 25, 1999.(b)
10.27 First Amendment to the Employment Agreement of David H.
Peterson, dated June 27, 1999.(b)
10.28 Second Amendment to the Employment Agreement of David H.
Peterson, dated August 26, 1999.(b)
10.29 Third Amendment to the Employment Agreement of David H.
Peterson, dated October 20, 1999.(b)
10.30 Swap Master Agreement between Niagara Mohawk Power
Corporation and
NRG Power Marketing, Inc., dated June 11, 1999.(b)
10.31 Standard Offer Service Wholesale Sales Agreement between the
Connecticut Light and Power Company and NRG Power Marketing,
Inc., dated October 29, 1999.(b)
10.32 364-day Revolving Credit Agreement among the Company and The
Financial Institutions party thereto, and ABN-AMRO Bank,
N.V., as Agent, dated as of March 10, 2000.(b)
10.33* Amended Agreement for the Sale of Thermal Energy between
Northern States Power and Norenco Corporation, dated January
1, 1983.
10.34* Operations and Maintenance Agreement between Northern States
Power and NRG, dated November 1, 1996.
</TABLE>

<PAGE> 154

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.35* Agreement for the Sale of Thermal Energy and Wood Byproduct
between Northern States Power and Norenco Corporation, dated
December 1, 1986.
10.36* Federal and State Income Tax Sharing Agreement between
Northern States Power Company and NRG Group, Inc., dated
April 4, 1991.
10.37* Support Agreement between Northern State Power Company and
CitiCorp USA Inc., dated March 27, 2000.
10.38* Administrative Services Agreement between Northern States
Power Company and NRG Thermal Corporation, dated January 1,
1992.
10.39** Form of Option Agreement with Northern States Power Company
10.40** Form of Registration Rights Agreement with Northern States
Power Company
10.41** Form of Long-Term Incentive Compensation Plan
10.42** Form of Indemnification Agreement
10.43** Form of Grant under the Long-Term Incentive Plan
21.1* Subsidiaries of NRG.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2** Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit
5.1)
24.1* Power of Attorney (included on signature page).
27.1 Financial Data Schedule.
</TABLE>

- ---------------

(a) Incorporated herein by reference to the Registrant's Registration Statement
on Form S-1, as amended, File No. 333-33397.

(b) Incorporated herein by reference to the Company's annual report on Form 10-K
for the year ended December 31, 1999.

(d) Incorporated herein by reference to the Company's current report on Form 8-K
dated November 16, 1999.

(e) Incorporated herein by reference to the Company's quarterly report on Form
10-Q for the quarter ended March 31, 1998.

* Previously filed

** To be filed

ITEM 17.

(a) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the registrant of expenses
incurred or paid by a director, officer or controlling person of the registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities begin
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.

(b) For purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of this
registration statement in reliance upon Rule 430A
<PAGE> 155

and contained in a form of prospectus filed by the registrant pursuant to Rule
242(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part
of this registration statement as of the time it was declared effective.

(c) For the purpose of determining any liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed to be
the initial bona fide offering thereof.

<PAGE> 156

SIGNATURES

Pursuant to the requirements of the Securities Act, the registrant has duly
caused this registration statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Minneapolis, State of
Minnesota, on May 8, 2000.

NRG ENERGY, INC.

/s/ JAMES J. BENDER
By:
--------------------------------------

Vice President, General Counsel
and Secretary

Pursuant to the requirements of the Securities Act, this registration
statement has been signed on May 8, 2000 by the following persons in the
respective capacities indicated opposite their names.

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ DAVID H. PETERSON* Chairman of the Board, President May 8, 2000
- --------------------------------------------- and Chief Executive Officer
David H. Peterson (Principal Executive Officer)

/s/ LEONARD A. BLUHM* Executive Vice President and Chief May 8, 2000
- --------------------------------------------- Financial Officer (Principal
Leonard A. Bluhm Financial Officer)

/s/ DAVID E. RIPKA* Controller (Principal Accounting May 8, 2000
- --------------------------------------------- Officer)
David E. Ripka

/s/ GARY R. JOHNSON* Director May 8, 2000
- ---------------------------------------------
Gary R. Johnson
</TABLE>

<PAGE> 157

<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ CYNTHIA L. LESHER* Director May 8, 2000
- ---------------------------------------------
Cynthia L. Lesher

/s/ EDWARD J. MCINTYRE* Director May 8, 2000
- ---------------------------------------------
Edward J. McIntyre

* By: /s/ JAMES J. BENDER May 8, 2000
- ---------------------------------------------
James J. Bender
Attorney-in-fact
</TABLE>

<PAGE> 158

EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
1.1** Underwriting Agreement.
3.1** Form of Amended and Restated Certificate of Incorporation.
3.2** Form of By-Laws.
4.1** Form of Common Stock Certificate
4.2 Indenture, dated as of June 1, 1997, between the Company and
Norwest Bank Minnesota, National Association.(a)
4.3 Loan Agreement, dated June 4, 1999 between Northeast
Generating LLC,
Chase Manhattan Bank and Citibank, N.A.(b)
4.4 Indenture between the Company and Norwest Bank Minnesota,
National Association, as Trustee dated as of May 25,
1999.(c)
4.5 Indenture between the Company and NRG Northeast Generating
LLC and The Chase Manhattan Bank, as Trustee dated as of
February 22, 2000.(b)
4.6 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70%
Remarketable or Redeemable Securities ("ROARS") due March
15, 2005.(b)
4.7 Trust Agreement between NRG Energy Inc. and The Bank of New
York, as Trustee, dated March 20, 2000.(b)
4.8 Indenture between NRG Energy Inc. and the Bank of New York,
as Trustee dated March 20, 2000, 160,000,000 pounds sterling
Reset Senior Notes due March 15, 2000.(b)
4.9 Indenture between the Company and Norwest Bank Minnesota,
National Association as Trustee dated as of November 8,
1999.(d)
4.10 Indenture, dated as of January 31, 1996, between the Company
and Norwest Bank Minnesota, National Association, As
Trustee.(a)
5.1** Opinion and Consent of Gibson, Dunn & Crutcher LLP,
regarding validity of Common Stock.
10.1 Employment Contract, dated as of June 28, 1995, between the
Company and
David H. Peterson.(a)
10.2 Note Agreement, dated August 20, 1993, among the Company
Energy Center, Inc. and each of the purchasers named
therein.(a)
10.3 Master Shelf and Revolving Credit Agreement, dated August
20, 1993 among the Company Energy Center, Inc., The
Prudential Insurance Registrants of America and each
Prudential Affiliate which becomes party thereto.(a)
10.4 Energy Agreement, dated February 12, 1988 between the
Company formerly known as Norenco Corporation) and Waldorf
Corporation (the "Energy Agreement").(a)
10.5 First Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.6 Second Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.7 Third Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.8 Construction, Acquisition, and Term Loan Agreement, dated
September 2, 1997 by the among NEO Landfill Gas, Inc., as
Borrower, the lenders named on the signature pages, Credit
Lyonnais New York Branch, as Construction/Acquisition Agent
and Lyon Credit Corporation as Term Agent.(a)
10.9 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
</TABLE>

<PAGE> 159

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.10 Construction, Acquisition, and Term Loan Agreement, dated
September 2, 1997 by and among Minnesota Methane LLC, as
Borrower, the lenders named on the signature pages, Credit
Lyonnais New York Branch, as Construction/Acquisition Agent
and Lyon Credit Corporation as Term Agent.(a)
10.11 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
10.12 Non Operating Interest Acquisition Agreement dated as of
September 12, 1997,
by and among the Company and NEO Corporation.(a)
10.13 Employment Agreements between the Company and certain
officers dated as of April 15, 1998.(e)
10.14 Wholesale Standard Offer Service Agreement between
Blackstone Valley Electric Company, Eastern Edison Company,
Newport Electric Corporation and NRG Power Marketing, Inc.,
dated October 13, 1998.(b)
10.15 Asset Sales Agreement by and between Niagara Mohawk Power
Corporation and NRG Energy, Inc., dated December 23,
1998.(b)
10.16 First Amendment to Wholesale Standard Offer Service
Agreement between Blackstone Valley Electric Company,
Eastern Edison Company, Newport Electric Corporation and NRG
Power Marketing, Inc., dated January 15, 1999.(b)
10.17 Generating Plant and Gas Turbine Asset Purchase and Sale
Agreement for the Arthur Kill generating plants and Astoria
gas turbines by and between Consolidated Edison Company of
New York, Inc., and NRG Energy, Inc., dated January 27,
1999.(b)
10.18 Transition Energy Sales Agreement between Arthur Kill Power
LLC and Consolidated Edison Company of New York, Inc., dated
June 1, 1999.(b)
10.19 Transition Power Purchase Agreement between Astoria Gas
Turbine Power LlC and Consolidated Edison Company of New
York, Inc., dated June 1, 1999.(b)
10.20 Transition Power Purchase Agreement between Niagara Mohawk
Power Corporation and Huntley Power LLC, dated June 11,
1999.(b)
10.21 Transition Power Purchase Agreement between Niagara Mohawk
Power Company and Dunkirk Power LLC, dated June 11, 1999.(b)
10.22 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Dunkirk Power LLC, dated June 11, 1999.(b)
10.23 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Huntley Power LLC, dated June 11, 1999.(b)
10.24 Amendment to the Asset Sales Agreement by and between
Niagara Mohawk Power Corporation and NRG Energy, Inc., dated
June 11, 1999.(b)
10.25 Transition Capacity Agreement between Astoria Gas Turbine
Power LLC and Consolidated Edison Company of New York, Inc.,
dated June 25, 1999.(b)
10.26 Transition Capacity Agreement between Arthur Kill Power LLC
and Consolidated Edison Company of New York, Inc., dated
June 25, 1999.(b)
10.27 First Amendment to the Employment Agreement of David H.
Peterson, dated June 27, 1999.(b)
10.28 Second Amendment to the Employment Agreement of David H.
Peterson, dated August 26, 1999.(b)
10.29 Third Amendment to the Employment Agreement of David H.
Peterson, dated October 20, 1999.(b)
</TABLE>

<PAGE> 160

<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.30 Swap Master Agreement between Niagara Mohawk Power
Corporation and
NRG Power Marketing, Inc., dated June 11, 1999.(b)
10.31 Standard Offer Service Wholesale Sales Agreement between the
Connecticut Light and Power Company and NRG Power Marketing,
Inc., dated October 29, 1999.(b)
10.32 364-day Revolving Credit Agreement among the Company and The
Financial Institutions party thereto, and ABN-AMRO Bank,
N.V., as Agent, dated as of March 10, 2000.(b)
10.33* Amended Agreement for the Sale of Thermal Energy between
Northern States Power and Norenco Corporation, dated January
1, 1983.
10.34* Operations and Maintenance Agreement between Northern States
Power and NRG, dated November 1, 1996.
10.35* Agreement for the Sale of Thermal Energy and Wood Byproduct
between Northern States Power and Norenco Corporation, dated
December 1, 1986.
10.36* Federal and State Income Tax Sharing Agreement between
Northern States Power Company and NRG Group, Inc., dated
April 4, 1991.
10.37* Support Agreement between Northern State Power Company and
CitiCorp USA Inc., dated March 27, 2000.
10.38* Administrative Services Agreement between Northern States
Power Company and NRG Thermal Corporation, dated January 1,
1992.
10.39** Form of Option Agreement with Northern States Power Company
10.40** Form of Registration Rights Agreement with Northern States
Power Company
10.41** Form of Long-Term Incentive Compensation Plan
10.42** Form of Indemnification Agreement
10.43** Form of Grant under the Long-Term Incentive Plan
21.1* Subsidiaries of NRG.
23.1 Consent of PricewaterhouseCoopers LLP.
23.2** Consent of Gibson, Dunn & Crutcher LLP (included in Exhibit
5.1)
24.1* Power of Attorney (included on signature page).
27.1 Financial Data Schedule.
</TABLE>

- ---------------

(a) Incorporated herein by reference to the Registrant's Registration Statement
on Form S-1, as amended, File No. 333-33397.

(b) Incorporated herein by reference to the Company's annual report on Form 10-K
for the year ended December 31, 1999.

(d) Incorporated herein by reference to the Company's current report on Form 8-K
dated November 16, 1999.

(e) Incorporated herein by reference to the Company's quarterly report on Form
10-Q for the quarter ended March 31, 1998.

* Previously filed

** To be filed

<PAGE> 1
Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the use in this Registration Statement on Form S-1 of
our report dated March 17, 2000, except as to Note 15 which is as of May 5,
2000, relating to the consolidated financial statements of NRG Energy, Inc., and
our report dated March 7, 2000 relating to the carve-out financial statements of
Cajun Electric, which appear in such Registration Statement. We also consent to
the references to us under the headings "Experts" and "Selected Financial Data"
in such Registration Statement.

PricewaterhouseCoopers LLP
Minneapolis, Minnesota
May 5, 2000