<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON APRIL 19, 2000
REGISTRATION NO. 333-
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------------------
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>
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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. [ ]
------------------------------------
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
PROPOSED MAXIMUM
TITLE OF EACH CLASS AGGREGATE AMOUNT OF
OF SECURITIES TO BE REGISTERED OFFERING PRICE(1) REGISTRATION FEE
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<S> <C> <C>
Common stock................................................ $600,000,000 $158,400
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</TABLE>
(1) Estimated solely for the purpose of computing the registration fee pursuant
to Rule 457(o) under the Securities Act.
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.
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<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 APRIL , 2000.
PROSPECTUS
SHARES
NRG ENERGY, INC.
COMMON STOCK
[NRG LOGO] $ PER SHARE
------------------
NRG Energy, Inc. is selling shares of its common stock. The
underwriters named in this prospectus may purchase up to 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 $ and $ per share.
We will apply to have the common stock listed on the under the
symbol " ."
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
% 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 .
Neither the Securities and Exchange Commission nor any other 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
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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............................................. 17
Dividend Policy............................................. 17
Capitalization.............................................. 18
Selected Consolidated Financial and Other Data.............. 19
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 21
Business.................................................... 29
Management.................................................. 63
Ownership of Capital Stock.................................. 72
Relationships and Related Transactions...................... 73
Description of Capital Stock................................ 75
Description of Indebtedness................................. 79
Shares Eligible for Future Sale............................. 84
Material United States Tax Consequences to Non-United States
Holders................................................... 85
Underwriting................................................ 87
Legal Matters............................................... 89
Experts..................................................... 89
Available Information....................................... 89
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 a :1 split
of our common stock, to be effective immediately prior to this offering, and
assumes that the underwriters have not exercised their option to purchase an
additional 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 .
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. We believe we are the second largest independent power generation
company in the United States and the seventh 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 Generating Capacity (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 capacity of approximately 3,300 MW.
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 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.
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 also one of the top three 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.
1
<PAGE> 6
MARKET OPPORTUNITY
The power industry is one of the largest industries in the world,
accounting for approximately $220 billion in annual revenues and having
approximately 730,000 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.
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 additional MW 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 provide an attractive domestic environment 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 OIL GAS OTHER
- ---- --- --- -----
<S> <C> <C> <C>
35 26.00 37.00 2.00
</TABLE>
DISPATCH LEVEL(3)
<TABLE>
<CAPTION>
PEAKING INTERMEDIATE BASELOAD
- ------- ------------ --------
<S> <C> <C>
41 19.00 40.00
</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
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 "baseload"
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
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 existing site
expansion projects and greenfield projects.
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 neither own nor do we intend to own any interest in nuclear generation
facilities.
Domestic. We intend to focus our near-term domestic development plans on
our existing three core markets, our Northeast, South Central and West Coast
regions, and add the Mid-Atlantic region as our fourth core market to be
established upon the closing of the 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 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, for a purchase price of $43 million, all of
its rights and obligations with respect to two 135 MW turbines being built for
it by Siemens Westinghouse. The two turbines are scheduled for delivery in the
first or second quarter of 2001.
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 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.
3
<PAGE> 8
KILLINGHOLME FACILITY
In March 2000, we acquired the Killingholme A plant 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, oil and jet fuel-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 will 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.
CORPORATE INFORMATION
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 are now 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.
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... shares(1)
Common stock to be
outstanding after the
offering.................... shares(2)
Class A common stock to be
outstanding after the
offering.................... shares(3)
Total common stock and class
A common stock to be
outstanding after the
offering.................... shares
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.......................
Proposed symbol............... " "
- ---------------
(1) Excludes 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 shares issuable upon the exercise of stock options
granted to our employees and non-employee directors under the NRG Long-Term
Incentive 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 are 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 dollar amounts are set forth in thousands, except 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 $ $
Equity in earnings of unconsolidated affiliates.... 26,200 81,706 67,500 67,500
Operating income (loss)............................ 18,109 57,012 109,520 189,665
Other income (expense)(2).......................... 11,371 9,379 14,970 13,100
Interest expense................................... (30,989) (50,313) (93,376) (166,624)
Income tax benefit(3).............................. 23,491 25,654 26,081 24,001
Net income (loss).................................. $ 21,982 $ 41,732 $ 57,195 $ 60,142 $ $
---------- ---------- ---------- --------- -------- --------
Earnings per share -- basic........................ $ $ $ $ $ $
Earnings per share -- diluted...................... $ $ $ $ $ $
Weighted average shares outstanding -- basic.......
Weighted average shares outstanding -- diluted.....
</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 $1,919,323 $
Total assets..................................... 1,168,102 1,293,426 3,431,684
Long-term recourse debt, including current
maturities..................................... 499,982 504,781 915,000
Long-term non-recourse debt, including
current maturities............................. 120,873 121,695 1,056,860
Stockholder's equity............................. 450,698 579,332 893,654
</TABLE>
<TABLE>
<CAPTION>
AS OF AS OF
DECEMBER 31, MARCH 31,
------------------------------------ ---------
1997 1998 1999 2000
---------- ---------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
OTHER GENERATION DATA
Net power generation capacity (MW)............... 2,637 3,300 10,990 13,664
</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.
6
<PAGE> 11
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. The wholesale power markets are unpredictable and
are subject to substantial price fluctuations over relatively short periods of
time.
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, 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
emissions 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 continue to effectively manage
this price volatility, and may not
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be able to successfully manage the other risks associated with trading in energy
markets, including the risk that counterparties 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. 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, and
- inability to negotiate acceptable acquisition, construction, fuel supply
or other material agreements.
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 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 WE GENERALLY DO NOT HAVE LONG-TERM FUEL SUPPLY AGREEMENTS.
Most of our domestic merchant power generation facilities 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. As a
result, 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
interests or in which we are or may be exploring development or acquisition
opportunities present risks of 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, that are greater than similar 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.
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, Australia wholesale power market 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 current power price
projections, 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 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 U.S.$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 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 50% of the ownership
interests. A substantial portion of our future investments in international
projects
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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 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.
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 % of the
total voting power of the common stock and the 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 of loans made to our foreign affiliates will be sufficient to
service our corporate-level indebtedness, there can be no assurance that these
funds will be sufficient to make corporate-level debt payments as and when due.
If we
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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 20 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 $557 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 WHICH 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 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 % of the total voting
power of the common stock and the 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
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.
Furthermore, we have adopted a "poison-pill" or investor rights plan designed to
make certain that offers for the shares of our common stock can be thoroughly
considered by all parties.
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. 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 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.
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
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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.
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 in 1992 also provides relief from regulation under PUHCA to exempt
wholesale generators ("EWGs") and foreign utility companies ("FUCOs").
Maintaining our status as a QF, EWG or FUCO is conditioned on our continuing to
meet statutory criteria, and could be jeopardized, for example, by the making of
retail sales by a project 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 foreign utility companies or are otherwise exempted under PUHCA;
thereafter, we will be subject to the regulations described in
"Business -- Energy Regulation in the United States."
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.
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 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. Currently, legislation is being
debated 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
geographical regions, our Connecticut facilities may be placed at a significant
competitive disadvantage.
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.
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
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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 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. 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 Title IV
of the Federal Clean Air Act permit requirements at seventeen utility generation
stations located in the southern and midwestern regions of the United States.
The United States Environmental Protection Agency 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. However, 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.
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
15
<PAGE> 20
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. These price limitations and other mechanisms may
adversely impact the profitability of our merchant plants. 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 % of our
total outstanding common equity and about % of total voting power and thus
will be able to exercise a controlling influence over our business.
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 will apply to have our common stock approved for listing on the
. 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 owns shares of class A common stock. The
class A common stock is 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 "Shares Eligible for Future Sale",
"Relationships and Related Transactions" and "Underwriting".
16
<PAGE> 21
USE OF PROCEEDS
The net proceeds from this offering are estimated to be approximately
. 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 in the foreseeable future.
17
<PAGE> 22
CAPITALIZATION
Capitalization is the amount invested in a company and is a common
measurement of a company's size. The table below shows our capitalization as of
December 31, 1999:
- on an actual basis;
- on a pro forma basis to reflect the acquisition of the Cajun facilities
in March 2000; and
- on a pro forma as adjusted basis to give effect to the acquisition of
the Cajun facilities and the sale of the shares of our common
stock offered by this prospectus at an assumed initial public offering
price of $ 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 shares of
our common stock under stock options granted to employees and non-employee
directors under the NRG Long-Term Incentive Plan. You should read this table in
conjunction with the consolidated financial statements and related notes that
are included in this prospectus.
<TABLE>
<CAPTION>
DECEMBER 31, 1999
-------------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
---------- ---------- -----------
(IN THOUSANDS EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
Cash and cash equivalents................................ $ 31,483 $ 31,483 $
Current portion of long-term debt........................ 30,462 30,426
Short-term debt:
Non-recourse (1)....................................... 35,766 35,766
Recourse(2)............................................ 340,000 628,000
Long-term debt
Non-recourse (1)....................................... 1,026,398 1,826,398
Recourse (2)........................................... 915,000 915,000
Stockholders' equity:
Preferred stock........................................ -- --
Common stock........................................... 1 1
Class A common stock................................... -- --
Additional paid-in capital............................. 781,913 781,913
Retained earnings...................................... 187,210 187,210
Accumulated other comprehensive income (loss)(3)....... (75,470) (75,470)
---------- ---------- -------
Total stockholders' equity............................. 893,654 893,654
---------- ---------- -------
Total capitalization................................ $3,272,763 $4,360,727 $
========== ========== =======
</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.
18
<PAGE> 23
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 dollar 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 $ $
Equity in earnings of
unconsolidated affiliates....... 28,639 32,815 26,200 81,706 67,500 67,500 8,667
------- ------- ------- -------- -------- -------- ------- ------- -------
Total operating revenues.......... 92,819 104,464 118,252 182,130 500,018 868,580 46,514
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations... 32,535 36,562 46,717 52,413 269,900 513,944 27,940
Depreciation and amortization..... 8,283 8,378 10,310 16,320 37,026 64,595 4,734
General, administrative, and
development..................... 34,647 39,248 43,116 56,385 83,572 100,376 15,985
------- ------- ------- -------- -------- -------- ------- ------- -------
Total operating costs and
expenses........................ 75,465 84,188 100,143 125,118 390,498 678,915 48,659
------- ------- ------- -------- -------- -------- ------- ------- -------
OPERATING INCOME (LOSS)........... 17,354 20,276 18,109 57,012 109,520 189,665 (2,145)
OTHER INCOME (EXPENSE)
Minority interest................. -- -- (131) (2,251) (2,456) (2,456) (464)
Other income, net(2).............. 29,746 9,477 11,502 11,630 17,426 15,556 734
Interest expense.................. (7,089) (15,430) (30,989) (50,313) (93,376) (166,624) (11,059)
------- ------- ------- -------- -------- -------- ------- ------- -------
Total other income (expense)...... 22,657 (5,953) (19,618) (40,934) (78,406) (153,524) (10,789)
------- ------- ------- -------- -------- -------- ------- ------- -------
INCOME (LOSS) BEFORE INCOME
TAXES........................... 40,011 14,323 (1,509) 16,078 31,114 36,141 (12,934)
INCOME TAX BENEFIT (EXPENSE)(3)... (8,810) 5,655 23,491 25,654 26,081 (24,001) 11,994
------- ------- ------- -------- -------- -------- ------- ------- -------
NET INCOME (LOSS)................. $31,201 $19,978 $21,982 $ 41,732 $ 57,195 $ 60,142 (940)
======= ======= ======= ======== ======== ======== ======= ======= =======
Earnings per share -- basic....... $ $ $ $ $ $
Earnings per share -- diluted..... $ $ $ $ $ $
Weighted average shares
outstanding -- basic............
Weighted average shares
outstanding -- diluted..........
</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 $1,919,323 $ 207,473
Net equity investments in
projects....................... 221,129 365,749 694,655 800,924 988,671 814,807
Total assets..................... 454,589 680,809 1,168,102 1,293,426 3,431,684 1,298,679
Long-term debt, including current
maturities..................... 90,034 212,141 620,855 626,476 1,971,860 498,019
Stockholder's equity............. 319,764 421,914 450,698 579,332 893,654 680,017
</TABLE>
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<PAGE> 24
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
Total debt to total capitalization ratio................... 22.0% 33.5% 57.9% 52.0% 72.4%
Ratio of recourse debt to recourse debt and equity......... 5.4% 30.9% 52.6% 46.6% 58.4%
Consolidated interest expense coverage ratio(5)............ 7.81x 2.47x 1.28x 1.64x 1.72x
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>
- ---------------
(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 includes 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 the sum of funds from operations plus interest
expense on recourse debt divided by interest expense on recourse debt. Funds
from operations is calculated by subtracting working capital changes from
cash provided (used) by operations.
(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.
20
<PAGE> 25
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. We have grown significantly during the last three years. During this
period, we have grown from a company deriving most of our revenues from our
interests in power generation investments in which we owned less than 50% and
from heating, cooling and thermal activities, to one of the largest independent
power generation companies in the United States (measured by MW of net ownership
interests in 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 to 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.
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<PAGE> 26
The following charts illustrate the sources of our domestic power
generation revenue (excluding thermal, resource recovery and NEO) 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
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%), while 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
22
<PAGE> 27
ownership and operation of our Northeast assets that were acquired during 1999
accounted for approximately $194.9 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 our NEO subsidiary.
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 our NEO subsidiary. 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 $7.3
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 on 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 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 $30.0 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 generate 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 are paid by Northern States Power on a
dollar-for-dollar basis for the reduction of Northern States Power's taxes
attributable to the tax benefits we create. We have recorded an income tax
benefit due to the recognition of Section 29 tax credits associated with our NEO
subsidiary, 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.
23
<PAGE> 28
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%), heating, cooling and thermal activities (46%), and
technical services (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 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 charge for our West Java, Indonesia project, 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.
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<PAGE> 29
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
is 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 December 31, 1999, our financing activities
provided cash totaling approximately $2,260 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 cash in operating activities.
Our use of cash in 1999 primarily related to ongoing working capital
requirements for new operations.
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 carefully 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.
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<PAGE> 30
In addition, we have a $500 million revolving credit facility 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:
- $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 L325 million
($517 million) 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 purpose of financing
the acquisition of the Killingholme facility and revolving credit and
letter of credit facilities (collectively, L90 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
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<PAGE> 31
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
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, which we expect to finance 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.
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 counterparties to such
derivative financial instruments. We have established controls to determine and
monitor the creditworthiness of counterparties in order to mitigate our exposure
to counterparty 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
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<PAGE> 32
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 $5.0 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 $5.0 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.
- 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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<PAGE> 33
BUSINESS
INTRODUCTION
We are a leading global energy company primarily engaged in the
acquisition, development, ownership and operation of power generation
facilities. We believe we are the second largest independent power generation
company in the United States and the seventh 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 Generating Capacity (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 includes MW
attributable to projects under construction, which totaled 383 MW as of
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.
We believe that our operational skills and experience gives us a strong
competitive position in the unregulated generation marketplace. 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. 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.
In addition to our power generation projects, we also have interests in
district heating and cooling systems and steam generation and 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 also one of the top three 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 $220 billion in annual revenues and approximately 730,000 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
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<PAGE> 34
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.
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 additional MW 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 provide an attractive domestic environment 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.
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 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 generation 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 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.
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<PAGE> 35
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 now the second largest district heating and cooling provider
in the United States, with operations in Minnesota, California and Pennsylvania,
and the third largest landfill gas operator in the United States.
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 Queensland Power Trading Corporation 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 31
Ronald J. Will................. Senior Vice President, Europe 11 39
</TABLE>
OUR INDEPENDENT POWER GENERATION BUSINESS
DOMESTIC
Our near-term domestic development plans are focused on core markets that
are considered to have attractive business fundamentals and where we believe we
have the ability to build 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
CAPACITY OUR NET
UNITED STATES REGIONS STATES OF OPERATION PRIMARY FUELS (MW) INTEREST (MW)
- --------------------- ------------------- -------------------- -------- -------------
<S> <C> <C> <C> <C>
Northeast...................... Connecticut, Maine, Gas, Coal, Jet Fuel, 7,602 7,099
Massachusetts, New and Oil
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 core
domestic 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.
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<PAGE> 36
The table that follows describes our existing international power
generation operations.
<TABLE>
<CAPTION>
TOTAL
CAPACITY OUR NET
GLOBAL MARKETS COUNTRIES OF OPERATION PRIMARY FUELS (MW) EQUITY (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
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 OIL GAS OTHER
- ---- --- --- -----
<S> <C> <C> <C>
35 26.00 37.00 2.00
</TABLE>
DISPATCH LEVEL(3)
<TABLE>
<CAPTION>
PEAKING INTERMEDIATE BASELOAD
- ------- ------------ --------
<S> <C> <C>
41 19.00 40.00
</TABLE>
- ---------------
(1) Based upon MW of net ownership interests as of March 31, 2000
(2) Several of our generation facilities, constituting approximately 3,900 MW of
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 "baseload"
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.
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 existing
expansion projects and greenfield projects.
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 neither own nor do we intend to own any interest in nuclear generation
facilities.
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<PAGE> 37
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 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 plans on our existing
three core markets, our Northeast, South Central, West Coast regions, and add
the Mid-Atlantic region as our fourth core market to be established upon closing
of the planned acquisition from Conectiv. In each of these markets, we believe
that attractive business fundamentals and growth opportunities exist that will
enable us to pursue a top three position in these markets. We will consider
domestic projects outside of these markets if we believe that a future market
opportunity exists to create a new core market or that the expected project
returns warrant our 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 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 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 contracts 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 as appropriate, by building facilities at
new sites within a market, also known as "greenfield development," or by
expanding or repowering of facilities at existing sites. 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 generation capacity outside of the
United States has been owned and controlled by governments. During the past
decade, however, many foreign governments have moved 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
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<PAGE> 38
awarding long-term contracts for energy and capacity to purchasers of 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 the 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. 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 ensure an appropriate balance of 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 continue to focus on other areas that are
consistent with our strategy.
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 expense, 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 project affiliate, 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.
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 to 9 years); and
- "transition" power purchase agreements with the former owners of
acquired facilities
(generally 3-5 years).
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<PAGE> 39
- 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.
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 group markets energy and
energy related commodities, including electricity, natural gas, oil, coal and
emissions 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 wholly-owned 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 emissions
allowances needed to operate these facilities.
We operate within strict limits, 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 and 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 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 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 and 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.
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<PAGE> 40
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. The NRG Power Marketing board 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 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 $1,250,000 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
counterparties, prior to the entering into transactions with such
counterparties.
Our risk management guidelines also require that our treasury department
approves in advance credit limits for all counterparties. That is, 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 merchant 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, and 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 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
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<PAGE> 41
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 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.
An example of our successful operating performance is our Gladstone
facility. Although we only own 37.5% of Gladstone, we are the sole operator of
this facility and receive an annual operating fee and an operating performance
bonus for achieving plant availability targets. We have earned performance
bonuses for each year since the privatization of the Gladstone 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 key 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 of
these regions are responsible for the full spectrum of development activities as
well as responsibility for asset optimization within each 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,
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 the 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
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<PAGE> 42
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 generation capacity in the Northeast
United States in New York, New Jersey, Connecticut, Massachusetts and
Pennsylvania. These generation facilities are well diversified in terms of
dispatch level (baseload, intermediate and peaking), fuel source (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. We have joined
several other independent power producers in New York in filing a claim with
FERC challenging the independent system operator's actions. If this claim is
unsuccessful, our revenues from ancillary services sold in the New York Power
Pool could be substantially reduced.
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.
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<PAGE> 43
The following table summarizes our Northeast generation facilities:
<TABLE>
<CAPTION>
OUR
OUR NET
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/Jet Fuel
Middletown, Connecticut............... NEPOOL/NYPP/ISO-NE 856 100.00% 856 Oil/Gas/Jet Fuel
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/Jet Fuel
Connecticut Jet Power, 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 equity interests 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 jet facilities
for $519 million.
The purchase prices for each of the facilities set forth below, other than the
Oswego and Somerset facilities, reflects an allocation of the purchase price
paid in the bundled transaction in which it 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 $84.9 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> 44
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 Facility. The Astoria facility was 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 later of (a) the earlier of (i) December 31,
2002 or (ii) 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, or (b) the end of the capability period immediately preceding the
capability period covered by the first auction for capacity sponsored by the
independent system operator in New York State.
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 $55.2 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 of the Middletown, Montville, Norwalk,
Devon, and Connecticut Jet 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. 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 from Connecticut
Light & Power Company in December 1999 for a purchase price of $92.5 million.
The Middletown facility, located in
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<PAGE> 45
Middetown, Connecticut, is a natural gas/oil-fired intermediate/peaking plant
consisting of four units with a total capacity of 856 MW.
Montville Facility. The Montville facility was acquired from Connecticut
Light & Power in December 1999 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 from Connecticut Light
& Power in December 1999 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 from Connecticut Light &
Power in December 1999 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 Jet Facilities. These six combustion turbine facilities were
acquired from Connecticut Light & Power in December 1999 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 UNITED STATES REGION
We own approximately 1,888 MW of generation 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 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
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 a $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.
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<PAGE> 46
The following table summarizes our South Central generation facilities:
<TABLE>
<CAPTION>
OUR OUR NET
TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- ----- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
Big Cajun I, Louisiana
Unit 1................................... Cooperatives/Municipals 110 100.00% 110 Gas
Unit 2................................... Cooperatives/Municipals 110 100.00% 110 Gas
Big Cajun II, Louisiana
Unit 1................................... Cooperatives/Municipals 575 100.00% 575 Coal
Unit 2................................... Cooperatives/Municipals 575 100.00% 575 Coal
Unit 3................................... Cooperatives/Municipals 575 58.00% 338 Coal
Sterlington, Louisiana(1).................. Various 200 100.00% 200 Gas
Rocky Road Power, Illinois(2).............. ECAR/MAIN 350 50.00% 175 Gas
Other(3)................................... Various 337 Various 55 Various
----- -----
Total.................................. 2,832 2,138
===== =====
</TABLE>
- ---------------
(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 equity interests 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 approximately $1,026 million for
these facilities. The Cajun facilities consist of 100% of two gas-fired,
intermediate/peaking electric generation units with a total capacity of 220 MW,
which we collectively refer to as "Big Cajun I," and two coal fired, baseload
power generation units with a total capacity of 1,150 MW and a 58% interest in a
third coal-fired, baseload 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 electric generating
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 account for 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 is a merchant facility that sells energy
into the ECAR and MAIN markets.
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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
with excess power from another unit. Dynegy is providing power marketing
services to West Coast Power.
In June 1999, West Coast Power financed a significant portion of the
purchase price for its assets with a 5-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. We, however, retain the right to participate in any
energy or ancillary services markets prior to being dispatched as a must-run
unit. 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 facilities:
<TABLE>
<CAPTION>
OUR OUR NET
TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- ------ --------- -------- ---------
<S> <C> <C> <C> <C> <C>
El Segundo Power, California................. Cal PX 1,020 50.00% 510 Gas
Encina, California........................... Cal PX/Must-run 965 50.00% 482 Gas
Long Beach Generating, California............ Cal PX 530 50.00% 265 Gas
San Diego Combustion Turbines, California.... Cal PX/Must-run 253 50.00% 127 Gas
Crockett Cogeneration, California............ PG&E 240 57.67% 138 Gas
Mt. Poso Cogeneration, California............ PG&E; 50 39.10% 19 Coal
Other(1)..................................... Various 93 Various 62 Various
------ -----
Total........................................ 3,151 1,603
====== =====
</TABLE>
- ---------------
(1) Includes our net equity interests in three small facilities.
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<PAGE> 48
El Segundo Generating 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 Generating 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 Generating 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.
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.
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<PAGE> 49
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.
<TABLE>
<CAPTION>
OUR
OUR NET
TOTAL 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 the largest independent power producer in Australia with a net
ownership interest of 1,312 MW. We intend to maintain our position in the market
through 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 assets:
<TABLE>
<CAPTION>
OUR OUR NET
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 $64.4 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.
45
<PAGE> 50
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 December 31,
1999, the two-year average equivalent availability factor was 87.7%.
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 owner 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 owner of Boyne
Smelters is 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 to 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 operator of the power station
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 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
46
<PAGE> 51
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, Australia wholesale power market 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 current power price
projections, 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 $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.
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 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 Limited, a
publicly traded company listed on the Australian Stock Exchange. 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
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<PAGE> 52
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 assets:
<TABLE>
<CAPTION>
OUR OUR NET
TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- ------ --------- -------- ---------
<S> <C> <C> <C> <C> <C>
Killingholme, UK............................ U.K. Electricity Grid 680 100.00% 680 Gas
Enfield, UK................................. U.K. Electricity Grid 396 25.00% 99 Gas
Schkopau Power Station, Germany............. VEAG 960 20.95% 200 Coal
MIBRAG mbH, Germany......................... WESAG/MIBRAG 110 33.33% 37 Coal
MIBRAG mbH, Germany......................... WESAG/MIBRAG 86 33.33% 29 Coal
MIBRAG mbH, Germany......................... WESAG/MIBRAG 37 33.33% 12 Coal
Kladno, Phase I, Czech Republic............. STE/Industrials 28 44.26% 12 Coal
Kladno, Phase II, Czech Republic............ STE/Industrials 345 44.50% 154 Coal/Gas
----- -----
Total..................................... 2,642 1,223
===== =====
</TABLE>
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 $370 million) for the costs of the
acquisition and L90 million (approximately $142 million) for letters of credit
and working capital needs. We are selling power from the facility into the
wholesale electricity market of England and Wales, and we intend to enter into
short and long term power contracts when we believe it to be advantageous to do
so. 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 power station.
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. In the future, we intend to enter into short- and long-term agreements
to sell a portion of the output from the Killingholme facility 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 $11.2 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
48
<PAGE> 53
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 results
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 operations include Profen, Zwenkau and Schleenhain with total
estimated reserves of 776 million metric tons, which is 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 a company called Energy Center Kladno, of which we own a
44.26% interest. The expansion project is held separately through ECK
Generating, a Czech limited liability company, of which we own a 44.5% interest.
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<PAGE> 54
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:
<TABLE>
<CAPTION>
OUR OUR NET
TOTAL OWNERSHIP INTEREST
NAME AND LOCATION OF FACILITY PURCHASER/POWER MARKET MW INTEREST (MW) FUEL TYPE
- ----------------------------- ---------------------- ------ --------- -------- ----------------
<S> <C> <C> <C> <C> <C>
COBEE, Bolivia.......................... Electropaz/ELF 219 49.10% 108 Hydro/Gas
Bulo Bulo, Bolivia...................... Bolivian Grid 87 30.00% 26 Gas
Latin Power Funds, Various.............. Various 772 Various 52 Gas/Coal/Oil/Geo
----- ---
Total................................. 1,078 186
===== ===
</TABLE>
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 an electricity supply contract with Electricidad de La Paz S.A., a Bolivian
distribution company ("Electropaz"), which expires in 2008 with Empresa de Luz
Fuerza Electrica de Oruro S.A. another Bolivian distribution company. All
payments under these contracts are made in United States dollars.
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 on May 1, 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 $180 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
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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 Estonia 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, one in Rybnik and the
other in Pak.
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
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
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
Hennepin Co. Energy Center,
Minnesota................. NA(2) 290 mmBtu/hr (85 MW) Leased MEC Customers
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
</TABLE>
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<TABLE>
<CAPTION>
ACQUISITION OUR OWNERSHIP ENERGY PURCHASER/
NAME AND LOCATION OF FACILITY DATE CAPACITY(1) INTEREST MSW SUPPLIER
- ----------------------------- ----------- ------------------------------- ------------- ---------------------------
<S> <C> <C> <C> <C>
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........ NA(2) MSW: 1,500 tons/day 0.00% 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 MW: 175 51.43% 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 these facilities on behalf of Northern States Power.
Minneapolis Energy Center. Minneapolis Energy Center provides steam to
approximately 90 customers and chilled water to approximately 35 customers in
downtown Minneapolis, Minnesota. Minneapolis Energy Center provides steam and
chilled water to its customers 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
System, 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 $70.7 million and loans to fund
development, construction and start-up amounted to $26.9 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 $20.4 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
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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 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 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
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. The Energy Policy Act laid the ground work for a competitive
wholesale market for electricity. Among other things, the Energy Policy Act
expanded the 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, the 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 the 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 and/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.
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FINANCING
We fund our projects with a combination of non-recourse debt and equity
contributions. Historically, equity contribution infused into a project
consisted of cash from operations, corporate-level debt and capital.
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.
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 agrees to undertake
liability. We have agreed to undertake limited financial support for certain of
our project subsidiaries 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.
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<PAGE> 59
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 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.
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
and ownership structure, and while we strive to take advantage of the
opportunities created by such changes, it is impossible to predict the impact of
those 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
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with FERC prior to commencement of wholesale sales or 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 we
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 foreign utility companies ("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. 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. In addition, 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 we will
be a subsidiary of the surviving entity, Xcel Energy. Xcel Energy will be
subject to the provisions of various energy-related laws
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and regulations, including regulation as a registered holding company under
PUHCA, and, in turn, we will be subject to constraints imposed by PUHCA. These
constraints include restrictions imposed upon aggregate investment by registered
holding companies in EWGs and FUCOs, financed by contributions or guarantees by
the parent holding company, pursuant to SEC regulation which limits 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 such
investment cap and the potential need to request SEC waivers of or increases in
the cap could delay any infusions of capital from Xcel Energy which we may need.
This delay could be increased by the fact that to obtain a waiver from the
Securities and Exchange Commission 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 Securities and Exchange Commission. 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.
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 (1) critical legislative initiatives which could
impact operation of our facilities and (2) proposed construction projects which
could subject us to stringent pollution controls imposed on "major
modifications" as defined under the Clean Air Act and/or changes in discharge
characteristics as defined under the Clean Water Act with the goal of achieving
compliance with (1) applicable regulations, (2) administrative consent orders,
and/or (3) variances from applicable air-quality-related regulations. Air
pollution controls, inclusive of clean fuel use, utilized at our projects meets
or exceeds emission limitations reflective of reasonably available control
technology.
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/or 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.
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Our plants are subject to a variety of regulations governing emissions of
oxides of nitrogen (NO(X)). We are installing pollution control equipment at our
Somerset facility to implement the "Consumers First" Agreement between Montaup
Electric Company and the Attorney General for the Commonwealth of Massachusetts
that requires the Somerset facility to reduce NO(X) emissions at Unit 6 to .15
lb/mmBtu by the year 2003. At the Encina facility, we anticipate installing
selective catalytic reduction (SCR) on at least two of the units at that
facility 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 subject to
NO(X) Budget Programs pursuant to which we are required to hold NO(X)
"allowances" that equal, for each "ozone season" (May 1 - 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 the "RECLAIM" trading
program, which is another emissions trading program designed to control NO(X).
We currently intend to install SCR on one of the units at the El Segundo
facility in order to assist with our compliance with the RECLAIM program. As for
our East Coast plants other than Somerset, we intend to implement a strategic
plan for the purchase of NO(X) allowances and/or reduction of NO(X) emissions
through the installation of pollution control equipment which best meets our
business objectives.
Title V of the Clean Air Act imposes federal requirements which dictate
that most of our fossil-fuel-fired generating 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 (NJDEP) as a result of the 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 have agreed to settle the outstanding
Administrative Orders with the NJDEP and have executed an Administrative Consent
Order (ACO) with the NJDEP in March 2000. The ACO requires us to pay a penalty
in the amount of $102,500 within 60 days of the execution of the ACO by both
parties. To our knowledge, the NJDEP has not yet executed the ACO.
As a result of alleged violations of opacity, or visible emission,
standards at the Huntley, Dunkirk and Oswego facilities, Niagara Mohawk (NiMo),
the former owner and operator of these facilities, was in the process of
negotiating a consent order with the NYDEC to resolve such violations at the
time we acquired these facilities. Under the terms of our asset purchase
agreements with NiMo, NiMo will be responsible for any and all exceedances which
occurred prior to the closing of the transactions contemplated in the asset
purchase agreements. 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 opacity standards. We
believe that almost all of the opacity exceedances 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 NYDEC regarding
this issue. We are also currently in discussions with NYDEC regarding issues of
alleged opacity exceedances at the Huntley facility.
The hazardous air pollutant provisions of the 1990 Clean Air Act Amendments
do not currently extend to the electric utility steam generating unit source
category. Section (112)(n)(1)(A) of the Clean Air Act, as amended, requires the
EPA to perform a study of the hazards to the public health reasonably
anticipated to occur as a result of emissions by electric utility steam
generating units of hazardous air pollutants after imposition of the
requirements of the 1990 Amendments. The results of the study were presented in
a Report to Congress on February 24, 1998. The regulatory determination is to be
made by December 15, 2000. In their final report, EPA stated that mercury is the
pollutant of greatest interest and the only pollutant for which additional
information was to be gathered. The EPA is collecting additional
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mercury-in-coal data from each coal-fired utility in the United States and
additional speciated mercury emissions data from a subset of these coal-fired
utilities. The data-gathering effort for the mercury-in-coal analyses commenced
January 1, 1999 and continued until December 31, 1999. It is expected that the
speciated stack testing will be completed by February 29, 2000. All final test
reports are due to the EPA by May 31, 2000.
Until studies of the emissions from such facilities are completed and
Congress either amends the Clean Air Act further or the EPA promulgates
regulations in connection therewith, the nature and extent to which federal
hazardous air pollutants emissions restrictions will apply to our facilities and
other electric utility steam generation units will remain uncertain.
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. Currently, legislation is being debated 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 (e.g.
market based emission trading between sources located across broad geographical
regions), our Connecticut facilities may be placed at a significant competitive
disadvantage.
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 Title IV
of the Federal Clean Air Act permit requirements 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
has received information requests from the EPA regarding the Deepwater and BL
England facilities that we have agreed to purchase. However, 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
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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. Costs related to renewal of the NPDES permits, e.g., conducting
studies related to thermal discharges and/or the entrainment/impingement of
fish, and/or, where applicable, costs related to complying with the terms of a
consent order have generally been included as part of the project's pro forma.
Where thermal discharges are known to be contentious, e.g., at Conectiv's Indian
River Plant, we budgeted in our pro forma capital projects to address such
concerns.
Congress has not recently undertaken efforts to re-authorize the Clean
Water Act. Even so, the conditions in NPDES permits have continued to tighten
with increased focus on toxic pollutant discharges, receiving water body
biological monitoring requirements, bioassay requirements, additional controls
on stormwater runoff, and water quality standards and enforcement provisions. If
the Clean Water Act is reauthorized and becomes more stringent, or the results
of studies demonstrate significant issues related to effluent toxicity, thermal
discharges and/or entrainment of impingment of fish, our facilities may be
required to retrofit existing wastewater treatment facilities to accommodate
removal of metals, install controls to reduce thermal discharges and/or to
modify the water intake/discharge structures. Based on past operating experience
and/or on the funds we have already budgeted to address known issues associated
with effluent discharges, we do not expect the impact of these additional
expenses to affect significantly the profitability of the facilities.
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.
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 often particularly 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;
- If existing generating facilities are to be sold or transferred to third
parties, procedures for doing so;
- Limitations on which customers may be served by independent power
producers;
- 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 nation'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
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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. Therefore, 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
our offices at 1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403,
under a five-year lease that expires in June 2002. Our thermal division leases
and operates the Hennepin County Energy Center.
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
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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.
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 over 20 years
in various financial positions with Northern States Power.
Keith G. Hilless has been Senior Vice President, Asia Pacific of NRG 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 of NRG, and President
and Chief Executive Officer of NRG Energy 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 NSP 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 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 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 NRG's parent company, Northern States Power and 6 years with NRG.
Mr. Hewitt joined NRG in 1994 as a member of the
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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., where she was responsible for various types of accounting and reporting.
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.
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.
BOARD OF DIRECTORS
Upon completion of this offering, our board of directors will consist of
nine directors, five of whom will be employees of Northern States Power and
three of whom will be unaffiliated, independent directors.
COMMITTEES OF THE BOARD OF DIRECTORS
Our board of directors has a compensation committee and an audit committee.
Compensation Committee. Following this offering, the members of our
compensation committee will be , , and . The
compensation committee reviews and makes recommendations to our board of
directors concerning salaries and incentive compensation for our officers and
employees. The compensation committee also will administer the NRG Long-Term
Incentive Plan.
Audit Committee. Following this offering, the members of our audit
committee will be , and . Our board of directors
has determined that each member of the audit committee is "independent," that
each member is "financially literate," and that each member has "accounting or
related financial management expertise." The audit committee reviews and
monitors our financial statements and accounting practices, makes
recommendations to our board of directors regarding the selection of independent
auditors and reviews 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-employee
directors are also entitled to participate in the NRG Long-Term Incentive Plan,
as described below. Prior to the offering we expect to issue options to purchase
shares of our common stock to each of our non-employee directors.
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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 214,160 107,341 5,162 50,075 15,275(4)
Senior Vice President, 1998 188,640 83,564 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.
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STOCK OPTION HOLDINGS
The following table sets forth information concerning fiscal year-end value
of unexercised options 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(1)
<TABLE>
<CAPTION>
NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED IN-THE-MONEY
UNEXERCISED OPTIONS/SARS AT FY-END 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 TABLE
As of January 1, 1999, pension benefits were changed. Prior to 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.
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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>
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. Will and Mr. Bender
have selected the pension equity program; all other Named Executives have
selected the traditional program.
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<PAGE> 73
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.
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.
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 directors
have participated in this plan. As part of the conversion to a stock
appreciation rights plan, the stock price will be determined as the average
closing price per share of our common stock for the last fifteen trading days of
the plan year.
NRG LONG-TERM INCENTIVE 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 as 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
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<PAGE> 74
to be authorized for issuance under the incentive plan is expected to be
approximately shares.
As of the completion of the offering, we intend to make stock option grants
under the incentive plan to our officers and other selected executives. These
awards and subsequent awards under the incentive plan will be targeted to be
competitive with equity-based awards in our industry. The initial options will
have an exercise price equal to the initial public offering price. Subsequent
awards, anticipated to be made annually, will have an option price at least
equal to the market price of our common stock on the date of grant. Options
generally will vest over a three-year period from date of grant. Each option
granted will expire at such time as the board of directors determines at the
time of grant; provided, however, that no option shall be exercisable later than
the tenth anniversary date of its grant. The total number of shares covered by
the initial awards is expected to be approximately shares.
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.
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<PAGE> 75
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 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> 76
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
shares of class A common stock. Upon completion of this offering,
class A common stock will constitute % of our total outstanding common equity
and about % of our total voting power. Upon completion of this offering,
common stock will constitute about % of our total outstanding stock and about
% of our total voting power.
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<PAGE> 77
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> 78
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 % of the outstanding common stock and
class A common stock on a combined basis.
REGISTRATION RIGHTS AGREEMENT
On 2000, we entered into a registration rights agreement with
Northern States Power, under which we have agreed 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 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 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> 79
DESCRIPTION OF CAPITAL STOCK
AUTHORIZED STOCK
The authorized capital stock of NRG consists of shares of common
stock, par value, shares of class A common stock,
par value and shares of preferred stock, 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 SHARES CLASS A COMMON SHARES
------------- ---------------------
<S> <C> <C>
Public Market................ Will be listed on the None.
, 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 any transfer
(including by way of merger,
consolidation or
reorganization) or if the
number of outstanding shares
of class A common stock drops
below shares.
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 (including by
way of merger, consolidation
or reorganization) or if the
number of outstanding shares
of class A common stock drops
below shares.
Reissuance................... Additional shares may be No additional shares may be
issued and redeemed shares issued, and shares redeemed
may be reissued. or 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
75
<PAGE> 80
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 other than our series A redeemable preferred stock. See "--
Rights Plan."
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 shares of class A common stock,
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
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<PAGE> 81
- 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,
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 % of the outstanding shares of
common stock, the affirmative vote of the holders of at least 80% of the
outstanding shares of common stock is required to amend the provisions of our
certificate of incorporation described above under "-- Advance Notice
Requirement 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 49% of the outstanding shares of common stock, by the affirmative
vote of the holders of a majority of the outstanding shares of common
stock; or
- after that date, by the affirmative vote of the holders of a least 80% of
the outstanding shares of common stock.
RIGHTS PLAN
We have declared a dividend on shares of common stock and class A common
stock for holders of record as of the closing date of this offering consisting
of the right to purchase shares of our series A redeemable preferred
stock for a purchase price equal to $ per share upon the occurrence of
a "triggering event." The triggering event is the acquisition by a person or
entity of shares of common stock, the result of which is that such person or
entity has beneficial ownership of % of more of the voting power of the
outstanding common stock, unless such acquisition was approved in advance by our
board of directors. The series A redeemable preferred stock, when issued, will
entitle the holder thereof to purchase shares of our common stock. The
rights may be redeemed by us at a price of $ per right. Our rights plan
makes it highly unlikely that any third party could acquire us without the
approval of our board of directors.
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;
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<PAGE> 82
- 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 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. Except for
an action recently brought by one of our stockholders against us and each of our
directors, 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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<PAGE> 83
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 the indentures have 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, 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 contain 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
proceedings 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 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) 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 $250 million aggregate
principal amount of certificates that represented an undivided beneficial
interest in the assets of the trust, which assets consist principally of the
7.97% Reset Senior Notes. Interest on the 7.97% Reset Senior Notes is payable
semiannually in arrears on each September 15 and March 15.
The 7.97% Reset Senior Notes are governed by the terms of an indenture. The
material terms of the indenture are described below. As a summary, the following
discussion necessarily omits many of the details of the indenture. A copy of the
indenture has been filed as an exhibit to the registration statement of which
this prospectus is a part.
CHANGE OF CONTROL
If a change of control (as defined in the indenture) occurs on or before
March 15, 2005 in L, we must make an offer to purchase all 7.97% Reset Senior
Notes then outstanding at a purchase price equal to 100% of their principal
amount plus accrued and unpaid interest plus a payment in U.S. dollars equal to
1% of the principal amount of trust certificates to be redeemed by the trust
pursuant to a similar change of
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control offer under the trust agreement. If a change of control occurs prior to
March 15, 2005, but after an event of default that results in the principal
amount of the 7.97% Reset Senior Notes being due and payable immediately, we may
be required to purchase all or a part of the notes at a price in U.S.$ 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 L 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 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 senior notes.
MANDATORY TENDER
We have entered into a Remarketing Agreement and a Call Agreement with 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
- 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 7.97%
Reset Senior Notes.
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
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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 shares of common
stock or 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 owns shares of class A common stock, which
represent % 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.
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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.....................................................
=======
</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 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
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sold by the underwriters or that an active trading market in the common stock
will develop and continue after this offering.
We will apply to have the common stock listed on the under
the symbol " ".
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
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 $ .
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. 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
.
At our request, the underwriters have reserved for sale, at the initial
public offering price, up to 5% of the shares offered hereby to be sold to some
of our employees, management and directors. The number of shares of our common
stock available for sale to the general public will be reduced to the extent
that those persons purchase the reserved shares. Any reserved shares not so
purchased will be offered to the general public on the same terms as the other
shares.
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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 registration statement,
and the exhibits and schedules thereto, which may be inspected without charge
and copied at prescribed rates at the Public Reference Section of the Commission
at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the
Commission's regional offices at 7 World Trade Center, Suite 1300, New York, New
York 10048, and Northwestern Atrium Center, 500 West Madison Street, Suite 140,
Chicago, Illinois 60661. 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.
89
<PAGE> 94
INDEX TO NRG ENERGY, INC. FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
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 Stockholders' Equity.............. F-6
Notes to Consolidated Financial Statements.................. F-7
INDEX TO PRO-FORMA FINANCIAL STATEMENTS
Introduction to Pro Forma Financial Statements.............. F-33
Pro Forma Balance Sheet..................................... F-34
Pro Forma Income Statement.................................. F-36
</TABLE>
CAJUN ELECTRIC (CAJUN FACILITIES)
INDEX TO CARVE-OUT FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE NO.
--------
<S> <C>
Independent Accountant's Report............................. F-37
Carve-Out Statement of Net Assets........................... F-38
Carve-Out Statement of Certain Revenue and Expenses......... F-39
Notes to Financial Statements............................... F-40
</TABLE>
F-1
<PAGE> 95
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
F-2
<PAGE> 96
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS EXCEPT PER
SHARE AMOUNTS)
<S> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations..................... $432,518 $100,424 $ 92,052
Equity in earnings of unconsolidated affiliates........... 67,500 81,706 26,200
-------- -------- --------
Total operating revenues and equity earnings........... 500,018 182,130 118,252
-------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations........................... 269,900 52,413 46,717
Depreciation and amortization............................. 37,026 16,320 10,310
General, administrative and development................... 83,572 56,385 43,116
-------- -------- --------
Total operating costs and expenses..................... 390,498 125,118 100,143
-------- -------- --------
OPERATING INCOME............................................ 109,520 57,012 18,109
-------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
subsidiary............................................. (2,456) (2,251) (131)
Gain on sale of interest in projects...................... 10,994 29,950 8,702
Write-off of project investments.......................... -- (26,740) (8,964)
Other income, net......................................... 6,432 8,420 11,764
Interest expense.......................................... (93,376) (50,313) (30,989)
-------- -------- --------
Total other expense.................................... (78,406) (40,934) (19,618)
-------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES........................... 31,114 16,078 (1,509)
INCOME TAX BENEFIT.......................................... (26,081) (25,654) (23,491)
-------- -------- --------
NET INCOME.................................................. $ 57,195 $ 41,732 $ 21,982
======== ======== ========
EARNINGS PER SHARE-BASIC AND DILUTED........................ $ 57,195 $ 41,732 $ 21,982
======== ======== ========
WEIGHTED AVERAGE SHARES OUTSTANDING-BASIC AND DILUTED....... 1,000 1,000 1,000
======== ======== ========
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE> 97
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income............................................... $ 57,195 $ 41,732 $ 21,982
Adjustments to reconcile net income to net cash provided
by operating activities
Undistributed equity in earnings of unconsolidated
affiliates.......................................... (27,181) (23,391) 6,481
Depreciation and amortization......................... 37,026 16,320 10,310
Deferred income taxes and investment tax credits...... (3,401) 7,618 3,107
Minority interest..................................... 857 (5,019) --
Investment write-downs................................ -- 26,740 8,964
Gain on sale of investments........................... (10,994) (29,950) (8,702)
Cash provided (used) by changes in certain working
capital items, net of effects from acquisitions and
dispositions
Accounts receivable................................. (99,608) 297 (2,859)
Accounts receivable-affiliates...................... 9,964 21,657 (19,963)
Accrued income taxes................................ 25,834 (24,861) 1,762
Inventory........................................... (17,287) (28) (307)
Other current assets................................ (13,433) 469 305
Accrued property and sales taxes.................... 1,740 (553) 1,645
Accounts payable.................................... 40,616 (8,082) 7,791
Accrued salaries, benefits, and related costs....... 1,955 4,735 3,826
Accrued interest.................................... 5,192 1,050 1,215
Other current liabilities........................... (3,533) (2,219) 6,084
Cash used by changes in other assets and
liabilities...................................... (16,322) (4,517) (7,155)
----------- --------- ---------
NET CASH (USED) PROVIDED BY OPERATING ACTIVITIES........... (11,380) 21,998 34,486
----------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Investments in projects............................... (163,340) (132,379) (318,149)
Acquisition, net of liabilities assumed............... (1,519,365) -- (148,830)
Consolidation of equity subsidiaries.................. 20,181 -- --
Cash from sale of project investment.................. 43,500 18,053 19,158
Decrease (increase) in notes receivable............... 58,331 16,858 (37,431)
Capital expenditures.................................. (94,853) (31,719) (26,936)
(Increase) decrease in restricted cash................ (13,067) (2,433) 16,100
Other, net............................................ -- -- 10,114
----------- --------- ---------
NET CASH USED BY INVESTING ACTIVITIES...................... (1,668,613) (131,620) (485,974)
----------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Net borrowings under line of credit agreement......... 216,000 2,000 122,000
Capital contributions from parent..................... 250,000 100,000 80,900
Proceeds from issuance of long-term debt.............. 575,633 23,169 254,061
Proceeds from issuance of note........................ 682,096 -- --
Principal payments on long-term debt.................. (18,634) (21,152) (5,925)
----------- --------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES.................. 1,705,095 104,017 451,036
----------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS....... 25,102 (5,605) (452)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR............. 6,381 11,986 12,438
=========== ========= =========
CASH AND CASH EQUIVALENTS AT END OF YEAR................... $ 31,483 $ 6,381 $ 11,986
=========== ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid (net of amount capitalized)............. $ 82,891 $ 49,089 $ 30,890
Income taxes paid (benefits received), net............ (54,384) (6,797) (24,577)
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE> 98
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------
1999 1998
---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 31,483 $ 6,381
Restricted cash........................................... 17,441 4,021
Accounts receivable-trade, less allowance for doubtful
accounts of $186 and $100............................... 126,376 15,223
Accounts receivable-affiliates............................ -- 7,324
Taxes Receivable.......................................... -- 21,169
Current portion of notes receivable -- affiliates......... 287 4,460
Current portion of notes receivable....................... -- 26,200
Inventory................................................. 119,181 2,647
Prepayments and other current assets...................... 29,202 4,533
---------- ----------
Total current assets.................................... 323,970 91,958
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST
In service................................................ 2,022,724 291,558
Under construction........................................ 53,448 5,352
---------- ----------
Total property, plant and equipment..................... 2,076,172 296,910
Less accumulated depreciation............................. (156,849) (92,181)
---------- ----------
Net property, plant and equipment....................... 1,919,323 204,729
---------- ----------
OTHER ASSETS
Investments in projects................................... 988,671 800,924
Capitalized project costs................................. 2,592 13,685
Notes receivable, less current portion -- affiliates...... 65,494 101,887
Notes receivable, less current portion.................... 5,787 3,744
Intangible assets, net of accumulated amortization of
$4,308 and $2,984....................................... 55,586 22,507
Debt issuance costs, net of accumulated amortization of
$6,640 and $1,675....................................... 20,081 7,276
Other assets, net of accumulated amortization of $8,909
and $7,350.............................................. 50,180 46,716
---------- ----------
Total other assets...................................... 1,188,391 996,739
---------- ----------
TOTAL ASSETS................................................ $3,431,684 $1,293,426
---------- ----------
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Current portion of project level long-term debt........... $ 30,462 $ 8,258
Revolving line of credit.................................. 340,000 --
Consolidated project level, non-recourse debt............. 35,766 --
Accounts payable-trade.................................... 61,211 7,371
Accounts payable-affiliate................................ 6,404 --
Accrued income taxes...................................... 4,730 --
Accrued property and sales taxes.......................... 4,998 3,251
Accrued salaries, benefits and related costs.............. 9,648 7,551
Accrued interest.......................................... 13,479 7,648
Other current liabilities................................. 17,657 8,289
---------- ----------
Total current liabilities............................... 524,355 42,368
OTHER LIABILITIES:
Minority interest......................................... 14,373 13,516
Consolidated project-level, long-term, non-recourse
debt.................................................... 1,026,398 113,437
Corporate level long-term debt, less current portion...... 915,000 504,781
Deferred Income Taxes..................................... 16,940 19,841
Deferred Investment Tax Credits........................... 1,088 1,343
Postretirement and other benefit obligations.............. 24,613 11,060
Other long-term obligations and deferred income........... 15,263 7,748
---------- ----------
Total liabilities....................................... 2,538,030 714,094
---------- ----------
STOCKHOLDER'S EQUITY
Common stock; $1 par value; 1,000 shares authorized; 1,000
shares issued and outstanding........................... 1 1
Additional paid-in capital................................ 781,913 531,913
Retained earnings......................................... 187,210 130,015
Accumulated other comprehensive income.................... (75,470) (82,597)
---------- ----------
Total Stockholder's Equity.............................. 893,654 579,332
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY.................. $3,431,684 $1,293,426
========== ==========
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE> 99
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
ACCUMULATED
ADDITIONAL OTHER TOTAL
COMMON PAID-IN RETAINED COMPREHENSIVE STOCKHOLDER'S
STOCK CAPITAL EARNINGS INCOME EQUITY
------ ---------- -------- ------------- -------------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
BALANCES AT DECEMBER 31, 1996.......... $1 $351,013 $ 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 $431,913 $ 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 $531,913 $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 $781,913 $187,210 $(75,470) $893,654
== ======== ======== ======== ========
</TABLE>
Other comprehensive income is shown net of tax expenses (benefits) which
were $0 during both 1999 and 1998 and $5.9 million in 1997.
See notes to consolidated financial statements.
F-6
<PAGE> 100
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.
F-7
<PAGE> 101
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 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
F-8
<PAGE> 102
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.
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.
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 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.
F-9
<PAGE> 103
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, 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 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
F-10
<PAGE> 104
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.
NOTE 4 -- PROPERTY, PLANT AND EQUIPMENT
The major classes of property, plant and equipment at December 31 were as
follows:
<TABLE>
<CAPTION>
1999 1998
---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C>
Facilities and equipment, including construction work
in progress of $53,448 and $5,352................... $2,000,541 $280,876
Land and improvements................................. 64,330 10,397
Office furnishings and equipment...................... 11,301 5,637
---------- --------
Total property, plant and equipment.............. 2,076,172 296,910
Accumulated depreciation.............................. (156,849) (92,181)
---------- --------
Net property, plant and equipment..................... $1,919,323 $204,729
========== ========
</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.
F-11
<PAGE> 105
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>
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Operating revenues....................................... $1,732,521 $1,491,197 $1,612,897
Costs and expenses....................................... 1,531,958 1,346,569 1,522,727
---------- ---------- ----------
Net income.......................................... $ 200,563 $ 144,628 $ 90,170
---------- ---------- ----------
Current assets........................................... $ 742,674 $ 710,159 $ 713,390
Noncurrent assets........................................ 7,322,219 7,938,841 7,733,886
---------- ---------- ----------
Total assets........................................ $8,064,893 $8,649,000 $8,447,276
---------- ---------- ----------
Current liabilities...................................... $ 708,114 $ 527,196 $ 472,980
Noncurrent liabilities................................... 5,168,893 5,854,284 6,042,102
Equity................................................... 2,187,886 2,267,520 1,932,194
---------- ---------- ----------
Total liabilities and equity........................ $8,064,893 $8,649,000 $8,447,276
NRG's share of equity.................................... $ 988,671 $ 800,924 $ 694,655
NRG's share of income.................................... $ 67,500 $ 81,706 $ 26,200
</TABLE>
In accordance with FASB No. 121 "Accounting for Impairment of 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.
F-12
<PAGE> 106
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 percent 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.
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.
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, 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.
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.
F-13
<PAGE> 107
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, are as follows:
<TABLE>
<CAPTION>
1999 1998
---- ----
(THOUSANDS OF DOLLARS)
<S> <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)............................................. 207 132
Various secured notes due 2000 and later, non-interest and
interest bearing.......................................... 224 723
NEO notes to various affiliates due primarily 2012, prime
+2% to 12.5%.............................................. 26,850 27,445
Southern MN Praireland Solid Waste, note due 2003, 7%....... 44 1,441
Pacific Generation, various notes, prime +2% to 12%......... 3,368 4,203
NRGenerating International BV notes to various affiliates,
non-interest bearing...................................... 40,410 34,234
O'Brien Cogen II note, due 2008, non interest bearing....... 465 --
------- --------
Total................................................ $71,568 $136,291
======= ========
</TABLE>
F-14
<PAGE> 108
NOTE 8 -- LONG-TERM DEBT
Long-term debt consists of the following at December 31:
<TABLE>
<CAPTION>
1999 1998
---- ----
(THOUSANDS OF DOLLARS)
<S> <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 --
O'Brien Cogen II due August 31, 2000, 9.5%.................. 2,893 --
NRG San Diego, Inc. promissory note, due June 25, 2003,
8.0%...................................................... 1,729 2,141
Pittsburgh Thermal LP -- Credit Line, due 2004, LIBOR
+4.25%.................................................... 1,100 --
San Francisco Thermal LP -- Credit Line, due 2004, LIBOR
+4.25%.................................................... 900 --
Pittsburgh Thermal LP, due 2002-2004, 10.61%-10.73%......... 6,800 --
San Francisco Thermal LP, October 5, 2004, 10.61%........... 5,905 --
NRG Energy senior notes, due February 1, 2006, 7.625%....... 125,000 125,000
Note payable to NSP, due December 1, 1995-2006,
5.40%-6.75%............................................... 6,495 7,174
NRG Energy senior notes, due June 15, 2007, 7.50%........... 250,000 250,000
Camas Power Boiler LP, unsecured term loan, due June 30,
2007, 7.65%............................................... 17,087 17,576
Camas Power Boiler LP, revenue bonds, due August 1, 2007,
4.65%..................................................... 9,130 11,010
Various NEO debt due 2005-2008, 9.35%....................... 28,615 --
NRG Energy senior notes, due June 1, 2009, 7.50%............ 300,000 --
NRG Energy Center, Inc. senior secured notes due June 15,
2013, 7.31%............................................... 68,881 71,783
NRG Energy senior notes, due Nov. 1, 2013, 8.00%............ 240,000 --
Crockett Corp. LLP, due Dec. 31, 2014, 8.13%................ 255,000 --
NRG Northeast Generating debt............................... 646,564 --
---------- --------
1,971,860 626,476
Less current maturities..................................... (30,462) (8,258)
---------- --------
Total................................................ $1,941,398 $618,218
========== ========
</TABLE>
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.
F-15
<PAGE> 109
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 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 percent 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, NRG South Central Generating LLC, a subsidiary of the
Company, issued $800 million of senior secured bonds in a two-part offering. The
first tranche was for $500 million with a coupon of 8.962 percent and a maturity
of 2016. The second tranche was for $300 million with a coupon
F-16
<PAGE> 110
of 9.479 percent and a maturity of 2024. The proceeds will be used to finance
the Company's investment in the Cajun generating facilities.
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 AU$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.
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>
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Current
Federal................................................ $ 3,620 $(10,773) $ (8,516)
State.................................................. 1,041 (3,940) (1,274)
Foreign................................................ 4,040 2,358 236
-------- -------- --------
8,701 (12,355) (9,554)
Deferred
Foreign................................................ (7,668) (7,736) (2,703)
Federal................................................ (2,792) 8,828 (958)
State.................................................. (3,901) 1,541 (439)
-------- -------- --------
(14,361) 2,633 (4,100)
Tax credits recognized................................... (20,421) (15,932) (9,837)
-------- -------- --------
Total income tax (benefit).......................... $(26,081) $(25,654) $(23,491)
======== ======== ========
Effective tax rate....................................... (84)% (160)% (1,557)%
</TABLE>
F-17
<PAGE> 111
The components of the net deferred income tax liability at December 31
were:
<TABLE>
<CAPTION>
1999 1998
---- ----
(THOUSANDS OF
DOLLARS)
<S> <C> <C>
Deferred tax liabilities
Differences between book and tax basis of property........ $37,713 $29,712
Investments in projects................................... 17,308 14,911
Goodwill.................................................. 1,117 978
Other..................................................... 5,544 6,212
------- -------
Total deferred tax liabilities............................ 61,682 51,813
Deferred tax assets
Deferred revenue.......................................... 841 1,402
Deferred compensation, accrued vacation and other
reserves............................................... 10,996 6,514
Development costs......................................... 6,768 9,241
Deferred investment tax credits........................... 450 661
Steam capacity rights..................................... 844 910
Foreign tax benefit....................................... 20,919 12,425
Other..................................................... 3,924 819
------- -------
Total deferred tax assets................................. 44,742 31,972
------- -------
Net deferred tax liability................................ $16,940 $19,841
======= =======
</TABLE>
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
F-18
<PAGE> 112
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>
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Service cost benefits earned................................ $ 1,602 $ 1,303 $ 1,127
Interest cost on benefit obligation......................... 1,739 1,417 1,187
Expected return on plan assets.............................. (2,866) (2,226) (1,029)
Amortization of prior service cost.......................... 393 172 5
Recognized actuarial (gain) loss............................ (2,053) (1,878) (3)
------- ------- -------
Net periodic (benefit) cost............................... $(1,185) $(1,212) $ 1,287
======= ======= =======
</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 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>
1999 1998
-------------------------- -------------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Benefit obligation at Jan. 1................. $ 1,143,464 $ 20,112 $1,048,251 $17,410
Service cost................................. 36,421 1,602 31,643 1,303
Interest cost................................ 86,429 1,739 78,839 1,417
Plan amendments.............................. 184,255 2,214 102,315 3,045
Actuarial gain............................... (105,634) (178) (41,635) (2,278)
Benefit payments............................. (97,086) (1,200) (75,949) (785)
----------- -------- ---------- -------
Benefit obligation at Dec. 31.............. $ 1,247,849 $ 24,289 $1,143,464 $20,112
=========== ======== ========== =======
Fair value of plan assets at Jan. 1.......... $ 2,221,819 39,079 $1,978,538 $18,795
Actual return on plan assets................. 293,904 9,199 319,230 21,069
Benefit payments............................. (97,086) (1,200) (75,949) (785)
----------- -------- ---------- -------
Fair value of plan assets at Dec. 31....... $ 2,418,637 $ 47,078 $2,221,819 $39,079
=========== ======== ========== =======
Funded status at Dec. 31 -- excess of assets
over obligation............................ $ 1,170,788 $ 22,789 $1,078,355 $18,967
Unrecognized transition (asset) obligation... (311) -- (387) --
Unrecognized prior service cost.............. 277,350 4,775 114,305 2,954
Unrecognized net gain........................ (1,381,889) (26,944) (1,167,340) (22,486)
----------- -------- ---------- -------
Accrued (prepaid) benefit obligation at Dec.
31......................................... $ 65,938 $ 620 $ 24,933 $ (565)
=========== ======== ========== =======
</TABLE>
AMOUNT RECOGNIZED IN THE BALANCE SHEET
<TABLE>
<CAPTION>
1999 1998
----------------------- -----------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Prepaid benefit cost............................. $65,938 $ 868 $24,933 $ --
Accrued benefit liability........................ -- (248) -- (565)
------- ----- ------- -----
Net amount recognized -- asset
(liability)............................... $65,938 $ 620 $24,933 $(565)
======= ===== ======= =====
</TABLE>
F-19
<PAGE> 113
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.
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.
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.
F-20
<PAGE> 114
The Company's net annual periodic benefit cost under SFAS No. 106 includes
the following components:
COMPONENTS OF NET PERIODIC BENEFIT COST
<TABLE>
<CAPTION>
1999 1998 1997
---- ---- ----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Service cost benefits earned................................ $ 9 $165 $223
Interest cost on benefit obligation......................... 24 145 246
Amortization of transition asset............................ -- 17 70
Amortization of prior service cost.......................... (104) (40) --
Recognized actuarial (gain) loss............................ (34) 2 --
----- ---- ----
Net periodic (benefit) cost............................ $(105) $289 $539
===== ==== ====
</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.
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>
1999 1998
------------------------ ------------------------
NSP PLAN NRG PORTION NSP PLAN NRG PORTION
-------- ----------- -------- -----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Benefit obligation at Jan. 1................... $ 219,762 $ 1,517 $ 279,230 $ 3,893
Service cost................................... 196 9 3,247 165
Interest cost.................................. 9,184 24 15,896 145
Plan amendments................................ (80,840) (770) (51,456) (1,872)
Actuarial gain loss............................ 8,269 (359) (9,732) (814)
Benefit payments............................... (16,637) -- (17,423) --
--------- ------- --------- -------
Benefit obligation at Dec. 31............. $ 139,934 $ 421 $ 219,762 $ 1,517
========= ======= ========= =======
Fair Value of plan assets at Jan. 1............ $ 34,514 $ -- $ 19,783 $ --
Actual return on plan assets................... 3,982 -- 2,471 --
Employer contributions......................... 13,339 -- 29,683 --
Benefit payments............................... (16,637) -- (17,423) --
--------- ------- --------- -------
Fair value of plan assets at Dec. 31...... $ 35,198 $ -- $ 34,514 $ --
========= ======= ========= =======
Funded status at Dec. 31 -- unfunded
obligation................................... $(104,736) $ (421) $ 185,248 $ 1,517
Unrecognized transition obligation............. 22,073 -- (104,482) --
Unrecognized prior service cost................ (2,926) (1,452) 2,399 786
Unrecognized net gain (loss)................... 10,580 (562) (3,790) 237
--------- ------- --------- -------
Accrued (liability) benefit recorded at Dec.
31........................................... $ (75,009) $(2,435) $ 79,375 $ 2,540
========= ======= ========= =======
</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,
F-21
<PAGE> 115
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 percent of the Company's benefit employees are
represented by eight local labor unions under collective bargaining agreements,
which expire between 2000 and 2003.
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>
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<PAGE> 116
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.
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.
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<PAGE> 117
NOTE 12 -- FINANCIAL INSTRUMENTS
The estimated December 31 fair values of the Company's recorded financial
instruments are as follows:
<TABLE>
<CAPTION>
1999 1998
----------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Cash and cash equivalents.......................... $ 31,483 $ 31,483 $ 6,381 $ 6,381
Restricted cash.................................... 17,441 17,441 4,021 4,021
Notes receivable, including current portion........ 71,568 71,568 136,291 136,291
Long-term debt, including current portion.......... 1,971,860 1,931,969 502,476 519,418
</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.
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.
- 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.
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.
F-24
<PAGE> 118
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>
The Company expects to invest approximately $2.7 billion in 2000 and
approximately $4.7 billion for the five-year period 2000 - 2004 for nonregulated
projects and property, which include acquisitions and projects investments. The
Company's capital requirements for 2000 reflect expected acquisitions of
existing generation facilities, 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 20 million pounds 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 percent 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.
F-25
<PAGE> 119
The Company has contractually agreed to the monetization of certain tax
credits generated from landfill gas sales through the year 2007.
Future capital commitments related to projects are as follows:
<TABLE>
<CAPTION>
(MILLIONS OF
DOLLARS)
------------
<S> <C>
2000........................................................ $2,700
2001........................................................ 500
2002........................................................ 500
2003........................................................ 500
2004........................................................ 500
------
Total..................................................... $4,700
======
</TABLE>
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.
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.
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
F-26
<PAGE> 120
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. 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
F-27
<PAGE> 121
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 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
F-28
<PAGE> 122
"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 S02 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. 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 legislation that would
require older electrical generating stations to comply with more stringent
pollution standards for NO(X) and SO(2) emissions. During the 1999 legislative
session, the Connecticut House of Representatives voted in favor of such
legislation. The House bill was referred to the Energy Technology Committee
where no action was taken. Similar legislation has been introduced as part of
the 2000 legislative session.
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 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.
F-29
<PAGE> 123
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-30
<PAGE> 124
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>
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.................................... 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.......................................... $ 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.................................... 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.......................................... $ 73,405 $ 13,427 $ 6,600 $(51,700) $ 41,732
</TABLE>
F-31
<PAGE> 125
<TABLE>
<CAPTION>
INDEPENDENT
POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
----------- ----------- ------- ----- -----
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
1997
OPERATING REVENUES
Revenues from wholly-owned operations(a).......... $ 5,339 $ 27,257 $48,604 $ 9,926 $ 91,126
Intersegment revenues............................. -- 926 -- -- 926
Equity in earnings of unconsolidated
affiliates(b)................................... 26,206 (192) 186 -- 26,200
-------- -------- ------- -------- --------
Total operating revenues................... 31,545 27,991 48,790 9,926 118,252
-------- -------- ------- -------- --------
OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations................... 1,693 17,730 24,902 2,392 46,717
Depreciation and amortization..................... 483 2,842 6,623 362 10,310
General, administrative, and development.......... 8,186 6,111 2,403 26,416 43,116
-------- -------- ------- -------- --------
Total operating costs and expenses......... 10,362 26,683 33,928 29,170 100,143
-------- -------- ------- -------- --------
OPERATING INCOME.................................... 21,183 1,308 14,862 (19,244) 18,109
-------- -------- ------- -------- --------
OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated
Subsidiary...................................... (131) (131)
Write-off of investment........................... (8,964) (8,964)
Gain on sale of interest in projects.............. 1,559 7,143 8,702
Other income, net................................. 5,888 2,618 (14) 3,272 11,764
Interest expense.................................. (653) (529) (5,958) (23,849) (30,989)
-------- -------- ------- -------- --------
Total other income (expense)............... (2,301) 2,089 (5,972) (13,434) (19,618)
-------- -------- ------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES................... 18,882 3,397 8,890 (32,678) (1,509)
INCOME TAX (BENEFIT)................................ (6,502) (4,888) 3,165 (15,266) (23,491)
-------- -------- ------- -------- --------
NET INCOME.......................................... $ 25,384 $ 8,285 $ 5,725 $(17,412) $ 21,982
</TABLE>
- ---------------
(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.
F-32
<PAGE> 126
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 presents the combination of NRG and the
Cajun Electric facilities as if the acquisition occurred on January 1, 1999. 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-33
<PAGE> 127
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..................... 2,022,724 1,208,832 451,647(A) 3,683,203
Under construction............. 53,448 3,996 57,444
---------- ---------- ---------- ---------- ----------
Total property, plant and
equipment................. 2,076,172 1,212,828 451,647 -- 3,740,647
Less accumulated
depreciation................ (156,849) (632,899) (789,748)
---------- ---------- ---------- ---------- ----------
Net property, plant and
equipment................. 1,919,323 579,929 451,647 -- 2,950,899
---------- ---------- ---------- ---------- ----------
OTHER ASSETS
Investments in projects........ 988,671 988,671
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.......... 1,188,391 4,188 -- -- 1,192,579
---------- ---------- ---------- ---------- ----------
TOTAL ASSETS..................... $3,431,684 $ 653,793 $ 451,647 $ -- $4,537,124
========== ========== ========== ========== ==========
</TABLE>
F-34
<PAGE> 128
<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 STOCKHOLDERS
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
Common stock; $1 par value;
1,000 shares authorized;
1,000 shares issued and
outstanding................. 1 1
Additional paid-in capital..... 781,913 636,353 636,353(C) 781,913
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 $1,088,000 $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.
(C) Reflects elimination of Cajun Electric equity.
(D) Reflects short-term borrowings used to fund the acquisition of the Cajun
facilities.
F-35
<PAGE> 129
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..................... (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-36
<PAGE> 130
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-37
<PAGE> 131
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-38
<PAGE> 132
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-39
<PAGE> 133
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-40
<PAGE> 134
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-41
<PAGE> 135
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-42
<PAGE> 136
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-43
<PAGE> 137
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-44
<PAGE> 138
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-45
<PAGE> 139
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 five-year 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.
Louisiana Generating LLC has entered into a five-year 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-46
<PAGE> 140
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-47
<PAGE> 141
INSIDE BACK COVER PAGE
NRG ENERGY, INC. PROJECT LIST
<TABLE>
<CAPTION>
CAPACITY OWNERSHIP
PROJECT LOCATION (MW) (NET MW)
- ------- -------------------------------------------- -------- ---------
<S> <C> <C> <C>
NORTHEAST REGION
Osweg, 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 remote jets, Connecticut................................. 127.4 127.4
Kingston Cogeneration, Kingston, Ontario, Canada............................. 110.0 27.5
Parlin Cogen, Parlin, NJ.................................. 122.0 24.4
Cadillac, Cadillac, MI................................ 39.0 19.5
Grays Ferry Cogen, Grays Ferry, PA............................. 150.0 15.0
Newark Cogen, Newark, NJ.................................. 54.0 10.8
Penobscot Energy Recovery, Orrington, ME............................... 25.3 7.3
Curtis-Palmer Hydroelectric, Corinth, NY................................. 58.3 5.0
Philadelphia Cogen, Philadelphia, PA............................ 22.0 3.7
Maine Energy Recovery, Biddeford, ME............................... 22.0 3.6
Turners Falls, Turners Falls, MA**......................... 20.1 1.8
7,602.0 7,099.0
NEO, Various Locations........................... 175.0 90.0
Other Investors Fund - Domestic, Various.......... 999.0 10.0
Total North America............................... 14,759.0 10,940.0
Total Worldwide, Existing and Under
Construction................................ 23,660.0 13,664.0
SOUTH CENTRAL REGION
Louisiana Generating LLC, Baton Rouge, LA............................. 1,945.0 1,708.5
Sterlington, Sterlington, LA ***......................... 200.0 200.0
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
</TABLE>
<PAGE> 142
<TABLE>
<CAPTION>
CAPACITY OWNERSHIP
PROJECT LOCATION (MW) (NET MW)
- ------- --------------------------------------------- -------- ---------
<S> <C> <C> <C>
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
Artesia (Calif. Cogen), Artesia, CA.................................. 34.0 34.0
Mt. Poso, Bakersfield, CA.............................. 49.5 19.5
San Joaquin Valley Energy, Chowchilla, CA**............................. 43.0 19.4
Jackson Valley Energy, Ione, CA**................................... 16.0 8.0
3,151.0 1,603.0
2,832.0 2,138.0
</TABLE>
<TABLE>
<CAPTION>
CAPACITY OWNERSHIP
PROJECT LOCATION (MW) (NET MW)
- ------- --------------------------------------------- -------- ---------
<S> <C> <C> <C>
EUROPE
Killingholme, 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 77.7
Energy Center Kladno, Kladno, Czech Republic....................... 28.0 12.4
-------- --------
2,642.0 1,223.0
International Asia-Pacific
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
Energy Developments, Ltd., Various Locations............................ 274.0 79.1
-------- --------
4,146.0 1,312.0
Latin America
Bolivian Power Company, Bolivia...................................... 219.2 108.4
Scudder Latin American Power, Various Locations............................ 772.0 51.2
Bulo Bulo, Bolivia ***.................................. 87.0 26.1
1,078.0 186.0
Energy Investors Fund - Various Locations............................ 1,035.0 3.0
Total International, Total........................................ 8,901.0 2,724.0
======== ========
</TABLE>
- ---------------
* Includes 69 megawatts on deactivated reserve
** Operations are suspended
*** Facilities under construction
<PAGE> 143
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
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> 144
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> 145
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
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
1.1* Underwriting Agreement.
3.1 Certificate of Incorporation.(a)
3.2 By-Laws.(a)
4.1 Indenture, dated as of June 1, 1997, between the Company and
Norwest Bank Minnesota, National Association.(a)
</TABLE>
<PAGE> 146
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
4.2 Loan Agreement, dated June 4, 1999 between Northeast
Generating LLC,
Chase Manhattan Bank and Citibank, N.A.(b)
4.3 Indenture between the Company and Norwest Bank Minnesota,
National Association, as Trustee dated as of May 25,
1999.(c)
4.4 Indenture between the Company and NRG Northeast Generating
LLC and The Chase Manhattan Bank, as Trustee dated as of
February 22, 2000.(b)
4.5 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70%
Remarketable or Redeemable Securities ("ROARS") due March
15, 2005.(b)
4.6 Trust Agreement between NRG Energy Inc. and The Bank of New
York, as Trustee, dated March 20, 2000.(b)
4.7 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)
4.8 Indenture between the Company and Norwest Bank Minnesota,
National Association as Trustee dated as of November 8,
1999.(d)
4.9 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> 147
<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> 148
<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.
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 current report on Form
10-K for the year ended December 31, 1999.
(c) Incorporated herein by reference to the Company's current report on Form 8-K
dated May 25, 1999.
(d) Incorporated herein by reference to Exhibit 4.1 to the Company's current
report on Form 8-K dated November 16, 1999.
(e) Incorporated herein by reference to Exhibit 10.17 on Form 10-Q for the
quarter ended March 31, 1998.
* To be filed by amendment
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 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> 149
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 April, 18, 2000.
NRG ENERGY, INC.
/s/ JAMES J. BENDER
By:
--------------------------------------
Vice President, General Counsel
and Secretary
POWER OF ATTORNEY
KNOW BY ALL MEN THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Leonard A. Bluhm and James J. Bender, and each of
them, his true and lawful attorneys-in-fact and agents, with full power of
substitution and resubstitution for him and in his name, place and stead, in any
and all capacities to sign any and all amendments (including post-effective
amendments) to this Registration Statement, and to file the same, with all
exhibits thereto, and other documents in connection therewith, including,
without limitation, any registration statement filed pursuant to Rule 462 under
the Securities Act of 1933, as amended, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents, and each of them,
full power and authority to do and perform each and every act and thing
requisite or necessary to be done in and about the premises, as fully to all
intents and purposes as he might or could do in person, hereby ratifying and
confirming all that each of said attorneys-in-fact and agents or any of them or
their or his substitute or substitutes, may lawfully do or cause to be done by
virtue hereof.
Pursuant to the requirements of the Securities Act, this registration
statement has been signed on April 18, 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 April 18, 2000
- --------------------------------------------- and Chief Executive Officer
David H. Peterson (Principal Executive Officer)
/s/ LEONARD A. BLUHM Executive Vice President and Chief April 18, 2000
- --------------------------------------------- Financial Officer (Principal
Leonard A. Bluhm Financial Officer)
/s/ DAVID E. RIPKA Controller (Principal Accounting April 18, 2000
- --------------------------------------------- Officer)
David E. Ripka
/s/ GARY R. JOHNSON Director April 18, 2000
- ---------------------------------------------
Gary R. Johnson
</TABLE>
<PAGE> 150
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<C> <S> <C>
/s/ CYNTHIA L. LESHER Director April 18, 2000
- ---------------------------------------------
Cynthia L. Lesher
/s/ EDWARD J. MCINTYRE Director April 18, 2000
- ---------------------------------------------
Edward J. McIntyre
</TABLE>
<PAGE> 151
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
1.1* Underwriting Agreement.
3.1 Certificate of Incorporation.(a)
3.2 By-Laws.(a)
4.1 Indenture, dated as of June 1, 1997, between the Company and
Norwest Bank Minnesota, National Association.(a)
4.2 Loan Agreement, dated June 4, 1999 between Northeast
Generating LLC,
Chase Manhattan Bank and Citibank, N.A.(b)
4.3 Indenture between the Company and Norwest Bank Minnesota,
National Association, as Trustee dated as of May 25,
1999.(c)
4.4 Indenture between the Company and NRG Northeast Generating
LLC and The Chase Manhattan Bank, as Trustee dated as of
February 22, 2000.(b)
4.5 NRG Energy Pass-Through Trust 2000-1, $250,000,000 8.70%
Remarketable or Redeemable Securities ("ROARS") due March
15, 2005.(b)
4.6 Trust Agreement between NRG Energy Inc. and The Bank of New
York, as Trustee, dated March 20, 2000.(b)
4.7 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)
4.8 Indenture between the Company and Norwest Bank Minnesota,
National Association as Trustee dated as of November 8,
1999.(d)
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 Indenture, dated as of January 31, 1996, between the Company
and Norwest Bank Minnesota, National Association, As
Trustee.(a)
10.3 Note Agreement, dated August 20, 1993, among the Company
Energy Center, Inc. and each of the purchasers named
therein.(a)
10.4 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)
10.5 Energy Agreement, dated February 12, 1988 between the
Company formerly known as Norenco Corporation) and Waldorf
Corporation (the "Energy Agreement").(a)
10.6 First Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.7 Second Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.8 Third Amendment to the Energy Agreement, dated August 27,
1993.(a)
10.9 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)
10.10 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
10.11 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)
</TABLE>
<PAGE> 152
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.12 Guaranty, dated September 12, 1997 by the Company in favor
of Credit Lyonnais New York Branch as agent for the
Construction/Acquisition Lenders.(a)
10.13 Non Operating Interest Acquisition Agreement dated as of
September 12, 1997,
by and among the Company and NEO Corporation.(a)
10.14 Employment Agreements between the Company and certain
officers dated as of April 15, 1998.(e)
10.15 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)
10.16 Asset Sales Agreement by and between Niagara Mohawk Power
Corporation and NRG Energy, Inc., dated December 23,
1998.(b)
10.17 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)
10.18 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)
10.19 Transition Energy Sales Agreement between Arthur Kill Power
LLC and Consolidated Edison Company of New York, Inc., dated
June 1, 1999.(b)
10.20 Transition Power Purchase Agreement between Astoria Gas
Turbine Power LlC and Consolidated Edison Company of New
York, Inc., dated June 1, 1999.(b)
10.21 Transition Power Purchase Agreement between Niagara Mohawk
Power Corporation and Huntley Power LLC, dated June 11,
1999.(b)
10.22 Transition Power Purchase Agreement between Niagara Mohawk
Power Company and Dunkirk Power LLC, dated June 11, 1999.(b)
10.23 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Dunkirk Power LLC, dated June 11, 1999.(b)
10.24 Power Purchase Agreement between Niagara Mohawk Power
Corporation and Huntley Power LLC, dated June 11, 1999.(b)
10.25 Amendment to the Asset Sales Agreement by and between
Niagara Mohawk Power Corporation and NRG Energy, Inc., dated
June 11, 1999.(b)
10.26 Transition Capacity Agreement between Astoria Gas Turbine
Power LLC and Consolidated Edison Company of New York, Inc.,
dated June 25, 1999.(b)
10.27 Transition Capacity Agreement between Arthur Kill Power LLC
and Consolidated Edison Company of New York, Inc., dated
June 25, 1999.(b)
10.28 First Amendment to the Employment Agreement of David H.
Peterson, dated June 27, 1999.(b)
10.29 Second Amendment to the Employment Agreement of David H.
Peterson, dated August 26, 1999.(b)
10.30 Third Amendment to the Employment Agreement of David H.
Peterson, dated October 20, 1999.(b)
10.31 Swap Master Agreement between Niagara Mohawk Power
Corporation and
NRG Power Marketing, Inc., dated June 11, 1999.(b)
10.32 Standard Offer Service Wholesale Sales Agreement between the
Connecticut Light and Power Company and NRG Power Marketing,
Inc., dated October 29, 1999.(b)
</TABLE>
<PAGE> 153
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<C> <S>
10.33 364-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)
10.34 Amended Agreement for the Sale of Thermal Energy between
Northern States Power and Norenco Corporation, dated January
1, 1983.
10.35 Operations and Maintenance Agreement between Northern States
Power and NRG, dated November 1, 1996.
10.36 Agreement for the Sale of Thermal Energy and Wood Byproduct
between Northern States Power and Norenco Corporation, dated
December 1, 1986.
10.37 Federal and State Income Tax Sharing Agreement between
Northern States Power Company and NRG Group, Inc. dated
April 4, 1991.
10.38 Support Agreement between Northern State Power Company and
CitiCorp USA Inc., dated March 27, 2000.
10.39 Administrative Services Agreement between Northern States
Power Company and NRG Thermal Corporation, dated January 1,
1992.
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 current report on Form
10-K for the year ended December 31, 1999.
(c) Incorporated herein by reference to the Company's current report on Form 8-K
dated May 25, 1999.
(d) Incorporated herein by reference to Exhibit 4.1 to the Company's current
report on Form 8-K dated November 16, 1999.
(e) Incorporated herein by reference to Exhibit 10.17 on Form 10-Q for the
quarter ended March 31, 1998.
* To be filed by amendment
<PAGE> 1
EXHIBIT 10.34
AMENDED AGREEMENT FOR THE SALE OF THERMAL ENERGY BETWEEN
NORTHERN STATES POWER COMPANY AND NORENCO CORPORATION
This Agreement, effective as of the first day of January, 1983, between
Northern States Power Company, a Minnesota corporation (hereinafter referred to
as "NSP") and Norenco Corporation, a Minnesota corporation (hereinafter referred
to as "NORENCO"), a wholly owned subsidiary of NSP, such parties hereinafter
referred to individually as "party" or collectively as "parties", supersedes and
replaces the original agreement between the parties which was executed on
February 8, 1983.
WITNESSETH
Whereas, NSP owns and operates the High Bridge Steam-Electric
Generatinq Plant located in St. Paul, Minnesota comprising boilers B9, B10,
B11 and B12 which supply steam to turbine-generators T3, T4, T5 and T6,
respectively. Boiler B9 or B10 can serve either turbine T3 or T4; and
WHEREAS, NSP desires to sell steam to NORENCO from boilers B9 and B10,
and NORENCO desires to purchase such steam from NSP to resell to Champion
International Corporation (hereinafter "Champion") which owns and operates a
paper mill in Saint Paul, Minnesota, pursuant to a steam supply agreement dated
August 30, 1982; and
WHEREAS, it is the intention of NSP and NORENCO that NORENCO reimburse
NSP for all of NSP's incremental costs associated with the sale of steam to
NORENCO.
<PAGE> 2
NOW THEREFORE, in consideration of the mutual covenants, stipulations
and agreements herein contained, the parties hereby covenant, stipulate and
agree as follows:
I. Term-Effective Date
1.1 This Agreement shall be effective on January 1, 1983, and
shall extend through December 31, 2002.
II. Conditions of Service
2.1 Steam sales from NSP's High Bridge Plant to NORENCO
normally will be interrupted within two hours after any oil-fired peaking is
required on NSP's system to meet system capacity requirements. Under system
emergencies as determined by NSP System Operations, boilers B9 and B10 will be
released immediately for electric generation.
2.2 At NSP's option, NORENCO may purchase steam from NSP after
any such oil-fired peaking is required. NORENCO will then reimburse NSP for the
incremental cost associated with replacement energy.
2.3 NORENCO shall make all modifications, adjustments, and
additions to NSP's existing boilers, pipes, valves, meters, controls, coal
handling and storage systems, buildings, yards, tracks and all other equipment
and machinery (collectively called Generating Equipment) at the High Bridge
Plant necessary to produce steam of the quality specified and in the quantity
required by this Agreement, (herein sometimes referred to as Useable Steam).
2.4 NORENCO shall obtain all necessary franchises, licenses,
permits, rights of way or easements and purchase,
2
<PAGE> 3
construct and install a transmission system which will connect boilers B9 and
B10 to the Champion paper mill. The transmission system (herein called the
Supply Line) shall include all pipes, pumps, valves, meters, controls, wires,
insulation and other equipment necessary to:
(a) transport Useable Steam from the High Bridge Plant to the
Champion paper mill.
(b) transport condensate and make-up water of the quality and
in the quantity required by this Agreement from the paper mill to the High
Bridge Plant; and
(c) provide for control of steam and communications between the
High Bridge Plant and the paper mill.
2.5 Throughout the Term of this Agreement NORENCO shall obtain, renew,
and maintain all licenses, permits and other governmental authorizations
necessary to furnish steam through the Supply Line. NSP shall use its best
efforts to change rules, regulations, laws or ordinances which would prevent NSP
from furnishing steam hereunder.
2.6 Throughout the Term of this Agreement NSP shall own, operate,
maintain, repair, and adjust the Generating Equipment. NSP will not purchase any
equipment not required for electric generation.
2.7 Throughout the Term of this Agreement, NORENCO shall own and pay
for the incremental cost of the operation, maintenance, repair and adjustment of
NORENCO-purchased equipment installed on NSP property. At NORENCO's cost, NSP
3
<PAGE> 4
shall, throughout the Term of this Agreement, operate, maintain and repair
NORENCO-purchased equipment installed on NSP property.
2.8 NORENCO shall not, by reason of this Agreement or the termination
of this Agreement or the payments made pursuant to this Agreement, acquire title
or ownership in or to the generating equipment of the High Bridge Plant.
2.9 NSP shall use its best efforts to produce and deliver to NORENCO
and NORENCO shall use its best efforts to purchase and accept from NSP all of
NORENCO's steam requirements at the Champion paper mill during the Term;
provided, however:
(a) NSP shall not be required to produce and deliver nor shall
NORENCO be required to purchase and accept more than 4,000,000 Million BTU's of
Useable Steam during any fiscal year;
(b) NSP shall use its best efforts to produce and deliver and
NORENCO shall use its best efforts to purchase and accept the Annual minimum
quantity of Useable Steam each fiscal year. The Annual Minimum quantity is
expected to be 2,640,000 million BTU's; and
(c) NSP shall use its best efforts to produce and deliver steam
for at least 347 days per year. NSP and NORENCO shall use their best efforts to
coordinate inspections, maintenance and repairs to their respective facilities.
2.10 All steam produced and delivered from boiler B9 or B10 shall meet
the following specifications when
4
<PAGE> 5
measured at the delivery point:
(a) Temperature: 790 degrees F with variations required for
load control.
(b) Pressure: 850 pounds per square inch gauge (PSIG) with
variations required for load control.
(c) Steam flow rate shall be from 250,000 pounds per hour to
430,000 pounds per hour.
2.11 Delivery point as used in Article II of this Agreement shall be
the point where the steam exits the steam conditioning valve and enters the
Supply Line at High Bridge.
2.12 During each fiscal year of the Term of this Agreement, NORENCO
shall provide 100% of the water necessary to produce steam for NORENCO at the
High Bridge Plant by delivering to NSP the condensate return water. (NORENCO
shall pay for the water to initiate steam production.) NORENCO shall return the
condensate in a condition acceptable for 850 PSIG boilers.
III. Billing
3.1 NSP will bill NORENCO by the 20th of the month following the month
in which the costs were incurred. Each month's bill shall be increased by 1% to
cover handling costs, working capital and miscellaneous costs.
3.2 NORENCO will pay NSP no later than 10 days following the date of
NSP's bill. Interest shall accrue on payments which are overdue at the daily
commercial prime rate in effect at the Northwestern National Bank of Minneapolis
from the date that interest first accrues.
5
<PAGE> 6
3.3 NSP will provide NORENCO with a cost component schedule along with
its bill similar to that shown in Table 1.
3.4 The total monthly cost billed shall be calculated pursuant to
Article IV of this Agreement.
IV. Cost of Service
For any steam delivered to NORENCO by NSP, the following costs shall be
recovered by NSP from NORENCO. The calculation of these costs includes the use
of coefficients which are to be updated at least annually by NSP. The costs
recovered by NSP are to be reviewed annually by NSP to ensure that the
provisions of this Agreement recover all appropriate costs. Corrections to
billings will be made if it can be demonstrated by either party to the other
party's satisfaction that the monthly payments made by NORENCO to NSP are in
error by at least plus or minus 1%. Any corrections to billings will be
consistent with the incremental cost approach.
4.1 Fuel Cost
4.1.1 NORENCO will provide NSP with a monthly estimate of steam
to be produced and delivered from the NSP High Bridge Plant to satisfy NORENCO
thermal energy requirements. The nature and timing of these estimates will be
specified in writing by NSP.
4.1.2 NSP will determine the amount of coal required to produce
the quantities of steam identified in paragraph 4.1.1. The quantities of coal so
calculated and schedules proposed to deliver such quantities will be provided to
NORENCO.
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4.1.3 Any quantities of coal identified in Section 4.1 will not
decrease the quantities of coal available for NSP electric generation from long
term coal supply agreements executed for the purpose of supplying coal for
electric generation.
4.1.4 The coal required to produce steam for the benefit of
NORENCO may be stored in the NSP High Bridge coal storage area.
4.1.5 NSP will provide to NORENCO monthly fuel inventory
reports for fuel used to produce steam for sale to NORENCO. These reports will
include beginning of month coal on hand for NORENCO, coal delivered during the
month for NORENCO, coal consumed during the month for NORENCO and coal on hand
at the end of the month for NORENCO. These reports will be in a format shown in
Table 2.
4.1.6 NORENCO will pay NSP for the actual cost per MMBTU of
coal (including retroactive adjustment) as delivered to High Bridge for NORENCO.
The cost per MMBTU will be determined from the delivered cost per ton and the
heat value of the coal as determined by NSP's Fuel Supply Department and NSP's
Coal Testing Laboratory. NORENCO will reimburse NSP for any adjustments charged
to NSP for fuel quality and for High Bridge coal handling charges for NORENCO
coal.
4.2 Incremental Maintenance Cost
Each month, NORENCO shall pay NSP for the cost
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of incremental maintenance as calculated using NSP Power Production's
incremental maintenance coefficient.
4.3 Incremental Auxiliary Cost
Each month, NORENCO shall pay NSP for the cost of incremental auxiliary
electrical power useage at High Bridge as calculated using the average
incremental system generation cost for that month.
4.4 Incremental No Load Maintenance Cost
4.4.1. Each month, for those hours that boiler B9 is in thermal
only service by NORENCO, NORENCO shall pay NSP the incremental cost of no load
maintenance as calculated using NSP Power Production's no load operation and
maintenance coefficient.
4.4.2 Each month, for those hours that boiler B10 is in thermal
only service by NORENCO, NORENCO shall pay NSP the incremental cost of no load
maintenance as calculated using NSP Power Production's no load operation and
maintenance coefficient.
4.5 Incremental No Load Auxiliaries
4.5.1 Each month, for those hours boiler B9 is in thermal only
service for NORENCO, NORENCO shall pay NSP an amount equal to that month's
average system incremental generation cost times that month's no load electrical
consumption by boiler B9.
4.5.2 Each month, for those hours boiler B10 is in thermal only
service for NORENCO, NORENCO shall pay NSP an amount equal to that month's
average system incremental
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generation cost times that month's no load electrical consumption by boiler
B10.
4.6 Ash Disposal
4.6.1 Ash disposal costs for High Bridge are accumulated in
FERC Account 152 (NSP Account 61.01.36).
4.6.2 The monthly charges to account 61.01.36 will be prorated
between NORENCO and NSP on the basis of monthly coal burned for NORENCO and coal
burned for electric generation at High Bridge as reported per Table 2. This
charge shall also include an incremental ash disposal site development cost for
NORENCO ash.
4.7 Energy Management System Costs
4.7.1 Replacement Energy
4.7.1.1 The cost of replacement energy is calculated as the
difference in the cost of NSP generation and purchases to supply NSP native
requirements with and without the supply of steam to NORENCO. The change in NSP
generation cost will include the changes in fuel and maintenance for startup and
hours of operation, and the incremental ash disposal cost. The change in billing
cost for purchases with and without the supply of steam to NORENCO will also be
used in the calculation.
4.7.1.2. Without NORENCO's thermal requirements, less efficient
units may be dispatched prior to the use of Units 3 and 4 at High Bridge. With
NORENCO's thermal requirements, when NSP interrupts thermal service for
electrical production on Units 3 and 4, energy costs may be avoided by NSP
because these units are available immediately.
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This credit will be reflected appropriately in determining replacement energy
costs.
4.7.1.3 The cost of replacement energy shall be calculated
using NSP System Operation's computer program. The capacity effect on either
turbine T3 or T4 shall be considered hourly by that program. The capacity effect
of turbines T3 and T4 shall reflect actual plant conditions as evaluated by NSP
Power Production.
4.7.2 Sales of Electricity for Resale
NORENCO will be charged monthly for incremental costs associated with
the loss of the opportunity to sell electricity for resale due to NORENCO's
thermal requirements. This incremental cost is the estimated lost revenues from
sales for resale from High Bridge Units 3 and 4 minus the estimated avoided
electrical production costs, had this energy been generated at High Bridge Units
3 and 4.
4.8 Flame Stabilization
4.8.1 NORENCO will be charged for any incremental flame
stabilization due to thermal operations. For oil flame stabilization the cost
will be calculated as follows:
Cost = Gallons of oil used for x Oil cost per
NORENCO flame stabilization gallon
4.8.2 For gas flame stabilization, the cost will be calculated
as follows:
Cost = Millions of Btu of gas x Gas cost per
used for NORENCO flame million Btu
stabilization.
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4.8.3 The High Bridge Plant will report monthly the gallons of oil
and the millions of Btu's of gas used for flame stabilization for thermal only
service on boilers B9 and B10.
4.9 Incremental Operating Cost
Any additional overtime or operating personnel shall be reported and
charged to NORENCO.
4.10 Thermal Equipment Operation and Maintenance
Any operation or maintenance of thermal only equipment (equipment
installed for thermal use only) will be charged on separate work orders to
NORENCO.
4.11 Standby No Loads
If NORENCO desires an additional boiler on line for backup, the no
load costs specified in 4.4 and 4.5 will be charged to NORENCO for those hours
that the backup boiler is used for thermal only service.
4.12 Supply of Gas or Oil
If NSP supplies any oil or natural gas to NORENCO, NORENCO shall
reimburse NSP for replacement cost of that oil or natural gas including
appropriate carrying and handling charges.
4.13 Cold Start Credits and Costs
Since NORENCO's use of boilers B9 and B10 for thermal service to
Champion will result in considerably fewer boiler cold starts than otherwise
would be the case, the cost credit associated with such reduction in cold starts
will be assumed to offset any startup costs of boilers B9 and B10
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caused by NORENCO.
4.14 Administrative and General Costs
Administrative and general costs are covered by the Administrative
Services Agreement dated January 1, 1983, and any amendments thereto, between
NSP and NORENCO.
V. LIABILITY
5.1 NORENCO shall hold harmless and indemnify NSP from any and all claims,
loss, damage or liability, including injury to and death of persons, caused
directly or indirectly by the steam or the use of NORENCO's facilities after the
delivery of steam to NORENCO other than those resulting solely from the
negligence of NSP or its agents or employees (excluding persons assigned to
NORENCO on a full-time basis). NSP likewise shall hold harmless and indemnify
NORENCO from any and all claims, loss, damage or liability, including injury to
and death of persons, caused directly or indirectly by steam or the use of NSP's
facilities before the delivery of steam to NORENCO other than those resulting
solely from the negligence of NORENCO or its agents or employees (including
those persons assigned to NORENCO on a full-time basis).
5.2 Notwithstanding any other provision of this Agreement, neither NSP nor
NORENCO in any event shall be liable to the other, whether arising under
contract, tort (including negligence), or otherwise, for claims of customers or
any other third parties, or for loss of use of capital or revenue, or for loss
of anticipated profits, or for
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any other special, indirect, incidental or consequential loss or damage of any
nature arising at any time or from any cause whatsoever
5.3 No provision of this Agreement shall in any way inure to the benefit
of any third person including the public at large) so as to constitute any such
person a third party beneficiary of this Agreement or of any one or more of the
terms hereof, or otherwise give rise to any cause of action in any person not a
party hereto.
5.4 The provisions of this section shall apply notwithstanding any other
provisions of this Agreement or of any other agreement.
5.5 The provisions of this section and of any other sections of this
Agreement providing for limitation of or protection against liability shall
apply to the full extent permitted by law and regardless of fault and shall
survive the expiration or termination of this Agreement.
VI. CONTINUITY OF SERVICE
6.1 NSP shall not be liable to NORENCO for its failure to deliver steam,
and NORENCO shall not be liable to NSP for its failure to receive steam, when
such failure on the part of either party shall be due to accident to or breakage
of pipelines or equipment, fires, floods, storms, weather conditions, strikes,
lockouts or other industrial disturbances, riots, legal interference, acts of
God or public enemy, shutdowns for necessary repairs and maintenance, or,
without limitation by enumeration, any other
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cause beyond the reasonable control of the party failing to deliver or receive
steam provided such party shall promptly and diligently take such action as may
be necessary and practicable under the then existing circumstances to remove the
cause of failure and resume the delivery or receipt of steam.
Furthermore, NSP shall not be liable for its failure to deliver steam
provided that such failure is (i) due to any scheduled or unscheduled
maintenance shutdown of boilers B9 and/or B10 or (ii) due to operating
conditions on boiler B9 or B10 and turbine T3 or T4 that warrant curtailment of
the delivery of steam to NORENCO. NSP shall have the sole right to determine
when those conditions exist. NSP and NORENCO shall cooperate with each other
regarding maintenance and steam service curtailment, and shall use their best
efforts to coordinate inspections, maintenance and repairs to their respective
facilities. NSP shall provide NORENCO with as much advance notice as possible of
scheduled interruption or curtailment of steam service.
VII MISCELLANEOUS
7.1 This Agreement shall bind and inure to the benefit of the respective
successors and assigns of the parties hereto, and any reference to any of the
parties hereto shall be deemed to include all successors and assigns.
Notwithstanding the foregoing, no assignment shall relieve a party of its duties
and obligations to the other party under
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<PAGE> 15
this Agreement if the assignee defaults in such duty or obligation, unless such
other party consents to the novation in writing.
7.2 Unless designated otherwise in writing, all notices from NORENCO to
NSP shall be delivered to:
D. E. Gilberts
Senior Vice President-Power Supply
Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
Unless designated otherwise in writing, all notices from NSP to NORENCO
shall be delivered to:
H.S. Wick, Jr.
Vice President
Norenco Corporation
414 Nicollet Mall
P.O. Box 1396
Minneapolis, MN 55440
7.3 All payments and reimbursements required to be made by NORENCO to NSP
pursuant to this Agreement shall be directed to:
Manager, General Accounting
Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
7.4 The costs and charges provided for herein are exclusive of any
present or future federal, state, municipal or other sales or use tax with
respect to the personnel covered hereby, or any other present or future excise
tax upon or measured by the gross receipts from this transaction or any
allocated portion thereof or by the gross value of the personnel covered hereby.
If NSP is required by applicable law or regulations to pay or collect any such
tax or
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taxes on account of this transaction or the personnel covered hereby, then such
amount shall be paid by NORENCO in addition to the costs or charges provided for
herein.
7.5 This Agreement shall be construed in accordance with and be governed
by the laws of the State of Minnesota.
IN WITNESSETH WHEREOF, the parties hereto have caused this instrument to
be executed by their respective officers thereunto duly authorized as of the day
and year below written.
NORENCO CORPORATION NORTHERN STATES POWER COMPANY
By /s/ H. S. Wick By /s/ D.E. Gilberts
-------------------------- --------------------------------
Its V.P. and Gen. Mgr. Its Sr. Vice President Power Supply
------------------------- -------------------------------
Date 5/18/83 Date 5/18/83
------------------------ ------------------------------
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Table 1 _________ Month _____ Year
4.1) FUEL Fuel Delivered in Month = $ _________
4.2) Incremental Maintenance ______ MMBtu ________ $/MWHO = $ _________
4.3) Incremental Auxiliaries ______ MMBtu ________ $/MWH = $ _________
4.4) No Load Maintenance ______ Hours ________ $/MWCAPO = $ _________
4.5) No Load Auxiliaries ______ Hours ________ $/MWH = $ _________
4.6) Ash Disposal = $ _________
4.7) Energy Management System Costs --
4.7.1) Replacement Energy = $ _________
4.7.1.1 Costs
Fuel $ ___________
Maintenance $ ___________
Startup $ ___________
Fuel & Ash Handling $ ___________
Other $ ___________
4.7.1.2 Boiler Availability Credits $ ___________
4.7.2) Sales of Electricity for Resale = $ _________
4.8) Flame Stabilization _____ MMBtu gas ______ gas cost = $ _________
_____ Gallons oil ______ oil cost = $ _________
4.9) Incremental Operations from time sheets = $ _________
4.10) Thermal Equipment O & M from work orders = $ _________
4.11) Standby No Loads _______ hours = $ _________
4.12) Supply of Gas and Oil = $ _________
<PAGE> 18
Table 2 ____________ Month __________ Year
HIGH BRIDGE FUEL
INVENTORY
---------
NSP Electric NORENCO
------------ -------
Tons MMBtu Tons MMBtu
Fuel beginning of month
Fuel delivered during month
Fuel consumed during month*
Fuel onsite end of month
* For boilers B9 and Bl0, fuel consumed will be prorated between NSP Electric
and NORENCO on the basis of measured integrated readings of steam flow to
NORENCO and the turbine generators T3 and T4. Total coal consumption by
boilers B9 and B10 will be measured using existing plant procedures and
instrumentation. Differences in measured and estimated pile inventory on
annual pile true-up will be prorated between NSP Electric and NORENCO on the
basis of the recorded NORENCO and Electric inventory at the time of true-up.
HIGH BRIDGE STEAM PRODUCTION
----------------------------
NSP Electric NORENCO
------------ -------
T3 T4
Steam integrator beginning of month
Steam integrator end of month
Steam consumption
<PAGE> 19
DEFINITIONS
Thermal Only Service At any point in time High Bridge Boilers B9
and B10 are either in a shutdown mode, a hot
standby mode, a startup mode, or an
operating mode. When those boilers would
otherwise be in the shutdown mode with
respect to system electric generation
requirements, such boilers shall be deemed
to be in thermal only service.
No Load Operation and A coefficient calculated periodically by NSP
Maintenance Coefficient Power Production which relates the annual
maintenance cost of a generating unit to the
energy output of the unit.
Average System Incremental Each month, NSP Power Production calculates
Generation Cost its average incremental cost to generate
electricity to meet NSP's native load
requirements.
<PAGE> 1
Exhibit 10.35
OPERATIONS AND MAINTENANCE AGREEMENT FOR ELK RIVER
RESOURCE RECOVERY FACILITY AND BECKER ASH LANDFILL
THIS OPERATIONS AND MAINTENANCE AGREEMENT (the "Agreement") is made as of this
1st day of November, 1996 by and between Northern States Power Company, a
Minnesota corporation ("Owner") and NRG Energy, Inc., a Delaware corporation
("Operator").
RECITALS:
WHEREAS, Owner is a public utility which serves retail customers in
Minnesota, South Dakota and North Dakota, and which is subject to regulation by
the Minnesota Public Utilities Commission ("MPUC"), among other agencies;
WHEREAS, Operator is a wholly-owned subsidiary of Owner engaged in the
business of owning and operating electric generating facilities and facilities
for the transportation and processing of municipal solid waste into
refuse-derived fuel ("RDF");
WHEREAS, Owner owns an undivided 85% interest in the fixed assets and 100%
interest in the mobile assets of a facility located in Elk River, Minnesota for
the receipt and processing of municipal solid waste into RDF as more
particularly described on Exhibit A (the "Facility");
WHEREAS, Owner owns an ash landfill facility in Becker, Minnesota, as more
particularly described on Exhibit B (the "Ash Landfill");
WHEREAS, the County of Anoka ("Anoka County") and Owner entered into a
Loan Agreement, as defined herein (the "Loan Agreement"), pursuant to which
Anoka County agreed to loan to Owner the proceeds of its Floating/Fixed Rate
Resource Recovery Revenue Bonds (Northern States Power Company Project), Series
1985 (the "Series 1985 Bonds") for the purpose of financing costs of the
Facility to be acquired, constructed and equipped and thereafter owned and
operated by Owner;
WHEREAS, Anoka County and Owner entered into a service agreement dated
November 26, 1985 as amended and restated on March 10, 1987 ("Anoka Service
Agreement");
WHEREAS, the County of Hennepin and Owner entered into a service agreement
dated December 30, 1987 ("Hennepin Service Agreement");
WHEREAS, the County of Sherburne and Owner entered into a service
agreement in March, 1987 ("Sherburne Service Agreement");
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WHEREAS, The Tri-County Solid Waste Management Commission ("Tri-County
Commission") and Owner entered into a service agreement in March, 1987
("Tri-County Service Agreement);
WHEREAS, Hennepin County, Anoka County, Sherburne County, the Tri-County
Commission and Owner entered into an Ash Management Services Agreement dated
June 15, 1989 ("Ash Management Service Agreement") pursuant to which Owner
agreed to transport, dispose of and store various ash;
WHEREAS, Anoka County and Owner entered into a design and construction
agreement dated November 26, 1985, as amended and restated on March 10, 1987
("Construction Agreement");
WHEREAS, Owner and United Power Association ("UPA") entered into an
agreement dated February 10, 1987 as amended on March 15, 1991 ("UPA
Agreement"), pursuant to which UPA and Owner defined their respective rights and
obligations with respect to management, administration, ownership, revenues and
responsibilities with respect to the Facility;
WHEREAS, Owner and Operator have entered into an Administrative Services
Agreement dated February 24, 1992 (the "Administrative Agreement") approved by
the MPUC under which either entity may provide services to the other and setting
forth the means by which compensation for any such services is to be computed;
and
WHEREAS, Owner desires that Operator continue to operate and maintain the
Facility and Ash Landfill, pursuant to an agreement independent of the
Administrative Agreement;
NOW THEREFORE, in consideration of the premises and the mutual promises
and agreements of the parties, the parties agree as follows:
1. DEFINITIONS
The following terms shall have the meaning set forth herein:
1.1 Agreement: This contract, including all appendices, exhibits and
schedules attached or incorporated, as it may be amended,
supplemented or modified by the Parties from time to time in
accordance with this Agreement.
1.2 Annual Operating Budget: The budget materials and information
prepared by Operator each year of the Term as set forth in Section
5.1.
1.3 Ash Landfill: The real property, fixtures, equipment, personal
property, improvements and other items described on Exhibit B.
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1.4 Ash Landfill Equipment: All equipment, fixtures and machinery used
in the operation or maintenance of the Ash Landfill.
1.5 Base Management Fee: The amount Owner is to pay Operator as provided
in Section 6.5.
1.6 Commencement Date: The date on which Operator commenced the
provision of operation and maintenance services for the Facility and
Ash Landfill, which is agreed to be January 1, 1994.
1.7 Contract Year: From January 1 to December 31 of any given calendar
year.
1.8 Effective Date: The date on which this Agreement takes effect, as
set forth in Section 9.1.
1.9 Emergency: Any condition, situation or event relating to or
affecting the Facility, the Ash Landfill, or any part thereof which
(i) imminently endangers or might endanger the life or safety of
persons or result in damage to property; or (ii) adversely affects
or might adversely affect the ability of the Facility or Ash
Landfill to meet any material obligation of the Loan Agreement or
might create an Event of Default under the Loan Agreement or any RDF
Facility Agreement; or (iii) creates, or might create, a material
violation of any Law or Permit.
1.10 Event of Default: Any occurrence defined in Section 14.1.
1.11 Facility: The real property, fixtures, improvements, equipment,
personal property and other items located on Exhibit A.
1.12 Facility Equipment: All equipment, fixtures and machinery used in
the operation or maintenance of the Facility.
1.13 Final Non-appealable Order: An order from the MPUC or from any other
judicial, quasi-judicial, administrative or legislative body from
which all rights to seek reconsideration and appeal have been
exhausted or from which the time limits applicable to seeking
reconsideration and appeal have expired.
1.14 Force Majeure: An event or events as defined in Article XII.
1.15 Governmental Authority: The United States of America, the State of
Minnesota, or any state or other political subdivision thereof,
including, without limitation, any municipality, township, or
county, and any entity exercising executive, legislative, judicial,
regulatory or administrative functions
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of or pertaining to government, including, but not limited to, any
corporation or other entity owned or controlled by any of the
foregoing.
1.16 Law(s): Any constitution, charter, act, statute, ordinance, code,
rule, regulation, order, permit, condition, specified standards or
objective criteria contained in any applicable permit, approval,
order, decision, determination or ruling of any Governmental
Authority having jurisdiction, all as in effect from time to time,
including without limitation, environmental laws pertaining to air
and water emissions relating to the Facility and Ash Landfill, and
the operation thereof, which standards or criteria must be met in
order for the Facility or Ash Landfill to be operated lawfully, or
other legislative, administrative or judicial action, decree,
judgment or Final Non-appealable Order of any Governmental Authority
having jurisdiction relating to the Facility or Ash Landfill.
1.17 Lien: Any security interest, mortgage, pledge, lien (statutory or
otherwise), claim, hypothecation, assignment, preference, priority,
charge, encumbrance, title, retention agreement, or Lessor's
interest under a capital lease or analogous instrument, or any other
agreement of any kind or nature which has substantially the effect
of constituting a security interest in, of, against or on any
portion of the Facility, Ash Landfill, Facility Equipment or Ash
Landfill Equipment.
1.18 Materials: All supplies, spare parts, materials, tools, consumables,
chemicals and equipment necessary for the operation and maintenance
of the Facility or Ash Landfill.
1.19 MPUC: The Minnesota Public Utilities Commission and any successor
agency.
1.20 Operation and Maintenance Manuals: The operating manuals for the
Facility and Ash Landfill, including the operating data and
parameters, design drawings, specifications, vendor manuals,
manufacturer manuals or warranties and similar materials for the
Facility, Ash Landfill, Facility Equipment and Ash Landfill
Equipment.
1.21 Operator: NRG Energy, Inc. and its successors and assignees.
1.22 Owner: Northern States Power Company and its successors and
assignees.
1.23 Parties: Owner and Operator and their respective successors and
assignees.
1.24 Party: Owner or Operator and any successor or assignee of either
Owner or Operator, respectively.
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1.25 Permits: All federal, state and local authorizations, certificates,
licenses, permits, consents, rights, exemptions, orders,
concessions, determinations, franchises, and approvals required by
any Governmental Authority for the construction, operation or
maintenance of the Facility, the Ash Landfill, the Facility
Equipment, or the Ash Landfill Equipment or otherwise applicable.
1.26 Person: Any individual, partnership, corporation, business trust,
limited liability company, joint stock company, trust,
unincorporated association, joint venture, Governmental Authority or
other entity.
1.27 Potential Event of Default: An event which, but for the passage of
time or the giving of notice or both, would constitute an Event of
Default.
1.28 Prudent Operating Practice: Those practices, designs, means,
techniques, equipment, methods, specifications and standards of
safety and performance, as the same may change from time to time, as
would be used by experienced, knowledgeable and professional firms
performing operation and maintenance services on facilities of the
type and size similar to the Facility or Ash Landfill, which, in the
exercise of reasonable judgment and in the light of the facts known
or which reasonably should have been known, are considered to be
sound, safe and prudent practice in connection with the operation
and maintenance of RDF processing facilities and ash landfill
facilities, and similar facilities, at the time a decision is made
or an action taken or not taken, and which are consistent with all
applicable laws, permits, the RDF Facility Agreements, the Loan
Agreement, the UPA Agreement and relevant standards for reliability,
safety, environmental protection, efficiency and economy.
1.29 RDF Facility Agreements: Collectively the Anoka Service Agreement,
Hennepin Service Agreement, Tri-County Service Agreement, Ash
Management Service Agreement, Construction Agreement, and UPA
Agreement.
1.30 Reimbursable Costs: The costs and expenses set forth in Section 6.2.
1.31 Requests for Payment: The periodic written invoices and requests
from Operator to Owner prepared in accordance with Section 6.7(a)
for payment of the Management Fee, Reimbursable Costs and other
amounts due from Owner to Operator.
1.32 Standards of Performance: The standards for Operator's performance
of the services to be provided as set forth in Section 3.2.
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1.33 Supplies: Lubricants, hand tools, office and laboratory supplies,
protective clothing and any other consumable items required for
operation and maintenance of the Facility, Facility Equipment, Ash
Landfill and Ash Landfill Equipment.
1.34 Term: The Period of time during which this Agreement is in effect.
ARTICLE 11
SCOPE OF WORK
2.1 Scope of Work: Operator will operate and maintain the Facility, Ash
Landfill, Facility Equipment and Ash Landfill Equipment
(collectively the "RDF Facilities") and perform certain other duties
as set forth in this Agreement, including, but not limited to, all
operation and maintenance services defined in Section 3.1 (the
"Contract Services"). Operator shall operate and maintain the RDF
Facilities in a clean, safe, efficient and environmentally
responsible manner. The Contract Services shall be performed in
accordance with the Standards of Performance set forth in Section
3.2.
2.2 RDF Facility Agreements and Permits: Prior to execution of this
Agreement, Owner has provided Operator with copies of the RDF
Facility Agreements and Permits. Upon execution or receipt by Owner
of any new RDF Facility Agreements, Permits, or any amendments to
RDF Facility Agreements or Permits previously transmitted to
Operator, Owner shall provide Operator with executed copies. The
Parties recognize and agree that this Agreement is intended, in
part, to fulfill Owner's operation and maintenance obligations under
the RDF Facility Agreements and, after compliance with the Permits,
Standards of Performance, Prudent Operating Practice, and Laws, to
optimize the operation of the RDF Facilities consistent with Owner's
objective to achieve its expected return.
2.3 Compliance with RDF Facility Agreements and Permits: Operator shall
abide by all terms and conditions of the RDF Facility Agreements and
Permits applicable to the operation and maintenance of the RDF
Facilities in performing any part of the Contract Services. If
Operator's compliance with this Agreement would cause Owner to be in
default or otherwise in breach or violation of any of its
obligations under any RDF Facility Agreement, the Loan Agreement, or
any Permit, the requirements of such agreements or permits shall
control Operator's performance hereunder to the extent necessary to
avoid such default, breach or violation, subject to Operator's
obligation to comply with all Laws. Each Party shall notify the
other as soon as it knows or believes that compliance with this
Agreement may result in such a default, breach or violation.
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ARTICLE III
OPERATOR RESPONSIBILITIES
3.1 On and after the Commencement Date and subject to approval by Owner
of the Annual Operating Budget and any other expenses Operator shall
be responsible for the operation and maintenance of the Ash
Landfill, Ash Landfill Equipment, Facility and Facility Equipment,
including, but not limited to, the following:
A. Performance of all operation and maintenance of the Ash
Landfill, Ash Landfill Equipment, Facility and Facility
Equipment, including the procurement of all Ash Landfill
Equipment, Facility Equipment, Materials, Supplies and related
services required to ensure operation and maintenance in
accordance with the provisions of this Agreement and industry
standards and to accomplish the objectives of maximizing
useful life and minimizing damage to the RDF Facilities and
outages or unavailability due to lack of maintenance.
B. Performance of all preventive maintenance, in accordance with
applicable Operation and Maintenance Manuals and
manufacturers' and vendors' warranties and recommendations;
the performance of routine maintenance such as lubrication,
oil changes, adjustments, and scheduled replacements; and the
performance of corrective maintenance such as repairs after
the occurrence of a problem, breakdown or failure.
C. Performance of all services required by the UPA Agreement, Ash
Management Services Agreement, Tri-County Service Agreement,
Anoka Service Agreement, Hennepin Service Agreement, and
Sherburne Service Agreement to operate and maintain the RDF
Facilities, including, but not limited to, all necessary
communication with the respective parties to such agreements,
and preparation of notices, reports and supporting data for
Owner's review and submittal under such agreements, and all
necessary administration of such agreements.
D. Applying for and maintaining all Permits necessary for the
operation of the RDF Facilities.
E. Administration and coordination of all municipal solid waste
supplies received at the Facility, including, but not limited
to, management of
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contract trucking services and landfill operator's contracts
and operations.
F. Preparing and revising site procedures, budgets, logs, records
and technical and administrative reports as may be required or
advisable.
G. Identifying the need for the procurement of subcontractors for
performance of portions of the Contract Services subject to
Owner approval, and scheduling, coordinating and supervising
any such subcontractors.
H. Preparing the Annual Operating Budget required in accordance
with Section 5.1.
I. Preparing and submitting, or providing to Owner for submittal,
with the appropriate Person or Governmental Authority, all
reports, data and other information required by the Permits
and RDF Facility Agreements.
J. Responding in a timely manner to written requests from Owner
for information about the Contract Services.
K. Performing all other responsibilities assigned to Operator
pursuant to this Agreement.
3.2 Standards of Performance: Operator shall perform each item of the
Contract Services in a careful, professional, prudent and efficient
manner at a level of care consistent with that expected from
similarly situated professional operation and maintenance providers,
and in accordance with the following requirements (collectively
"Standards of Performance"):
(a) Prudent Operating Practice;
(b) the terms of the Operation and Maintenance Manuals and other
operating instructions provided by Anoka County or its agents
pursuant to the Construction Agreement or provided by any
other vendors, suppliers or contractors (and, with regard to
any Facility Equipment acquired subsequent to the Commencement
Date, in accordance with the operating instructions provided
by the respective equipment suppliers, vendors or
manufacturers) or other appropriate practices, whichever are
more stringent;
(c) all operational and maintenance obligations imposed on the
Owner pursuant to any RDF Facility Agreement;
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(d) the requirements of the providers of insurance described in
Article VII, and any and all insurance coverage documents
maintained by Owner for the protection of the RDF Facilities
and their revenues, copies of which are provided to Operator;
(e) any and all warranties received from Anoka County or its
agents or any manufacturer of the Facility Equipment or
Materials, which are not part of any RDF Facility Agreements,
copies of which have been provided to Operator;
(f) the Permits and all applicable Laws;
(g) the site procedures, and all other procedures devised by
Operator for operation and maintenance of the RDF Facilities;
(h) after compliance with all relevant Laws, Permits, RDF Facility
Agreements and Standards of Performance, operation of the RDF
Facilities consistent with Owner's objective to achieve its
expected return from the operation of the Facility.
In the case of any conflict between any such standards, the most stringent
applicable standard shall govern.
3.3 Procurement of equipment, materials, services and supplies:
(a) Subject to the limitations set forth in Section 5.2, Operator
shall identify, select, schedule, procure and receive all
equipment, materials, supplies and services necessary to
perform the Contract Services. Operator shall identify all
such items needed, establish technical and commercial
requirements, develop qualified bid lists, request bids or
proposals from prospective vendors and subcontractors,
evaluate bids or proposals received and select appropriate
vendors and subcontractors. Operator shall use its best
efforts to procure all equipment, services and supplies at
competitive rates, and to make all purchases at the lowest
evaluated price available for the appropriate type and quality
of equipment, services and supplies. Operator shall use its
professional judgment to determine when competitive bidding is
appropriate.
(b) Operator shall receive, inspect and inventory all Equipment,
Materials and Supplies delivered and identify and resolve any
defects or deficiencies, and shall sign all invoices, bills of
lading or other documents indicating acceptance when the
Equipment, Materials and
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Supplies meet Operator's purchase order or other
specifications. Operator shall be responsible for resolving
defects or deficiencies identified, including arrangement for
obtaining replacements, modifying or withholding payment, or
otherwise processing any claim or dispute arising under a
purchase order.
(c) In no event shall Operator take title to any Equipment,
Materials or Supplies received for the RDF Facilities. All
purchase orders, bills of lading and other title and shipping
documents with respect to the Equipment, Materials and
Supplies shall specify that Owner is to take title directly
from the manufacturer, vendor or supplier. Title to all
Equipment, Materials and Supplies or other services or items
purchased by Operator in connection with the Contract Services
shall pass directly to Owner from the manufacturer, vendor or
supplier free of all liens of Operator.
(d) Operator shall be responsible for supervising, coordinating
and administering the work of all subcontractors providing
services.
3.4 Inventory. Operator shall maintain an inventory of Materials adequate to
support the continuous and successful operation of the RDF Facilities. The
procurement of such inventory, including replacement Materials, shall be
made in accordance with the provisions of Section 3.3. Operator shall
provide necessary security for such inventory, and establish and manage an
inventory control system.
3.5 Personnel.
(a) Operator shall employ at the Facility and the Ash Landfill the
appropriate number of properly qualified and trained personnel to
perform the Operator's obligations under this Agreement as approved
under the Annual Operating Budget. Operator shall be solely
responsible for the development of a staffing plan and the selection
and training of all personnel employed by Operator at the Facility
and the Ash Landfill following the Commencement Date.
(b) All personnel shall be qualified (including holding all appropriate
valid licenses required by Law) and fully trained for their
respective positions. All individuals utilized by Operator to
perform Contract Services shall be employees of the Operator or
workers or independent contractors under Operator's direction.
Working hours, rates of compensation, and all other matters relating
to such personnel shall be determined by Operator (subject to
Owner's approval with respect to budget items.)
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(c) Operator shall retain sole responsibility and control of labor
matters pertaining to its personnel. Operator shall provide Owner
with such information regarding the selection of its personnel as
Owner may reasonably request. With respect to hiring of personnel
and its employment policies, Operator shall comply with all
applicable federal and state labor and employment Laws and shall
exercise control over labor relations in a reasonable manner
consistent with the intent and purpose of this Agreement, including
the laws and policies set forth in Exhibit C.
(d) Operator acknowledges and agrees that it does not have the authority
to enter into any contracts or collective bargaining agreements
which bind or purport to bind or obligate Owner.
3.6 Training.
(a) Operator shall insure that its personnel are trained in a
satisfactory manner so as to enable each of the personnel to perform
their assigned functions and as required to enable Operator to
comply with its obligations under this Agreement. Operator shall
establish and maintain a regular ongoing training program for the
personnel. This training program shall be designed to train new
personnel, keep existing personnel familiar with all existing site
procedures and informed of all new revisions. Owner may at any time,
upon reasonable notice, review Operator's regular training program
in order to assess its adequacy and compliance with this Section
3.6.
(b) If this Agreement is scheduled to terminate for any reason, Operator
will cooperate with Owner and any replacement operator, at Owner's
expense, in training replacement personnel for the RDF Facilities,
including permitting such replacement personnel to participate in
the training program described in Section 3.6(a).
3.7 Taxes. Operator shall pay all federal, state and local taxes which it is
obligated to pay with respect to wages, salaries and benefits paid or
provided by it to its employees, including, but not limited to: (i) all
payroll-related or consumer taxes of its employees, federal, state and
local tax withholdings, Federal Insurance Contribution Act taxes, and
federal and state unemployment taxes and; (ii) all federal, state and
local corporate income taxes on income earned by Operator. Owner shall pay
real and tangible real estate and personal property taxes for property
owned, leased, or rented by Owner. Operator shall forward to Owner any tax
bills for which Owner is responsible immediately upon receipt by Operator.
Operator shall maintain
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all appropriate records reflecting its tax obligations, withholdings and
payments.
3.8 Safety. Operator shall take all necessary and advisable precautions for
the safety and security of its personnel and other persons at the Facility
and the Ash Landfill and in connection with the performance of the
Contract Services, and shall comply with all applicable safety laws and
requirements, necessary to prevent accidents or injury to persons or
damage to property at the Facility or the Ash Landfill. Operator shall
promptly and continuously update its safety and security procedures to
ensure safe, secure and efficient operation of the Facility and Ash
Landfill.
3.9 Administration. Operator shall administer and be responsible for all cost
accounting, purchasing, personnel, insurance and payroll functions
relating to the performance of the Contract Services. All accounting shall
be in accordance with generally accepted accounting principles. Operator
shall pay all bills related to the Contract Services in a timely manner so
as to take advantage of any available discounts and to avoid any
penalties, except for those bills which are the obligation of Owner to
pay.
3.10 Licenses and Permits.
(a) Operator shall cause each of its personnel to procure and maintain
their respective licenses as required to perform the Contract
Services.
(b) Operator shall maintain each of the Permits and procure any
renewals, revisions, waivers or new Permits necessary or desirable
for the operation and maintenance of the RDF Facilities. Operator
shall retain all original Permits received or obtained by Operator
for the Facility and Ash Landfill from time to time as such Permits
are received or obtained during the term of this Agreement,
including any renewals, revisions, waivers, or amendments and
deliver copies of all such Permits to Owner.
(c) Operator shall perform Owner's obligations under the Permits and any
renewals thereof and shall give all notices required by, and
otherwise comply with, all applicable Permit terms and shall keep
the Permits in full force and effect. In the event any Permit shall
be violated by the operation or maintenance of the Facility or Ash
Landfill by Operator or otherwise, Operator shall promptly notify
Owner and all other applicable Persons and take all necessary action
required to place the Facility and Ash Landfill into compliance with
the Permit as soon as practicable. The provisions of this section
shall apply to any Permit
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required in connection with the transportation, handling,
processing, storage or disposition of any Hazardous Materials.
3.11 Compliance with Laws. Operator shall at all times operate and maintain the
RDF Facilities in a manner which complies in every material respect with
all applicable Laws and Permits, as amended from time to time. In the
event any of the RDF Facilities, Contract Services, or Operator shall
violate any Law, Operator shall promptly notify Owner and all other
applicable Persons and take all necessary action to place the RDF
Facilities into compliance with the applicable Laws.
3.12 Emergencies In the case of an Emergency, Operator shall, as soon as
reasonably practicable, notify Owner of the nature of such Emergency, the
proposed remedial measures and its probable duration. Operator shall act
immediately as required to prevent or overcome any risk of injury to
Persons or material damage to property and to otherwise minimize the
likelihood and degree of adverse consequences from the Emergency.
3.13 Improvements. Operator shall identify any alterations, additions,
modifications or other changes to the RDF Facilities ("Improvements")
which would improve the overall operation, output, safety or efficiency of
the RDF Facilities, and advise Owner in writing of such proposed
Improvements. Upon the written approval of Owner, the Operator shall
arrange for the procurement and integration of all such equipment,
materials and other resources necessary to implement such Improvements at
the RDF Facilities. Except as set forth in the Annual Operating Budget,
the Operator shall make no Improvements other than Improvements made in
accordance with this Section 3.13.
3.14 Books and Record.
(a) Operator shall maintain operating logs, records and reports
documenting the operation of the RDF Facilities, including those
logs, records and reports required by any RDF Facility Agreement or
MPUC, maintain current revisions of Facility and Ash Landfill
drawings, equipment manuals, instruction books, and the Operation
and Maintenance Manuals; and maintain accurate cost ledgers and
accounting records regarding the Contract Services in accordance
with generally accepted accounting principles for review by Owner.
Operator shall also prepare all reports required for Governmental
Authorities, or by the Permits, and provide same to Owner for its
review. Upon termination of this Agreement, the Operator shall turn
over a copy of all such books, logs, ledgers, manuals, reports and
records to Owner.
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(b) Operator shall establish and maintain an information system
reasonably satisfactory to Owner to provide storage and ready
retrieval of Facility and Ash Landfill operating data, including
such information necessary to verify and support calculations for
preparation of documents pursuant to the RDF Facility and Loan
Agreements.
(c) Operator shall prepare and maintain, on a current basis, proper,
accurate, and complete books and records and accounts of all
transactions related to the Facility and Ash Landfill, including
information necessary to verify calculations made pursuant to this
Agreement.
(d) At all reasonable times Owner shall have access to the records
maintained pursuant to this Section and may audit the recordkeeping
practices and systems used to generate the data required by this
Section. Owner shall have the right to determine whether such
practices and systems are in accordance with generally accepted
accounting principles and may cause Operator to make such changes as
necessary to conform with such principles. Operator's records shall
also include all data required by the MPUC and shall be in a form
which satisfies all data requirements of the MPUC. This provision
does not require Operator to utilize the Uniform System of Accounts
of the MPUC.
(e) Owner's right of access to the records described in this Section
3.14 and Operator's obligation to maintain and preserve the same
shall survive for a six (6) year period following the termination of
this Agreement.
(f) With the exception of information relating to Operator's training
program, all reports, data and other documents prepared by Operator
in connection with the Facility, Ash Landfill or Contract Services
shall be the property of Owner as and when the same are prepared and
shall be used by Operator only in the performance of Contract
Services.
3.15 Custody and Access. After the Commencement Date, Operator shall assume
responsibility for the care, custody and control of the Facility and the
Ash Landfill. Upon reasonable notice, Operator shall allow Owner and its
agents and designees full, unrestricted access to the Facility and the Ash
Landfill and all reports, data, information and documents related to the
RDF Facilities and Contract Services in Operator's possession at the
Facility and Ash Landfill, provided that Owner and its agents and
designees agree to comply with all
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applicable safety and security procedures which Operator deems necessary
or advisable.
3.16 Enforcement of Warranties. Operator shall preserve and maintain all
warranties or guarantees of which Owner is beneficiary regarding the
Facility, Facility Equipment, Ash Landfill, Ash Landfill Equipment,
Equipment, and Materials or any component thereof and shall notify Owner
of any claims which Owner may have under such warranties or guarantees of
which Operator becomes aware during the performance of Contract Services.
Operator shall manage and operate the Facility and Ash Landfill consistent
with the conditions applicable to all such warranties and guarantees so as
to preserve their effectiveness and shall take no action which may
adversely affect any claim under any warranty or guarantee without the
express written consent of the Owner.
3.17 No Liens or Encumbrances. Operator shall keep and maintain the Facility,
Ash Landfill, Facility Equipment and Ash Landfill Equipment free and clear
of all Liens and encumbrances (other than Liens created or permitted by
Owner) resulting from acts or omissions of Operator or its subcontractors
or work done at the request of Operator or its subcontractors. In the
event any Lien is imposed and unless (i) execution and enforcement are
effectively stayed, (ii) all claims which the Lien secures are being
actively contested in good faith, with due diligence and by appropriate
proceedings and (iii) Operator has posted a bond or created a financial
reserve sufficient to fully satisfy and release any contested Lien,
Operator shall immediately take whatever actions are necessary to satisfy
and release the Lien. Operator agrees to indemnify and hold Owner harmless
from all claims, judgments, losses, damages, and defense costs, including
reasonable attorneys' fees, incurred or suffered by Owner as a result of
the imposition or pendency of any Lien (other than Liens created or
permitted by Owner) or Owner's reasonable response to any such Lien,
including, but not limited to, all costs incurred to remove or satisfy any
such Lien if Operator fails to do so as required by this Agreement.
3.18 Facility Performance. If any significant deficiency in performance of the
Facility or Ash Landfill occurs, including, but not limited to, a failure
to meet any warranty or obligation under the RDF Facility Agreements, or
if such a deficiency is projected, Operator shall notify Owner of the
deficiency or projected deficiency and shall state Operator's opinion as
to the cause of the deficiency or projected deficiency and prepare a
report in detail, as required, together with a plan to remedy the problem.
Upon Owner's request, Operator shall make available those of its personnel
necessary to review and assess the cause of the deficiency or projected
deficiency with Owner.
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3.19 Periodic and Annual Review
(a) Status meetings shall be held quarterly between Owner's
Representative and Operator's Representative, or more frequently as
may be necessary for the purpose of reviewing Operator's provision
of the Contract Services.
(b) At least (10) ten days before each quarterly status meeting,
Operator shall submit to Owner (i) a progress report, in detail
acceptable to Owner, covering all operations conducted during the
quarter with respect to operations and maintenance, procurement,
Improvements, labor relations, significant interactions with UPA and
any Governmental Authorities, and other significant matters, which
report shall include (with respect to quantitative items) a
comparison of such items to corresponding values for the then
preceding quarter and year and listing of any significant operation
problems along with remedial actions planned and a brief summary of
major activities planned for the next reporting period.
(c) As soon as available, and in any event within forty-five (45) days
after the end of each Contract Year, Operator shall submit to Owner
an annual report certified by the Operator's Representative
describing in detail substantially similar to that contained in the
quarterly reports referred to in Section 3.19(b) above, all of the
Facility and Ash Landfill operations for the preceding Contract Year
and presenting a comparison of the Facility and Ash Landfill
operations with the Annual Operating Budget for the Contract Year
and with those obtained for the preceding Contract Year, if any (the
"Annual Report"). Within thirty (30) days after the submission of
each Annual Report, the Operator's Representative shall meet with
Owner's Representative to review and discuss the report and to
report upon any other aspects of the operations at the Facility and
Ash Landfill that Owner may request.
(d) Operator shall prepare any additional reports required by the RDF
Facility Agreements, Permits, Laws or any Governmental Authority in
a timely and complete manner.
3.20 Litigation; Permit Lapses. Upon obtaining notice or knowledge thereof,
Operator shall submit prompt written notice to Owner of: (i) any
litigation, or material claim, dispute or action, threatened in writing or
filed, concerning the Facility, the Ash Landfill, the RDF Facility
Agreements, or the Contract Services; (ii) any written refusal or
threatened refusal to grant, renew or extend or any pending or written
threatened action that might affect the granting, renewal or extension of,
any license, permit, approval, authorization
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or consent concerning the Facility or Ash Landfill or the Contract
Services; and (iii) any dispute with any Governmental Authority concerning
the Facility or Ash Landfill or the Contract Services, any Permit, or any
dispute with respect to any RDF Facility Agreement.
ARTICLE IV
OWNER RESPONSIBILITIES
4.1 Access. Owner shall provide and grant to Operator right of access to the
Facility and the Ash Landfill, throughout the term of this Agreement.
4.2 Accommodations. Owner shall make available such offices, storage
facilities, unloading docks, restrooms, office equipment and facilities as
are reasonably necessary to perform the Contract Services, and as are
reasonably practicable, at the Facility and Ash Landfill. This section
does not require Owner to invest in Improvements or to expend funds for
items which are properly included in Operator's overhead expenses.
4.3 Manuals and Drawings. Owner shall provide Operator with all current
Operating Manuals and with all as built drawings, specifications,
warranties, diagrams, test results and other documents and information
which Owner may have with respect to the RDF Facilities, which is
necessary to Operator's provision of the Contract Services. Should any
such information be classified as confidential or proprietary, Owner shall
seek to obtain all necessary authorizations, releases, acknowledgments or
other approvals necessary to provide Operator access to and use of such
information. Operator shall comply with all reasonable requests to protect
the confidential and proprietary nature of such information, including,
but not limited to, any requirements contained in any RDF Facility
Agreement.
4.4 Cooperation. Without limiting Operator's obligations hereunder, Owner
shall make reasonable efforts to cooperate with Operator in its
performance of the Contract Services.
4.5 Representatives.
Each Party shall designate a representative who shall be principally
responsible for administration of this Agreement and for communications
between the Parties. The designation of the representative for each Party
may be changed at any time by written notice.
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ARTICLE V
ANNUAL OPERATING BUDGET
5.1 Preparation of Budget. No later than ninety (90) days prior to the
beginning of each Contract Year, Operator shall submit for Owner's review
and approval, a proposed budget on a monthly basis, for the Contract
Services to be performed in the next succeeding Contract Year. The
proposed Annual Operating Budget shall be based on Operator's assessment
of the necessary Contract Services for the next Contract Year and shall
reflect the most economical and reasonable means of performing such
activities in accordance with the Standards of Performance. The proposed
Annual Operating Budget shall include:
(i) the proposed amount to be spent annually for Reimbursable Costs and
the Management Fee then in effect;
(ii) the proposed amounts to be spent for the purchase of Equipment,
Materials, Supplies and services in accordance with Section 3.3,
identifying the items to be purchased;
(iii) a proposed inventory plan;
(iv) proposed Improvements, with a statement describing the purpose and
necessity of each Improvement and the estimated cost of each
Improvement; and
(v) the estimated Performance Incentive, including a schedule detailing
its calculation in accordance with Section 6.6.
5.2 Owner's Review.
(a) Within thirty (30) days after Owner receives Operator's proposed
Annual Operating Budget, Owner shall notify Operator in writing of
Owner's approval or of any proposed revisions to the proposed Annual
Operating Budget. Within 30 days following receipt of Owner's
revisions, Operator shall either confirm to Owner its ability and
agreement to perform the Contract Services during the Contract Year
in question in accordance with the proposed Annual Operating Budget
as revised by Owner, or Operator shall object to Owner's revisions
in writing stating in detail the reason for each objection. Owner
and Operator shall use their best efforts to agree upon an Annual
Operating Budget, which shall be approved in writing by both
Parties, approval for which shall not be unreasonably withheld. If
Owner and
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Operator are unable to agree upon an Annual Operating Budget, Owner
and Operator shall present the dispute for dispute resolution in
accordance with Article VIII. In the event an Annual Operating
Budget has not been agreed upon by the first day of any Contract
Year, the Annual Operating Budget shall be the Annual Operating
Budget used for the preceding Contract Year. Each Annual Operating
Budget shall remain in effect throughout the applicable Operating
Year, subject to updating, revision and amendment as may be proposed
by either Party and consented to in writing by the other Party,
consent for which may not be unreasonably withheld.
(b) If, during any Contract Year, Operator determines that any category
within an Annual Operating Budget will vary for the Contract Year by
more than ten percent (10%) or one hundred thousand dollars
($100,000), whichever is greater, Operator shall immediately notify
Owner and shall follow Owner's instructions regarding further
expenditures for the operation and maintenance of the Facility and
Ash Landfill pursuant to this Agreement. Until such time as Operator
receives such instructions, Operator shall continue to operate and
maintain the Facility and Ash Landfill according to the terms of
this Agreement as permitted under the Annual Operating Budget then
in effect. At no time, without Owner consent, shall Operator be
entitled to make expenditures in any Annual Operating Budget
category which exceed the amount allocated for such category;
provided, however, that the foregoing limitation shall not apply in
the case of Emergencies, which shall be governed by Section 3.12.
ARTICLE VI
PAYMENT
6.1 As the sole and exclusive compensation and reimbursement to Operator for
the performance of the Contract Services Owner shall pay Operator, in the
manner and at the times specified, the Reimbursable Costs, the Management
Fee and the Performance Incentive, adjusted as necessary in accordance
with Sections 6.3, 6.4, 6.9, and 6.10.
6.2 Reimbursable Costs. Subject to any limitations on expenditures in this
Agreement, Owner shall reimburse Operator for the following costs incurred
by Operator in performing the Contract Services, to the extent properly
incurred by Operator pursuant to this Agreement and supported by adequate
documentation (the "Reimbursable Costs"):
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(a) the actual payroll cost for its personnel to the extent involved in
the performance of the Contract Services, including, but not limited
to, necessary overtime, plus the actual cost of associated payroll
taxes, unemployment and disability insurance, worker's compensation
insurance, benefits and other statutory compensation;
(b) the actual cost of Materials, Equipment and Supplies and services
provided by Operator or any subcontractor;
(c) the actual cost of any insurance paid by Operator to provide the
coverages set forth in Section 7.2, except for payments for
deductibles to be paid by Operator pursuant to Section 6.4, and any
claims not covered by insurance as described in Section 7.2(b).
(d) the actual fees and costs necessary to obtain and maintain Permits,
including fees and costs arising from any changes in Laws or Permits
after the execution of this Agreement;
(e) the actual cost of any Improvements approved by Owner, as incurred;
(f) any other cost or expense designated as a Reimbursable Cost in this
Agreement; and
(g) All other costs necessary for conducting the business of the
Facility and Ash Landfill.
6.3 Adjustments for Owner Provided Services. To the extent Operator obtains or
utilizes any Equipment, Materials, Supplies or services of any type from
Owner for its performance of the Contract Services ("Owner Provided
Services"), the value of the Owner Provided Services shall be computed in
accordance with procedures established in the Administrative Agreement and
approved by the MPUC as set forth in Exhibit D. Owner shall have the right
to set off or recoup the value of Owner Provided Services against amounts
due to Operator each month for Reimbursable Costs as invoiced by Operator
pursuant to Section 6.7. When Owner exercises its right to set off or
recoup for the value of Owner Provided Services, Owner shall provide
Operator with documentation, in reasonable detail, showing the basis for
the set off or recoupment and the calculation of the amount due Owner. Any
such set off or recoupment shall be without prejudice to Operator's right
to contest the amount claimed by Owner or the basis for that claim.
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6.4 Exclusions from Reimbursable Costs.
(a) Operator shall be responsible for payment of any fines or penalties
(or settlements in lieu of fines or penalties) payable to any
Governmental Authority, to the extent caused by the negligent acts
or omissions or willful misconduct of Operator, or Operator's
failure to comply with any Law, Permit or any provision of this
Agreement, and such fines or penalties shall not be considered
Reimbursable Costs or otherwise result in any increase in the costs
to be borne by Owner. Owner shall be responsible for the payment of
any other fines or penalties (or settlements in lieu of fines or
penalties) payable to any Governmental Authority as a result of the
failure of the Facility or Ash Landfill to comply with applicable
Laws or Permits. Operator also shall be responsible for payment of
all costs and expenses (including reasonable attorneys' fees and
expenses) incurred by Owner which arise from any negligent acts or
omissions or willful misconduct of Operator or Operator's failure to
comply with any Law, Permit or any provision of this Agreement, and
Owner shall be entitled to offset or recoup such amounts in the same
manner as provided in Section 6.3.
(b) Owner shall not be liable for any additional costs incurred by
Operator, or related fees, to the extent such costs are incurred by
Operator as a result of (i) performance of Contract Services in a
manner inconsistent with the Standards of Performance; (ii) Contract
Services performed to remedy a problem, fault or deficiency created
or aggravated by Operator's failure to conform to the Standards of
Performance, or Equipment, Materials, Supplies or services procured
from any other Person to remedy any such problem, fault or
deficiency; or (iii) Operator's negligent acts or omissions, willful
misconduct or failure to comply with any Law, Permit or any
provision of this Agreement. Any such additional costs or expenses
shall not be included as Reimbursable Costs.
6.5 Base Management Fee.
Owner shall pay to Operator an annual Base Management Fee of two hundred
fifty thousand dollars ($250,000) for each Contract Year, adjusted as set
forth in Section 6.10, commencing on the Effective Date and continuing for
each Contract Year thereafter. The Base Management Fee shall be earned in
monthly installments of one-twelfth of the annual Base Management Fee for
that Contract Year and paid along with incurred Reimbursable Costs as
provided in Section 6.7. If Operator provides Contract Services at any
time for only a portion of a month, the Base Management Fee shall be
prorated accordingly. The Base Management Fee shall constitute full
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payment for the services described in Article III, all Operator overhead
and profit for the Contract Services and general and administrative costs
incurred by Operator.
6.6 Performance Incentive.
In addition to the Base Management Fee and Reimbursable Costs, Owner shall
pay Operator a Performance Incentive, calculated independently for each
Contract Year, based on Actual Pretax Income Before Management Fees of the
Facility and the Ash Landfill, minus Specified Owner Return adjusted to a
pretax basis, minus the Base Management Fee. The components of this
calculation shall be determined as follows:
(a) Actual Pretax Income Before Management Fees shall be determined as:
(i) the sum of all revenues and income items other than income
taxes of the Facility and the Ash Landfill, computed in accordance
with generally accepted accounting principles (GAAP), minus (ii) the
sum of all expenses other than income taxes of the Facility and the
Ash Landfill, computed in accordance with GAAP, plus (iii) the Base
Management Fee, and Performance Incentive amounts. Such amount shall
exclude cumulative effect adjustments recorded as a result of
implementing changes in accounting principles or methods of applying
such principles, as defined by generally accepted accounting
principles, attributable to periods prior to the first Contract Year
for which a Performance Incentive is payable to Operator.
(b) Specified Owner Return shall be calculated as the product of Average
Owner Equity for the Contract Year multiplied by the Approved
Utility Return.
(c) Average Owner Equity shall be calculated based on the thirteen-month
average of the Owner Equity invested in the Facility and the Ash
Landfill for the Contract Year. The thirteen monthly Owner Equity
amounts to be averaged shall be the consecutive month-end balances,
as described in (d), beginning with December prior to the start of
the Contract Year and ending with December of the Contract Year.
(d) Subject to audit verification under Section 6.9, Owner Equity shall
be presumed to be represented by the balance included in Account
20.01.03 (Division 60) of the Owner's accounting records (related to
the Facility and the Ash Landfill). Owner Equity shall include the
cumulative amount of Owner cash invested in the Facility and the Ash
Landfill, assuming: (i) monthly distribution to the Owner of all net
income earned by the Facility and Ash Landfill, computed in
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accordance with GAAP; (ii) monthly distribution to the Owner of 60%
of the depreciation expense and 100% of the deferred income tax
expense of the Facility and Ash Landfill, such amounts computed in
accordance with GAAP; (iii) reduction of monthly distributions to
the Owner under (i) and (ii) for 60% of Improvements, equipment or
other items to be capitalized in the property, plant and equipment
accounts of the Facility and Ash Landfill, such amounts computed in
accordance with GAAP; and (iv) no other equity contributions from or
distributions to the Owner unless approved in writing by both
Parties.
(e) Approved Utility Return shall be the rate of return on common equity
approved by the MPUC in the most recent general rate proceeding of
the Owner for which a Final Nonappealable Order has been issued.
This rate of return shall be expressed as a percentage, and will be
rounded to the nearest one-hundredth of one percent.
(f) If the net numerical result of the calculated Performance Incentive
is less than zero for any Contract Year, the actual Performance
Incentive due to the Operator from the Owner shall be zero for that
year.
(g) For purposes of monthly payments of the Performance Incentive during
each Contract Year, an estimate of Performance Incentive amounts
shall be made using revenues and expenses (as defined in paragraph
6.6(a)) included in the final Annual Operating Budget agreed to by
the Operator and Owner under Sections 5.1 and 5.2. No later than the
March 31 following the end of each Contract Year, estimated
Performance Incentive amounts shall be trued-up to actual amounts
based on actual revenues and expenses of the Facility and Ash
Landfill (as defined in 6.6(a)) and the actual Owner Equity for the
Contract Year. Subject to audit verification under Section 6.9, such
revenues and expenses shall be presumed to be represented by the
corresponding revenues and expenses recorded in the Owner's
accounting records related to the Facility and the Ash Landfill.
6.7 Payments.
(a) By the twentieth day following the end of each month, Operator shall
present an invoice to Owner reflecting amounts due for Reimbursable
Costs incurred and due for the preceding month, the monthly portions
of the Base Management Fee and Performance Incentive and the
appropriate adjustments. The precise format of the invoice and the
required amount of documentation in support of the invoice shall be
established by agreement of the Parties, but in any event shall be
sufficient to accurately and completely describe the Contract
Services
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provided and each significant Reimbursable Cost so as to allow for
meaningful review by Owner and, if necessary, MPUC, parties to the
RDF Facilities Agreements, or any Government Authority. The invoice
shall also state whether or not the Facility and Ash Landfill
operation conformed to the applicable Annual Operating Budget during
the billing period and, if not, the extent and reason for any
material deviation and any related remedial action. No Reimbursable
Costs shall be invoiced by Operator unless they were incurred in
accordance with the applicable Annual Operating Budget, as amended,
supplemented or modified. Except for costs and expenses arising from
an Emergency, any cost or expense incurred or to be incurred by
Operator in order to perform the Contract Services which is not
contemplated or included in the Annual Operating Budget, or which
exceeds the amount included for that cost or expense in the Annual
Operator Budget, and which will cause an increase in the Annual
Operating Budget of more than $100,000, shall be submitted to Owner
separately for approval and, if approved, the Annual Operating
Budget shall be amended accordingly and the increase allowed as a
Reimbursable Cost.
(b) Upon receipt of an invoice from Operator, Owner shall apply any
setoff, recoupment or adjustments pursuant to Sections 6.3 and 6.4
or otherwise appropriate. The balance due Operator shall be due and
payable within 30 days after receipt of the invoice by Owner. If the
due date falls on a weekend or legal holiday, the due date shall be
the next working day.
(c) Owner shall make payment of bills via wire transfer of funds if
requested in writing by Operator, or other similar means at
Operator's sole Expense, and if the request contains adequate
payment information. Owner shall be entitled to conclusively
presume, without any liability whatsoever, that the payment
information furnished by Operator (including name, financial
institution, account numbers, payee, etc.) is accurate. In no event
will Owner be required to pay any bill more than once where the
invoice was first paid in accordance with Operator's instructions.
6.8 In addition to any setoff, recoupment or adjustment otherwise made by
Owner, if Owner disputes the validity, reasonableness or accuracy of any
invoice submitted to it for payment, it shall provide Operator an
explanation of the reasons for its dispute within the time provided for
payment by Section 6.6(b).
If Owner disputes only part of a statement submitted to it for payment,
then it shall pay to Operator the undisputed portion of such statement in
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accordance with Section 6.6 and notify Operator in writing of the amount
disputed in accordance with this Section. All such disputes shall be
resolved pursuant to Article VIII of this Agreement.
6.9 Audit Rights.
Notwithstanding the payment of any amount pursuant to Sections 6.6 and
6.7, Owner shall remain entitled at Owner's expense to conduct an audit
and review of all payments made to Operator on a time and material or cost
reimbursable basis, together with any supporting documentation in
accordance with the provisions of Section 6.2 for a period of three (3)
years from and after the close of each Contract Year. Any audit and review
may be conducted by Owner or by its designee and the person conducting the
audit and review shall be entitled to inspect, copy and audit any of
Operator's financial books, records, accounts, and ledgers relating to the
Facility, Ash Landfill or the Contract Services. Operator shall cooperate
with auditors and promptly respond to any questions relating to any audit.
Operator shall retain all information described above for a period of six
(6) years. If, pursuant to any audit and review, it is determined that
any amount previously paid by Operator within the prior three years did
not constitute a due and payable item hereunder, including without
limitation, a properly payable Reimbursable Cost, Operator shall repay
Owner such amount immediately upon demand, with interest determined in
accordance with Section 6.11, or Owner may offset or recoup such amount
for any payment that subsequently may become due to Operator pursuant to
this Agreement. If, pursuant to any such audit or review, it is determined
that Operator is entitled to additional payment or reimbursement, Owner
shall pay Operator such amount immediately upon demand, with interest in
accordance with Section 6.11.
6.10 Management Fee Adjustment.
If the calculation of the Performance Incentive pursuant to Section 6.6
should produce a result which is less than zero, the Owner and Operator
agree that the Management Fee arrangements will be reevaluated to
determine if the definitions of Performance Incentive and/or Specified
Owner Return should be modified in order to provide the Owner with a
reasonable return on equity invested and the Operator with fair
compensation for services provided. Such modifications shall be made, in
the form of an amendment to this Agreement, only if agreed to by both
Parties.
6.11 Interest.
Any amount owed to either Party by the other Party shall accrue interest
each day from the date the amount is due until the date received at the
rate equal
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to the rate established by the First Bank National Association,
Minneapolis, Minnesota as its prime rate plus one percent per annum,
computed and compounded daily.
ARTICLE VII
INSURANCE
7.1 Standards.
All insurance carried and maintained by Operator pursuant to this
Agreement shall be with insurance companies which are authorized to
transact insurance business and cover risks in the State of Minnesota and
which are rated "Excellent" or better by Best's Insurance Guide and Key
Ratings or other insurance companies of recognized responsibility and
satisfactory to the Owner, and, to the extent applicable, the parties to
the Service Agreements, Ash Management Agreement, Loan Agreement and UPA
Agreement, except to the extent Operator qualifies to self-insure the
required coverages.
7.2 Operator Provided Insurance.
(a) Coverages - Operator shall at all times throughout the Term of this
Agreement carry and maintain or cause to be maintained, at its own
expense, insurance with coverage as follows:
i. Worker's Compensation and Employer's Liability Coverage Operator
shall maintain or cause to be maintained Worker's Compensation
insurance written in accordance with statutory limits and Employer's
Liability in an amount not less than $1,000,000 per occurrence and
in the annual aggregate. The Employer's Liability coverage shall not
contain an occupational disease exclusion. Such policy or policies
shall contain an all states endorsement or stop gap endorsement and
alternate employer coverage.
ii. Comprehensive Automobile Liability Coverage - Operator shall
maintain or cause to be maintained Comprehensive Automobile
Liability insurance covering all owned, non-owned and hired vehicles
used by Operator or its permissive users in connection with Contract
Services. Such coverage shall be written in an amount not less than
$1,000,000 per occurrence.
iii. Excess (or Umbrella) Liability Coverage - Operator shall maintain
Excess (or Umbrella) Liability insurance written on an occurrence
basis or on an acceptable claims-made basis providing coverage for a
limit
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of $9,000,000 per occurrence and annual aggregate in excess of the
insurance required in Sections 7(a)(ii) and 7(a)(v).
iv. Subcontractor Insurance - Operator shall require all of Operator's
subcontractors to obtain, maintain and keep in force during the time
in which they are engaged in performing services hereunder
reasonably adequate coverage in accordance with Operator's normal
practice (but not less than Worker's Compensation insurance written
in accordance with statutory limits and Employer's Liability,
Comprehensive Automobile Liability and Commercial General Liability
each with limits of not less than $1,000,000 per occurrence and in
the aggregate) and furnish Owner with acceptable evidence of such
insurance upon its request.
v. Commercial General Liability Coverage. Commercial or Comprehensive
General Liability insurance with a combined single limit of not less
than $1,000,000 per occurrence and in the annual aggregate. Such
coverage shall also include premises/operations, explosion,
collapse and underground hazard, broad form contractual,
products/completed operations, independent contractors, broad form
property damage and personal injury.
vi. Property and Boiler and Machinery Coverage. Property and Boiler and
Machinery insurance on an "all risk" replacement cost basis with
extended coverages, providing coverage for the Facility and Ash
Landfill, Facility Equipment and Ash Landfill Equipment, which shall
include coverage for removal of debris and shall insure the
buildings, structures, boiler and machinery, equipment, facilities,
fixtures and other properties constituting a part of the Facility
and Ash Landfill in an amount satisfactory to Owner with a
deductible of not greater than $1,000,000.
(b) Deductibles. All deductibles or self-insured retentions for the coverages
specified in Section 7(a) shall be the sole responsibility of Operator.
(c) Endorsements. Any insurance policies provided in accordance with Section
7(a) shall be endorsed to provide that if any insurance policy is canceled
for any reason whatsoever, or any substantial change is made in the
coverage that affects the interest of Owner, UPA, Anoka County, Hennepin
County, Sherburne County or the Tri-County Commission, the cancellation or
change shall not be effective as to Owner until thirty (30) days after
receipt by Owner of written notice sent by registered mail from the
insurer of such cancellation or change or ten (10) days in the event of
nonpayment of premiums. In
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addition, any insurance provided in accordance with Sections 7(a) (ii),
(iii), (iv), (v), and (vi) shall be endorsed to provide that:
i. Owner, UPA, Anoka County, Sherburne County, Hennepin County and the
Tri-County Commission shall be additional insureds in each case with
the understanding that any obligation imposed upon Operator
(including the liability to pay premiums) shall be the sole
obligation of Operator and not that of Owner or the other additional
insureds.
ii. The insurer waives all rights of subrogation against Owner or any
other additional insured and any other right to deduction due to
outstanding premiums, whether by attachment or otherwise. This
provision shall apply to the insurance provided under Section
7.2(a)(i) as well.
iii. The insurance shall be primary without right of contribution of any
other insurance carried by or on behalf of Owner, or any other
additional insured with respect to its interest as such in the
Facility or Ash Landfill.
iv. To the extent the policies are written to cover more than one
insured, all terms, conditions, insuring agreements and endorsements
(other than the limits of liability) shall operate in the same
manner as if there were a separate policy covering each insured.
Any insurance provided in accordance with Section 7(a)(i) shall be
endorsed to provide that the insurer thereunder waives all rights of
subrogation against Owner and the additional insureds and any other
right to deduction due to outstanding premiums, whether by
attachment or otherwise.
(d) On the Effective Date, and each Contract Year thereafter, the
Parties shall arrange to furnish each other with an approved
certificate reflecting all required insurance and copies of
policies, if requested. Such certification shall be executed by each
insurer or by an authorized representative of each insurer. Such
certificate or notice, as the case may be, shall identify insurers,
the type of insurance, the insurance limits, the policy term and
shall specifically list the special provisions enumerated for such
insurance required by this Article VII.
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7.3 Owner Provided Insurance.
(a) Owner shall carry and maintain, or cause to be maintained,
throughout the Term of this Agreement, at its own expense, insurance
with coverage as follows:
i. Excess (or Umbrella) Liability Coverage. Owner shall maintain
excess (or Umbrella) Liability Insurance providing coverage
for a limit of $9,000,000 per occurrence and in the annual
aggregate in excess of any Commercial General Liability
insurance carried by Owner.
ii. Worker's Compensation and Employer's Liability Coverage Owner
shall maintain or cause to be maintained Worker's Compensation
insurance written in accordance with statutory limits and
Employer's Liability in an amount not less than $1,000,000 per
occurrence and in the annual aggregate. The Employer's
Liability coverage shall not contain an occupational disease
exclusion. Such policy or policies shall contain an all states
endorsement or stop gap endorsement and alternate employer
coverage.
iii. Comprehensive Automobile Liability Coverage - Owner shall
maintain or cause to be maintained Comprehensive Automobile
Liability insurance covering all owned, non-owned and hired
vehicles used by Owner or its permissive users in connection
with Contract Services. Such coverage shall be written in an
amount not less than $1,000,000 per occurrence.
(b) Deductibles. All deductibles for the coverages specified in Section
7.3.(a), (i), (ii), and (iii) shall be the sole responsibility of
Owner, except that Operator shall be responsible for such
deductibles to the extent the claim arises out the negligence or
willful misconduct of Operator, or Operator's breach of this
Agreement, in the performance of the Contract Services not to exceed
$100,000 per occurrence pursuant to Section 7.3(a) (i) or $200,000
per occurrence pursuant to Section 7.3 (a)(ii) and (iii). Any such
deductible or self-insured retention paid by Operator shall not be
deemed to be a Reimbursable Cost hereunder.
(c) Endorsements. Any insurance provided in accordance with Section
7.3(a) shall be endorsed to provide that Operator shall be an
insured for losses occurring at the Facility or Ash Landfill with
the understanding that, except as expressly provided in Section
7.3(b), any
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obligation imposed upon Owner (including the liability to pay
premiums) shall be the sole obligation of Owner and not that of
Operator. To the extent policies are written to cover more than one
insured, all terms, conditions, insuring agreements and endorsements
(other than the limits of liability) shall operate in the same
manner as if there were a separate policy covering each insured.
7.4 Optional Insurance Responsibilities.
If requested by Owner in writing, Operator shall assist Owner in obtaining
for its own account the insurance Owner is required to maintain pursuant
to Section 7.3(a) subject to Owner reimbursing Operator for its reasonable
costs incurred in providing such assistance.
ARTICLE VIII
DISPUTE RESOLUTION
8.1 Arbitration and Mediation Standards.
(a) Any controversy or claim arising out of or relating to the
Agreement, or the breach thereof, shall be subject to resolution by
mediation or binding arbitration as set forth in this Article VIII.
(b) Prior to initiation of mediation and arbitration, the Owner
Representative and Operator Representative designated under Article
16.3 or other persons designated by the Parties shall meet for the
purposes of discussing and resolving the controversy or claim. If
the dispute is not resolved within 30 days, the Parties agree to
submit the dispute to mediation in accordance with the commercial
mediation rules of the American Arbitration Association, or other
mediation procedures agreed to by the Parties, before proceeding to
arbitration. The Parties agree to each pay one-half the costs of the
mediation.
8.2 Mediation Procedure.
(a) The Parties shall have ten days to agree upon a mutually acceptable
and neutral mediator and, if the parties cannot so agree, they shall
jointly request the American Arbitration Association or other agreed
mediation service to propose potential mediators and to assist in
the selection of a disinterested mediator.
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(b) The Parties shall, with the mediator, devise procedures appropriate
for negotiating a resolution of the dispute(s). The Parties agree to
participate in good faith in the mediation and related negotiations,
and to expeditiously exchange information and documents necessary
for the fair and full discussion of the dispute(s).
(c) The mediator shall be disqualified as a witness, consultant, expert,
or counsel for either party with respect to the dispute(s) and any
related matters. The Parties agree that the mediator shall not be
liable to either party for any statement, action or omission related
to the mediation. The mediator shall keep confidential all
information disclosed in private discussions with either Party when
that Party has requested that the information be kept confidential.
(d) The Parties agree that the mediation procedure is a compromise
negotiation for purposes of the Federal Rules of Evidence and any
State rules of evidence. The entire procedure is confidential, and
no stenographic, visual or audio record shall be made. All conduct,
statements, promises, offers, views and opinions, whether oral or
written, made in the course of the mediation by either of the
Parties, their agents, employees, representatives or other invitees
and by the mediator (who will be the Parties' joint agent for
purposes of these compromise negotiations) are confidential and
shall, in addition and where appropriate, be deemed to be work
product and privileged. Such conduct, statements, promises, offers,
views and opinions shall not be discoverable or admissible for any
purposes, including impeachment, in any litigation or other
proceeding involving the Parties, and shall not be disclosed to
anyone not an agent, employee, expert, witness, or representative of
either of the Parties; provided, however, that evidence otherwise
discoverable or admissible is not excluded from discovery or
admission as a result of its use in the mediation.
(e) The Parties agree to participate in the mediation for a period of 30
days, which period may be extended by agreement. If the Parties are
not successful in resolving the dispute(s) through mediation, then
they agree to submit the unresolved dispute(s) or portions thereof
to binding arbitration as provided in Section 8.3.
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8.3 Arbitration Procedure.
All disputes arising between the Parties which relate to the validity,
interpretation or performance of this Agreement, and which are not
successfully resolved by the Parties or through the mediation process
prescribed in Article 8.2, shall be submitted to arbitration at the
request of either party to the dispute, in accordance with the Commercial
Arbitration Rules of the American Arbitration Association then in effect,
and with the following provisions.
(a) The demand for arbitration shall be filed in writing with the other
party to this Agreement and with the Minneapolis, Minnesota office
of the American Arbitration Association within ten days of the
conclusion of mediation. No arbitration initiated by the Parties
shall include by consolidation, joinder or in any other manner, any
other person unless such person and both Parties agree to the
inclusion and unless such person is substantially involved in a
common question of law or fact or its presence is required if
complete relief is to be accorded in the arbitration. This agreement
to arbitrate between the Parties, and any fully executed subsequent
agreement to arbitrate with a third party, shall be specifically
enforceable under the Minnesota or federal arbitration act,
whichever is applicable.
(b) If the dispute(s) submitted to arbitration is identified as
involving claims whose total value exceeds $250,000, the Parties
shall be entitled to utilize the discovery provisions contained in
Minnesota Rules of Civil Procedure 26-37 and 45 with the following
exceptions:
(1) Each party shall be limited to three depositions unless
approval of the arbitrator(s) is obtained for additional
depositions, which approval shall only be granted upon a
showing of good cause;
(2) Each party shall be restricted to no more than 25
interrogatories, with subparts counted as separate
interrogatories.
(3) All discovery issues shall be determined by order of the
arbitrators upon motion made to them by either Party. When a
Party is asked to reveal material which the Party considers to
be proprietary information or trade secrets, the Party shall
bring the matter to the attention of the arbitrators who shall
make such protective orders as are reasonable and necessary or
as are otherwise provided by law.
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(c) The arbitrators shall have jurisdiction and authority to interpret,
apply, or determine compliance with the provisions of this Agreement
insofar as shall be necessary to the determination of issues
properly before the arbitrators. In making the decision, the
arbitrators shall issue appropriate findings and conclusions
regarding the issues. The arbitrators shall not have jurisdiction or
authority to alter the provisions of this Agreement or any
applicable law or rule of civil procedure. The arbitrators shall
have the authority to require either Party to specifically perform
its obligations under this Agreement. The arbitrators shall render a
decision within sixty (60) days after the completion of the hearing
on the matter.
(d) The arbitration shall be closed to observation or monitoring by
third parties.
(e) The award rendered by the arbitrator(s) shall be final and judgment
may be entered upon it in accordance with applicable law in any
court having jurisdiction. Any decision (including orders arising
out of disputes as to the scope or appropriateness of a request for,
or a response to, discovery) of the arbitrators may be enforced in
state or federal district court, whichever is applicable, with all
costs, including attorneys fees, paid by the losing Party. Nothing
in Article VIII shall prohibit a Party from instituting litigation
to enforce a final decision of the arbitrators.
(f) The administrative expense of any arbitration, including
compensation for the arbitrator(s), shall be borne and paid equally
by the Parties unless the arbitrator(s) finds that the position
taken by either Party on any issue is not substantially justified,
in which case all or part of the costs and fees of the Party
prevailing on that issue shall be awarded to it. Except as provided
herein, each Party shall bear its own costs and fees.
(g) All arbitration proceedings under this Article 8 shall take place in
Minneapolis, Minnesota at a location agreed upon by the Parties and,
in the event of failure to agree, the arbitrators shall determine
the most convenient location based on the location of the majority
of the documentary evidence and prospective witnesses.
(h) Pending the final decision of the arbitrators, the Parties agree to
diligently proceed with the performance of all obligations,
including the payment of all sums, required by this Agreement. To
the extent practicable and consistent with all Laws and Permits, RDF
Facility Agreements and Loan Agreement the interpretation or
decision of the
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nonaggrieved party shall take precedence until the dispute is
resolved, but shall not relieve the nonaggrieved Party from any
liability resulting from such interpretation or decision to the
extent it is ultimately determined to be wrong by the arbitrators.
(i) Nothing in this Article VIII shall preclude a Party from seeking
specific performance of this Agreement or similar injunctive relief
in state or federal court if the Party seeking such equitable relief
would otherwise be irreparably harmed by the passage of time
involved for the completion of the mediation and arbitration
processes set forth in this Article. Any judicial decree or order
granting such specific performance shall be effective only to the
extent and for the time period necessary to prevent the irreparable
harm specifically found by the court. Final resolution of any
underlying dispute, or related issues, shall still occur pursuant to
the provisions of this Article VIII.
8.4 Compromise and Settlement.
(a) Except as may be necessary for (i) any review by the MPUC, FERC, or
other Governmental Authority; or (ii) any enforcement proceeding
under Section 8.3(e), no communications sent or documents delivered
by either Party because of a proceeding under Article VIII shall be
disclosed by the other Party to a third person if that communication
or document contains the caption "Privileged and Confidential;
Settlement Proceedings" or similar caption.
(b) Except as may be necessary for (i) any review by the MPUC, FERC or
other rate regulatory agency of any matter determined to be within
its exclusive jurisdiction; or (ii) any enforcement proceeding, the
arbitrators' decision shall be deemed to be a settlement between the
Parties and the decision shall be treated as a settlement for all
purposes in the future.
8.5 Effect of Termination.
This Article VIII shall survive the termination of the Agreement as
necessary to resolve any disputes arising out of, in connection with, or
relating to the Agreement.
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ARTICLE IX
TERM
9.1 Effective Date.
This Agreement shall not become effective until the Effective Date, which
shall be the first day after all conditions precedent identified in this
Section 9.1 have been fully and satisfactorily performed and satisfied:
(a) The Agreement has been executed by authorized representatives of
Owner and Operator.
(b) Any consent to this Agreement which is required from a party to any
RDF Facility Agreement, the Loan Agreement, or the UPA Agreement has
been received in writing by Owner in a form executed by an
authorized representative of the party. Operator and Owner are not
aware of any such necessary consent at this time.
(c) The MPUC approves the Agreement in a Final Nonappealable Order,
pursuant to Minnesota Statutes Chapter 216B, in which the MPUC finds
that the amounts to be paid to Seller under the Agreement are
reasonable and in the public interest. In the event NSP is unable to
obtain a Final Nonappealable Order of the MPUC specifically
approving the Agreement without significant modification to the
Agreement by the MPUC, the Agreement shall terminate unless NSP and
Seller mutually agree in writing to accept the modification.
9.2 Term.
This Agreement shall remain in full force and effect until December 31,
2003, or until the expiration or termination of all of the RDF Facility
Agreements and UPA Agreement, whichever is earlier.
9.3 Options to Extend.
Owner shall have the option to extend the term of this Agreement for up to
two additional three (3) year terms. To exercise its options, Owner shall
provide written notice to Operator of its intent to exercise the option no
later than 180 days prior to the expiration of the Term.
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9.4 Services Prior to Effective Date.
Services provided by Operator since the Commencement Date and prior to
January 1, 1996 shall be paid for and performed in accordance with the
Administrative Agreement, including appropriate compensation or offsets
for Owner Provided Services. To the extent practicable and approved by the
MPUC the Parties shall begin performance of this Agreement as of January
1, 1996 and the First Contract Year shall be deemed to be calendar year
1996. If the MPUC fails to approve this Agreement, including the
provisions for Operator's fees, for any portion of the period between
January 1, 1996 and the Effective Date, Operator shall be entitled only to
reimbursement as allowed by the Administrative Agreement and the MPUC.
9.5 Termination.
This Agreement may be terminated only by mutual written agreement of the
Parties, pursuant to the default provisions of Article XV, or under the
following circumstances:
(a) Upon damage to, or destruction of, a substantial portion of the
Facility or Ash Landfill, which cannot reasonably be expected to be
repaired or rebuilt within one calendar year;
(b) if the Effective Date does not occur within six months of the date
this Agreement is executed.
9.6 Termination Procedure.
(a) Upon the effective date of termination of this Agreement authorized
under Section 9.5, the Operator shall (i) discontinue performance of
the Contract Services, (ii) place no further orders or subcontracts
for Materials, Equipment, Supplies, services, or labor, except as
authorized in advance by Owner or required of Operator to avoid
giving rise to an Event of Default under this Agreement, (iii) make
every reasonable effort to obtain cancellation of affected
subcontracts or, at Owner's request, cause the assignment of any
such contracts to Owner or its replacement operator upon terms
satisfactory to Owner, and (iv) take such other action as may be
reasonably requested by Owner for the orderly closeout and
transition of Operator's operation and maintenance activities,
including cooperation with any replacement operator. After deduction
of any amounts owed by Operator to Owner, upon termination pursuant
to this Article, Owner shall pay, or cause to be paid, to Operator
(A) the amount, if any due and payable to Operator pursuant to this
Agreement up to and including the date of
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termination, and (B) except in the case of a termination of Operator
pursuant to Article X, all reasonable documented costs incurred by
Operator for its own efforts to implement termination and the
resulting reasonable costs actually incurred for turnover and
demobilization, excluding any loss of anticipated profit. Such
payments to Operator shall not duplicate any other payments
hereunder made to Operator. Operator and Owner shall use reasonable
efforts to minimize all termination costs.
(b) Other than as set forth in this Section 9.6, Owner shall have no
liability to Operator for costs, expenses or losses of any kind or
nature incurred by Operator as a result of such termination. In no
event shall the aggregate payments of Owner hereunder exceed the
amount due for the then-current Contract Year, pro-rated for any
partial Contract Year. Within sixty (60) Days following the
effective date of termination, Operator shall submit to Owner its
final invoice statement which Owner shall review and make payments
on in accordance with the provisions of Article VI. Upon Operator's
receipt of final payment in full from Owners, this Agreement shall
terminate and neither Party shall have any further obligation to the
other Party except with respect to those provisions of this
Agreement which by their terms survive.
ARTICLE X
INDEMNIFICATION
10.1 Indemnity.
Operator and Owner agree to defend, indemnify, and hold each other, and
their respective officers, directors, employees, and agents, harmless from
and against all claims, demands, losses, liabilities, and expenses
(including reasonable attorneys' fees) (collectively "Damages") for
personal injury or death to persons and damage to each other's physical
property or facilities or the property of any other person or corporation
to the extent arising out of, resulting from, or caused by the negligent
or intentional acts, errors, or omissions of the indemnifying Party.
Furthermore, each Party shall defend, indemnify, and hold the other
harmless from and against all damages that are or were incurred or
suffered by the indemnified Party and which relate to the indemnifying
Party's breach or failure to perform any of the covenants, agreements,
obligations, representations, or warranties contained in the Agreement,
except as provided in Section 10.2. Nothing in this section shall relieve
Operator or Owner of any liability to the other for any breach of the
Agreement. This indemnification shall apply notwithstanding the active or
passive negligence of the indemnitee. Neither Party shall be indemnified
to
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the extent its Damages result from its sole negligence or willful
misconduct. These indemnity provisions shall not be construed to relieve
any insurer of its obligation to pay claims consistent with the provisions
of a valid insurance policy.
10.2 Limitation of Liability.
(a) For all claims, causes of action and damages the Parties shall be
entitled to the recovery of actual damages allowed by law unless
otherwise limited by the Agreement.
(b) Except as otherwise specifically and expressly provided in the
Agreement, no Party shall be liable to the other Party under the
Agreement for any indirect, special, or consequential damages,
including but not limited to, loss of use, loss of revenue, loss of
profit, interest charges, cost of capital, or claims of its
customers to which service is made from any cause, except to the
extent such damages are covered under an insurance policy for the
benefit of the liable Party. Notwithstanding the foregoing, the
arbitrators under Article VIII can award consequential damages
against a Party which willfully violates its obligations under the
Agreement with knowledge that the other Party is suffering
consequential damages if the arbitrators determine that such an
award appears necessary to prevent repetition of such willful
misconduct. In no event shall one Party's liability to the other
exceed any limit of liability established for either Party under any
Requirement of law.
(c) Notwithstanding the limitation set forth in Section 10.2(b),
Operator shall be liable for all damages, including, but not limited
to, loss of use, loss of revenue, loss of profit, and other
indirect, special or consequential damages suffered or incurred by
Owner, directly or through claims or causes of actions by others,
arising from or relating to the occurrence of any breach, event of
default, or failure to comply with the terms of any RDF Facility
Agreement, UPA Agreement or Loan Agreement to the extent caused by
Operator's negligent acts or omissions, willful misconduct, or
breach of this Agreement.
10.3 Survival.
The indemnity obligation of Section 10.1 and any other indemnity
obligation provided under this Agreement shall survive the expiration of
the term or termination of this Agreement for any reason and shall remain
in full force and effect. All waivers and disclaimers of liability,
releases from liability and limitations on liability shall also survive
the expiration of the Term or
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termination of the Agreement and shall apply at all times unless otherwise
expressly indicated.
10.4 Notice of Litigation.
If any Party indemnified pursuant to this Article X or otherwise under
this Agreement (each an "Indemnified Party" and collectively the
"Indemnified Parties") receives notice or acquires knowledge of any claim
that may reasonably result in a claim for indemnification by such
Indemnified Party against the other Party (the "Indemnifying Party")
pursuant to this Article X or otherwise, the Indemnified Party shall, as
promptly as possible, give the Indemnifying Party notice of such claim,
including a reasonably detailed description of the facts and circumstances
relating to such claim, and a complete copy of all notices, pleadings and
other papers related thereto, and the basis for its potential claim for
indemnification in reasonable detail and shall cooperate with the
Indemnifying Party in responding to the claim.
Subject to the limitations on the Indemnifying Party's indemnity
obligations, the Indemnifying Party shall assume on behalf of the
Indemnified Party, and conduct with due diligence and good faith the
defense of, any suit against one or more of the Indemnified Parties,
whether or not the Indemnifying Party is joined as a party. Without
relieving the Indemnifying Party of its obligations and subject to the
Indemnifying Party's control over the defense and settlement of any suit,
the Indemnified Party may elect to participate in the defense of any suit,
at its own expense. The Indemnifying Parties' indemnity is for the
exclusive benefit of the Indemnified Parties and their assignees and in no
event shall inure to the benefit of any other Person.
10.5 Cost Treatment.
Any amounts paid by Operator to Owner or otherwise arising from or related
to any indemnified claim pursuant to Section 10.1 or other indemnity
obligations of this Agreement shall not be Reimbursable Costs and shall be
paid at Operator's sole cost and expense.
10.6 Limitation of Liability.
With the exception of liabilities arising from Operator's indemnity and
similar obligations pursuant to Section 10.1, 3.17, 6.4, 6.8, 11.4 and
13.3, and the payment of deductibles for coverage provided under Section
7.2(b) which are expressly not governed by this Section, Operator's
aggregate liability to Owner with respect to any and all claims arising
out of the performance or nonperformance of its obligations under this
Agreement, whether based in
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contract, tort, warranty or otherwise shall not exceed, net of all
insurance proceeds applied to each such liability or related claim:
(i) For all claims arising and for which damages accrue solely within
one Contract Year, the amount of $1,000,000 or the total of the
Management Fee and Performance Bonus due to Operator for that
Contract Year, whichever is less.
(ii) for all claims made or for which damages accrue on a continuing
basis or over more than one Contract Year, the amount of $3,000,000
multiplied by the number of Contract Years or the total of the
Management Fee and Performance Bonus due to Operator for the
affected Contract Year, less any amounts paid pursuant to the
preceding subparagraph (i) for each of the Contract Years whichever
is less.
ARTICLE XI
REPRESENTATIONS AND WARRANTIES
11.1 Representations by Operator.
Operator represents and warrants to Owner:
(a) (i) Operator is duly organized, validly existing and in good
standing under the laws of the jurisdiction of its formation;
(ii) has the power and authority to own and operate its business
and property, to own or lease the property it occupies and to
conduct the business in which it is currently engaged;
(iii) is duly qualified as a corporation in Delaware and is in good
standing under the laws of Minnesota and each jurisdiction
where its ownership, lease or operation of property or the
conduct of its business requires such qualification and the
failure to be so qualified would have a material adverse
affect on the business, operations, financial condition or
prospects of Operator;
(iv) is in compliance with all material Requirements of Law,
applicable to Operator or its operations; and
(v) is in compliance with all material Contractual Obligations
applicable to Operator or its operations.
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(b) The execution, delivery, performance and observance by Operator of
its obligations under the Agreement is within Operator's powers,
have been duly authorized by all necessary corporate action and do
not and will not:
(i) require any consent or approval of the shareholders of
Operator which has not been obtained;
(ii) contravene, conflict or violate any provision of any
Requirement of Law presently in effect having applicability to
Operator;
(iii) require the consent or approval of or filing or registration
with any Governmental Authority or other Person which is not
specified as a condition precedent to the Agreement;
(iv) result in a breach of or constitute a default under any
Contractual Obligation.
(c) The Agreement is a legal, valid and binding obligation of Operator,
is enforceable against Operator in accordance with its respective
terms except as enforceability may be limited by applicable
bankruptcy, insolvency, reorganization or similar laws affecting the
enforcement of creditors' rights generally.
(d) No litigation, arbitration, investigation or other proceeding is
pending or threatened against Operator, except as listed on Exhibit
E,
(i) with respect to the Agreement or the transaction contemplated
thereby, the Facility, Ash Landfill, RDF Facility Agreements,
UPA Agreement or Loan Agreement; or
(ii) which would, if adversely determined, have a material adverse
effect on the business, operations, property or financial or
other condition of Operator taken as a whole, or the ability
of Operator to perform its obligations under the Agreement.
(e) To the best of Operator's knowledge and belief, no exhibit,
contract, report or document furnished by Operator to Owner in
connection with the negotiation or execution of the Agreement
contains any material misstatement of fact or omits to state a
material fact or any fact necessary to make the statements contained
therein not misleading.
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(f) To the best of Operator's knowledge and belief, all Permits required
by any Governmental Authority for the operation and maintenance of
the Facility and Ash Landfill have been obtained and are valid and
in full force and effect. The Facility and Ash Landfill are in
compliance with each Permit as of the date of this Agreement, and
Operator has received no notice and is not otherwise aware of any
default, violation or potential default or violation of any such
Permit.
(g) Operator has filed or caused to be filed all tax returns which were
required to be filed and has paid all taxes shown to be due and
payable on said returns or on any assessments made against it or any
of its property and all other taxes, fees or other charges imposed
on it or any of its property by any Governmental Authority; and no
tax liens have been filed and no claims are being asserted with
respect to any such taxes, fees or other charges.
(h) The Facility and Ash Landfill have been and are currently operated
in full compliance with all Environmental Laws and operated in full
compliance with all Permits, licenses, rules or orders promulgated,
issued or otherwise required by a Governmental Authority having
jurisdiction or enforcement power over any Environmental Law.
Operator has no knowledge of and has not received notice of any
past, present or future actions or plans which, with respect to the
Facility or Ash Landfill, may interfere with or prevent compliance
or continued compliance with Environmental Laws or may give rise to
any liability under any Environmental Law or to any common law or
legal liability or otherwise form the basis of any claim, action,
demand, suit, proceeding, hearing, study or investigation under the
Environmental Laws and there is no civil, criminal or administration
action, suit, demand, claim, hearing notice or demand letter, notice
of violation, investigation or proceeding pending or threatened
against Operator relating to the compliance with any Environmental
Law of the Facility or Ash Landfill.
(i) Operator intends to operate and maintain the Facility and Ash
Landfill in accordance with the Standards of Performance, applicable
Laws and Permits, the RDF Facility Agreements, Loan Agreement, and
the terms of this Agreement.
(j) No Event of Default or Potential Event of Default exists hereunder.
11.2 Owner's Representations.
Owner represents and warrants to Operator:
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(a) (i) Owner is duly organized, validly existing and in good standing
under the laws of the jurisdiction of its formation;
(ii) has the power and authority to own and operate its business
and property, to own or lease the property it occupies and to
conduct the business in which it is currently engaged;
(iii) is duly qualified as a corporation in Minnesota and is in good
standing under the laws of each jurisdiction where its
ownership, lease or operation of property or the conduct of
its business requires such qualification and the failure to be
so qualified would have a material adverse affect on the
business, operations, financial condition or prospects of
Owner;
(iv) is in compliance with all material Requirements of Law,
applicable to Owner or its operations; and
(v) is in compliance with all material Contractual Obligations
applicable to Owner or its operations.
(b) The execution, delivery, performance and observance by Owner of its
obligations under the Agreement is within Owner's powers, have been
duly authorized by all necessary corporate action and do not and
will not:
(i) require any consent or approval of the shareholders of Owner
which has not been obtained;
(ii) contravene, conflict or violate any provision of any
Requirements of Law presently in effect having applicability
to Owner;
(iii) require the consent or approval of or filing or registration
with any Governmental Authority or other Person which is not
specified as a condition precedent to the Agreement;
(iv) result in a breach of or constitute a default under any
Contractual Obligation.
(c) The Agreement is a legal, valid and binding obligation of Owner, is
enforceable against Owner in accordance with its respective terms
except as enforceability may be limited by applicable bankruptcy,
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insolvency, reorganization or similar laws affecting the enforcement
of creditors' rights generally.
(d) No litigation, arbitration, investigation or other proceeding is
pending or threatened against Owner, except as listed on Exhibit E.
(i) with respect to the Agreement or the transaction contemplated
thereby, the Facility, Ash Landfill, RDF Facility Agreements,
UPA Agreement or Loan Agreement; or
(ii) which would, if adversely determined, have a material adverse
effect on the business, operations, property or financial or
other condition of Owner taken as a whole, or the ability of
Owner to perform its obligations under the Agreement.
(e) To the best of Owner's knowledge and belief, no exhibit, contract,
report or document furnished by Owner to Operator in connection with
the negotiation or execution of the Agreement contains any material
misstatement of fact or omits to state a material fact or any fact
necessary to make the statements contained therein not misleading.
(f) Prior to the Commencement date, the Facility and Ash Landfill were
operated in full compliance with all Environmental Laws and operated
in full compliance with all Permits, licenses, rules or orders
promulgated, issued or otherwise required by a Governmental
Authority having jurisdiction or enforcement power over any
Environmental Law. Owner has no knowledge of and has not received
notice of any past, present or future actions or plans which, with
respect to the Facility or Ash Landfill, may interfere with or
prevent compliance or continued compliance with Environmental Laws
or may give rise to any liability under any Environmental Law or to
any common law or legal liability or otherwise form the basis of any
claim, action, demand, suit, proceeding, hearing, study or
investigation under any Environmental Law and there is no civil,
criminal or administration action, suit, demand, claim, hearing
notice or demand letter, notice of violation, investigation or
proceeding pending or threatened against Owner relating to the
compliance with any Environmental Law of the Facility or Ash
Landfill.
11.3 Owner's and Operator's Reliance.
Operator agrees and acknowledges that Owner is relying on and will
continue to rely on Operator's representations and warranties and, that
such reliance
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is reasonable, and that Owner will rely on such representations in its
filings and presentations to the MPUC in connection with this Agreement.
Owner agrees and acknowledges that Operator is relying on and will
continue to rely on Owner's representations and warranties and that such
reliance is reasonable.
11.4 Indemnity
If at any time during the Term of the Agreement any of the representations
and warranties made by either of the Parties are or become untrue, then
the Party which made the representation or warranty agrees to indemnify
and hold harmless the other Party against any and all claims, demands,
suits, actions, costs, and liabilities, damages, losses or judgments
arising out of, relating to or resulting from any such untrue
representation or warranty, as well as against any fees, costs, charges,
or expenses (including attorneys' fees) which the other Party might incur
in the defense of any such claim, suit, action or similar such demand made
or filed which may adversely affect the other Party as a consequence of
the untrue representation or warranty.
ARTICLE XII
FORCE MAJEURE
12.1 Force Majeure.
Neither Operator nor Owner shall be liable to the other for any failure
to perform pursuant to the terms and conditions of this Agreement to the
extent such performance was prevented by an event of Force Majeure. Force
Majeure as used in this Agreement means any event beyond the reasonable
control of the Party affected and which, with the exercise of due care,
the Party could not reasonably have been expected to avoid, including, but
not limited to, acts of God, explosions or fires, floods, hurricanes,
tornadoes, lightning, earthquakes, drought, epidemics, blight, famine,
quarantine, blockade, acts or inactions of Governmental Authorities, war,
insurrection or civil strife, rebellion, sabotage or strike. To be excused
from performance pursuant to this provision, however, the Party affected
must (i) give notice to the other Party, including full details of the
event of Force Majeure and its creation of an inability to perform, as
soon as practicable after the occurrence relied upon and (ii) exercise due
diligence to remove its inability to perform with all reasonable speed and
using all reasonable measures. The burden of proof to establish the
existence of an event of Force Majeure and any resulting inability to
perform on its part shall be on the Party seeking an excuse from
performance due to Force Majeure.
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12.2 Exclusions from Definition of Force Majeure.
Notwithstanding anything in the Agreement to the contrary, "Force Majeure"
shall not mean:
(a) Inclement weather affecting operation or maintenance of the Facility
or Ash Landfill.
(b) Changes in market conditions, governmental action, or weather
conditions that affect the cost of Operator's Contract Services,
Equipment, Materials, or Supplies.
(c) Unavailability of equipment, repairs or spare parts for the
Facility, Facility Equipment, Ash Landfill or Ash Landfill
Equipment, except where due to a strike against a third person which
was not reasonably foreseeable, and the consequences of which could
not be avoided by due care and planning.
(d) Inability to obtain, maintain or renew any Permit or any delay in
obtaining, maintaining, or renewing any Permit for any reason within
the control of the Party.
(e) Litigation or administrative or judicial action pertaining to the
Agreement, to the RDF Facilities, the acquisition, maintenance or
renewal of financing or any Permits, or the maintenance or operation
of the RDF Facilities.
(f) Any event to the extent caused by the negligence, willful misconduct
or breach of this Agreement by the Party claiming Force Majeure.
(g) Any event to the extent it could have been prevented by reasonable
diligence or was otherwise within the control of the Party claiming
Force Majeure.
(h) Any breakdown or failure of any mechanical or other component of the
Facility, Ash Landfill, Facility Equipment or Ash Landfill Equipment
which fully or partially curtails operations to the extent caused by
the design or construction of the component or the failure to
properly operate and maintain the component, irrespective of whether
the failure is attributable to the negligence or fault of the Party
asserting Force Majeure.
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(i) Failure to perform by any subcontractor, vendor, manufacturer,
supplier, provider or other third party unless the failure is also
caused by a qualifying event of Force Majeure as defined in this
Agreement. In this respect, the compliance of any Person contracting
with Operator or Owner with the terms of the applicable contract,
purchase order or other agreement shall be deemed to be within the
control of Owner or Operator, as applicable.
ARTICLE XIII
HAZARDOUS MATERIALS
13.1 Environmental Laws.
Any terms mentioned in the following subsections which are defined in
state local, or federal environmental statutes and/or regulations
promulgated in relation thereto shall have the meaning subscribed to such
terms in said statutes and regulations. These state, local and federal
environmental statutes, rules and regulations include, without limitation,
(1) the Comprehensive Environmental Response, Compensation, and Liability
Act (CERCLA), 42 U.S.C. Sections 9601-9657; (2) the 1986 Superfund
Amendments and Reauthorization Act (SARA), codified as a part of 41 U.S.C.
Section 9601 et seq.; (3) the Minnesota Environmental Response and
Liability Act (MERLA), Minn. Stat. Sections 115B.01-115B.17; (4) the
Resource Conservation and Recovery Act (RCRA), 42 U.S.C. Sections
6901-6987; (5) legislation and regulations governing underground storage
tanks (UST), including applicable federal laws and the Minnesota Petroleum
Tank Release Clean-Up Act, Minn. Stat. Sections 115C.01-115C.10; and (6)
state and federal laws creating any liens for clean-up costs, including
applicable provisions of SARA and comparable Minnesota laws, Minn. Stat.
Sections 514.671-514.676; (7) Groundwater Protection Act, Minn. Stat.
Sections 103H.001-103H.280; (8) the Clean Air Act, 42 U.S.C. Sections 7401
et seq.; (9) the federal Clean Water Act, 33 U.S.C. Sections 1321 et seq.;
(10) the Hazardous Materials Transportation Act, 49 U.S.C. Sections 1802
et seq.; (11) the Toxic Substances Control Act, 15 U.S.C. Sections 2601 et
seq.; (12) the federal Water Pollution Control Act, 15 U.S.C. Sections
2601 et seq.; and (13) any federal, state, county, municipal, local or
other statute, law, ordinance or regulation enforcing, governing or
related to the creation, handling, release, containment, transport or
disposal of any pollutant, contaminant, hazardous or unhealthy substance
or to human health or the environment; and any regulations interpreting,
applying or complementing each of the statutes described in clauses (1)
through (13). These statutes, rules and regulations, as amended from time
to time, are referred to collectively as the "Environmental Laws."
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The term "release" shall have the meaning specified in CERCLA and MERLA,
and the terms "solid waste" and "disposal" (or "disposed") shall have the
meanings specified in RCRA; provided, in the event CERCLA, SARA, RCRA,
MERLA or MPTRCA is amended so as to broaden the meaning of any term
defined thereby, such broader meaning shall apply subsequent to the
effective date of such amendment. "Hazardous Materials" means asbestos,
ureaformaldehyde, polychlorinated biphenyls ("PCBs"), nuclear fuel or
material, chemical waste, radioactive material, explosives, known
carcinogens, petroleum products and by-products and other dangerous, toxic
or hazardous pollutants, contaminants, chemicals, materials or substances
listed or identified in, or regulated by, any Environmental Laws.
13.2 Owner's Indemnity.
Owner agrees to indemnify, defend and hold Operator harmless from and
against any claim, suit, loss, cost, liability, fine or damage (including
reasonable attorneys' fees) arising from or assessed or incurred as a
result of any release or other violation of any Environmental Law based on
conditions existing at the Facility Site or Ash Landfill Site or created
prior to the Commencement Date, made or asserted by any Person, and
whether or not supported by fact or law.
13.3 Operator's Indemnity.
Operator agrees to indemnify, defend and hold Owner harmless from and
against any claim, suit, loss, cost, liability, fine or damage (including
reasonable attorneys' fees) arising from or assessed or incurred as a
result of any release or other violation of any Environmental Law based on
releases or other conditions occurring or created at the Facility Site or
Ash Landfill Site after the Commencement Date, including, but not limited
to, any negligent or culpable handling of Hazardous Materials in the
course of performing the Contract Services, made or asserted by any
Person, and whether or not supported by fact or law.
13.4 Hazardous Wastes.
Operator shall arrange for the proper collection, removal, transportation,
and disposal of any Hazardous Materials furnished, used, applied,
generated or stored at the RDF Facilities or emanating from the RDF
Facilities including, but not limited to, used oils, greases, and solvents
from flushing and cleaning processes performed under this Agreement. All
costs associated with the transportation and disposal of Hazardous
Materials to or from the RDF Facilities by Operator in connection with its
performance of the Contract
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Services pursuant to the terms of this Agreement shall be a Reimbursable
Cost. Operator shall comply with all applicable Laws and Permits in
collecting, handling, removing, transporting or disposing of any Hazardous
Materials, and shall be responsible for determining whether any material
or substance is a Hazardous Materials and for interpreting and applying
any Environmental Law.
ARTICLE XIV
DEFAULT
14.1 Events of Default.
The following occurrences or events, or any of them, by or against either
Operator or Owner, shall constitute an Event of Default under this
Agreement.
(a) A material breach of any of the terms, conditions, warranties,
covenants, or representations expressed in this Agreement; or
(b) the filing of a petition commencing a voluntary case under the
Federal Bankruptcy Code or for liquidation, reorganization or any
similar arrangement under federal or state law relating to
bankruptcy, insolvency, winding up or adjustment of debts; or
(c) the admission in writing of its insolvency or inability to pay its
debts generally as they become due or the acquiescence in or consent
to any involuntary case commenced as described in Section 15.1(d)
or the declaration of such Party as bankrupt or insolvent under the
Federal Bankruptcy code or any other federal or state law relating
to bankruptcy, insolvency, winding up or adjustment of debts; or
(d) the filing of a petition against it commencing an involuntary case
under the Federal Bankruptcy Code or proposing the adjudication of
such Party as a debtor or bankrupt or proposing its liquidation or
reorganization pursuant to any federal or state law relating to
bankruptcy, insolvency, winding up or adjustment of debts; or
(e) the dissolution of any Party or failure to maintain such Party's
good standing or qualification to do business in the State of
Minnesota or state of organization; or
(f) an assignment for the benefit of creditors.
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(g) with respect to the Operator, an Event of Default occurs under any
of RDF Facility Agreements or Loan Agreement due to the negligent or
intentional acts or omissions of the Operator or Operator's breach
of this Agreement.
14.2 Notice of Event of Default and Cure Rights.
(a) For any Event of Default arising under Sections 15.1(a) and (e),
the right of termination granted under Section 15.3 shall be subject
to a written notice of the Event of Default. Unless the nature of
the default requires more immediate action to cure, which shall be
set forth in the notice, the defaulting Party shall be provided
thirty (30) calendar days from the date of receipt of the notice to
cure the Event of Default. Failure to cure the default within this
thirty (30) day period shall constitute a material breach of the
Agreement granting to the nondefaulting Party the right to terminate
the Agreement pursuant to Section 15.3.
(b) For any Event of Default described by Sections 15.1(b), (c), (d)
and (f), notice of default shall not be required and termination may
be effected in accordance with Section 15.3 by the nondefaulting
Party to the extent permitted by applicable law.
(c) For any Event of Default by Operator pursuant to Section 15.1(g),
Owner shall immediately provide written notice to Operator of the
Event of Default, along with a copy of any notice of default
received by Owner with respect to the underlying agreement in
default or a description of the default in reasonable detail.
Operator shall have the balance of any cure period provided to Owner
under the agreement in default to cure the underlying default. If
Operator fails to cure the underlying default within the available
cure period, Owner shall have the right to terminate this Agreement
pursuant to Section 15.3.
14.3 Termination; Waiver.
(a) In the event the defaulting Party fails to correct the Event of
Default within the period for curative action under Section 15.2 of
the Agreement with respect to the Events of Default outlined in
Sections 15.1(a), (e) and (g) or upon the occurrence of any other
Event of Default set forth in Sections 15.1(b), (c), (d) and (f) or
15.5, the nondefaulting Party may terminate the Agreement at its
sole discretion by notifying the defaulting Party in writing of the
nondefaulting Party's intent to terminate the Agreement and of the
effective date of such termination.
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(b) Upon the occurrence of an Event of Default or subsequent termination
resulting from an Event of Default, the nondefaulting Party shall
have the right to pursue any and all legal and equitable remedies,
including specific performance and including all actual damages and
remedies as provided under the Agreement or related documents,
against the defaulting Party and shall be entitled to recover from
the defaulting Party all expenses (including reasonable attorneys'
fees) incurred by the nondefaulting Party in connection with the
pursuit of such remedies.
(c) Any waiver at any time by either Party of its rights with respect to
an Event of Default under the Agreement, or with respect to any
other matters arising in connection with the Agreement, shall not be
a waiver with respect to any subsequent default or other matter.
14.4 Obligations Upon Termination.
In the event that Owner elects to terminate this Agreement as a result of
Operator's default and without limiting any other right or remedy of
Owner, Owner may employ any other person, firm or corporation to perform
the Contract Services by whatever method Owner may deem expedient.
Furthermore, Operator shall, at Owner's expense, perform the following
services relative to the Contract Services affected by its default,
regardless of whether or not Owner elects to terminate this Agreement as a
result of such default:
(a) assist Owner in preparing an inventory of all Equipment, Materials,
or Supplies in use or in storage at the Facility and Ash Landfill;
and
(b) assign to Owner such subcontracts and other contractual agreements
relating to Operator's performance of the Contract Services as may
be designated by Owner. Furthermore, Operator shall execute all
documents reasonably requested by Owner and take such other steps as
are reasonably requested by Owner that may be required to assign and
vest in Owner or its designee all rights, benefits, interests and
title in connection with the contracts or obligations; and
(c) For a period not to exceed 90 days, assist Owner in training
Operator's successor and effectuating the transition to a successor
Operator.
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ARTICLE XV
MISCELLANEOUS
15.1 Non-Assignment.
The rights and obligations of this Agreement may not be assigned by either
Party without the prior written consent of the other Party, which consent
shall not be unreasonably withheld. Any purported assignment of this
Agreement in the absence of the required consent shall be void.
15.2 Notices.
Any notice, demand, request, or communication required or authorized by
the Agreement shall be delivered either by hand, facsimile, overnight
courier or mailed by certified mail, return receipt requested, with
postage prepaid, to:
Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
Attn:______________
on behalf of Owner; and to:
NRG Energy, Inc.
1221 Nicollet Mall, Suite 700
Minneapolis, MN 55403-2445
Attn:_____________________
on behalf of the Operator. The designation and titles of the person to be
notified or the address of such person may be changed at any time by
written notice. Delivery of any such notice, demand, request, or
communication shall be deemed delivered on receipt if delivered by hand or
facsimile and on deposit by the sending party if delivered by courier or
U.S. mail.
15.3 Captions.
All titles, subject headings, section titles and similar items are
provided for the purpose of reference and convenience and are not intended
to be inclusive, definitive or to affect the meaning of the contents or
scope of the Agreement or any of its provisions.
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15.4 No Third-Party Beneficiary.
No provision of the Agreement is intended to nor shall it in any way inure
to the benefit of any third party, so as to constitute any such person a
third-party beneficiary under the Agreement, or of any one or more of the
terms hereof, or otherwise give rise to any cause of action in any person
not a Party hereto.
15.5 Entire Agreement Modification and Waiver.
The Agreement, together with all exhibits attached hereto, constitutes the
entire agreement between the Parties relating to the transaction described
and supersedes any and all prior oral or written understandings. No
amendment, addition to, or modification of any provision hereof shall be
binding upon the Parties, and neither Party shall be deemed to have waived
any provision of any remedy available to it unless such amendment,
addition, modification or waiver is in writing and signed by a duly
authorized officer or representative of the applicable Party or Parties.
15.6 Governing law.
The Agreement is made in the State of Minnesota and shall be interpreted
and governed by the laws of the State of Minnesota without giving effect
to its conflict of law provisions, and/or the laws of the United States,
as applicable.
15.7 Contract Drafting.
The Parties expressly agree that neither Party shall be deemed solely
responsible for drafting all or any portion of the Agreement and, in the
event of a dispute, responsibility for any ambiguities arising from any
provision of the Agreement shall be shared equally by both Parties.
15.8 Form of Business Relationship.
(a) The duties, obligations, and liabilities of the Parties are intended
to be several and not joint or collective. The Agreement shall not
be interpreted or construed to create an association, joint venture,
fiduciary relationship or partnership between Operator and Owner or
to impose any partnership obligation or liability or any trust or
agency obligation or relationship upon either Party. Operator and
Owner shall not have any right, power, or authority to enter into
any agreement or undertaking for, or act on behalf of, or to act as
or be an agent or representative of, or to otherwise bind, the other
Party.
53
<PAGE> 54
(b) The relationship between Owner and Operator shall be that of
contracting party to independent contractor. Accordingly, subject to
the specific terms of the Agreement, Owner shall have no general
right to prescribe the means by which Operator shall meet its
obligations under the Agreement.
(c) Operator shall be solely liable for the payment of all wages, taxes,
and other costs related to the employment of persons to perform
Operator's obligations under the Agreement, including all federal,
state, and local income, social security, payroll, and employment
taxes, and statutorily mandated workers' compensation coverage. None
of the persons employed by Operator shall be considered employees of
Owner for any purpose; nor shall Operator represent to any person
that he or she is or shall become an employee or agent of Owner.
15.9 Good Faith and Fair Dealing: Reasonableness.
The Parties agree to act reasonably and in accordance with the principles
of good faith and fair dealing in the performance of the Agreement. Unless
expressly provided otherwise in this Agreement, (i) wherever the Agreement
requires the consent, approval, or similar action by a Party, such
consent, approval or similar action shall not be unreasonably withheld or
delayed, and (ii) wherever the Agreement gives a Party a right to
determine, require, specify or take similar action with respect to
matters, such determination, requirement, specification or similar action
shall be reasonable.
15.10 Severability.
Should any provision of the Agreement be or become void, illegal, or
unenforceable, the validity or enforceability of the other provisions of
the Agreement shall not be affected and shall continue in force. The
Parties will, however, use their best endeavors to agree on the
replacement of the void, illegal, or unenforceable provision(s) with
legally acceptable clauses which correspond as closely as possible to the
sense and purpose of the affected provision and the Agreement as a whole.
15.11 Confidentiality.
The Agreement and exhibits incorporated by reference, and all amendments
shall be considered proprietary and shall not be provided to a third party
without prior written approval of the other Party, unless a Party is
required to disclose such information by law or court order or when such
information is already in the public domain. In the event certain
information must be
54
<PAGE> 55
provided pursuant to a regulatory proceeding, the Parties shall take
reasonable steps to protect the confidentiality of proprietary
information.
15.12 Cooperation.
The Parties agree to reasonably cooperate with each other in the
implementation and performance of the Agreement. Such duty to cooperate
shall not require either Party to act in a manner inconsistent with its
rights under the Agreement.
15.13 Successors and Assigns.
This Agreement shall be binding upon the Parties, their successors and
permitted assignees.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed
as of the day and year first written above.
NORTHERN STATES POWER COMPANY,
a Minnesota corporation
By:
-------------------------------------
Its: President, NSP Electric
NRG ENERGY, INC., a Delaware corporation
By:
-------------------------------------
Its: Vice President Ops & Engr.
55
<PAGE> 1
Exhibit 10.36
AGREEMENT FOR THE SALE OF THERMAL ENERGY
AND WOOD BYPRODUCT
BETWEEN
NORTHERN STATES POWER COMPANY
AND
NORENCO CORPORATION
This Agreement, effective as of the first day of December, 1986, between
Northern States Power Company, a Minnesota corporation (hereinafter referred to
as "NSP") and NORENCO Corporation, a Minnesota corporation (hereinafter referred
to as "NORENCO"), a wholly owned subsidiary of NSP.
WITNESSETH
WHEREAS, NSP owns and operates the Allen S. King Electric Generating Plant
comprised of a high pressure boiler, which supplies steam to an extraction
condensing turbine-generator, and a low pressure heating boiler; and
WHEREAS, NSP desires to sell steam to NORENCO, and NORENCO desires to
purchase such steam from, NSP to resell to Andersen Corporation (hereinafter
"Andersen") and the State of Minnesota Correctional Facility, Stillwater
(hereinafter "State"); and
-1-
<PAGE> 2
WHEREAS, NORENCO desires to sell wood byproduct purchased from Andersen to
NSP to be used as fuel and NSP desires to purchase such wood byproduct from
NORENCO; and
WHEREAS, it is the intention of both NSP and NORENCO that NORENCO
reimburse NSP for all of NSP's incremental costs associated with the sale of
steam to NORENCO.
NOW THEREFORE, the parties hereby agree as follows:
1. Term-Effective Date
1.1 This Agreement shall become effective on December 1, 1986, and shall
continue through December 31, 2006.
2. Conditions of Service
2.1 NSP shall use its best efforts to produce and deliver to NORENCO and
NORENCO shall use its best efforts to purchase and accept from NSP all of
NORENCO's current Steam requirements at Andersen and the State.
2.2 Steam sales from NSP's King Plant to NORENCO may at NSP's option be
interrupted during electric system emergencies and times of peak electric loads.
2.3 NORENCO will reimburse NSP for the incremental cost associated with
replacement electric energy at all times steam is being purchased for resale.
2.4 NORENCO shall make in a manner acceptable to NSP, all modifications,
adjustments, and additions to NSP's existing boilers, pipes, valves, meters,
controls, buildings, yards,
-2-
<PAGE> 3
tracks and all other equipment and machinery (collectively called Generating
Equipment) at the King Plant necessary to produce steam of the quality specified
and in the quantity required by this Agreement (herein sometimes referred to as
Steam).
2.5 NORENCO shall obtain all necessary franchises, licenses, permits,
rights of way or easements and purchase, construct and install a transport
system which will connect King Plant to Andersen and the State. The transport
system (herein called the Supply System) shall include all pipes, pumps, valves,
meters, controls, wires, insulation and other equipment necessary to:
(a) transport Steam from the King Plant to Andersen and the State;
(b) transport condensate from Andersen and the State to the King
Plant;
(c) provide for control of Steam and communications between the King
Plant and Andersen and the State; and
(d) transport wood byproduct from Andersen to the King Plant.
2.6 Throughout the Term of this Agreement NORENCO shall obtain, renew, and
maintain all licenses, permits and other governmental authorizations necessary
to furnish Steam, condensate and wood byproduct through the Supply System. NSP
shall use its best efforts to change or challenge rules, regulations, laws
-3-
<PAGE> 4
or ordinances which would prevent NSP from furnishing Steam hereunder or using
wood byproduct as a fuel.
2.7 Throughout the Term of this Agreement NSP shall own, operate,
maintain, repair, and adjust the Generating Equipment. NSP will not purchase any
equipment not required for electric generation.
2.8 At NORENCO's expense, which shall be NSP's incremental cost, NSP
shall, throughout the Term of this Agreement, operate, maintain, repair and
adjust NORENCO-purchased equipment installed on NSP property.
2.9 NORENCO shall not, by reason of this Agreement, the termination of
this Agreement or the payments made pursuant to this Agreement, acquire title or
ownership in or to the Generating Equipment of the King Plant.
2. 10 All Steam produced and delivered from the King Plant shall meet the
following specifications when measured at the delivery point:
(a) Temperature: 0 to 10 degrees F above saturated steam conditions
with variations required for load control.
(b) Pressure: 150 to 250 pounds per square inch gauge (PSIG) with
variations required for load control.
(c) Steam flow rate: 0 to 160,000 pounds per hour.
2.11 Delivery point as used in Article 2 of this Agreement shall be the
point where the Steam exits the Steam conditioning valve and enters the Supply
Line at the King Plant.
-4-
<PAGE> 5
2.12 During each fiscal year of the Term of this Agreement, NORENCO shall
provide 100% of the water necessary to produce Steam for NORENCO at the King
Plant by delivering to NSP the condensate return water or pay NSP for the cost
of any makeup required. NORENCO shall return the condensate in a condition
acceptable for the King boilers.
3. Cost of Service
For any Steam delivered to NORENCO by NSP, the costs shall be recovered by
NSP from NORENCO as specified in this Section 3. The calculation of these costs
includes the use of coefficients which are to be updated at least annually by
NSP. The costs recovered by NSP are to be reviewed annually by NSP to ensure
that the provisions of this Agreement recover all appropriate costs. Corrections
to billings will be made if it can be demonstrated by either party to the other
party's satisfaction that the monthly payments made by NORENCO to NSP are in
error by at least plus or minus 1%. Any corrections to billings will be
consistent with the incremental cost approach.
3.1 Cost to Provide Steam From the King Turbine Cold Reheat Extraction
Line
The King Plant turbine-generator will be operated as required by NSP
for electric generation. When the turbine-generator is in operation, Steam will
be provided to NORENCO from the turbine cold reheat extraction line. NORENCO
will be charged for the cost of replacement energy generation (or loss of the
oppor-
-5-
<PAGE> 6
tunity to sell electricity for resale) due to NORENC0's Steam requirements as
follows:
(a) The cost of replacement energy is calculated as the difference
in the cost of NSP generation and purchases to supply NSP native requirements
with and without the supply of Steam to NORENCO. The change in NSP generation
cost will include such items as the changes in fuel and maintenance for startup
and hours of operation, and the incremental ash disposal cost. The change in
billing cost for purchases with and without the supply of Steam to NORENCO will
also be used in the calculation.
(b) NORENCO will be charged monthly for incremental costs associated
with the loss of the opportunity to sell electricity for resale due to NORENCO's
Steam requirements. This incremental cost is calculated as the estimated lost
revenues from sales for resale from the King Plant minus the estimated avoided
electrical production costs, had this energy been generated at the King Plant.
(c) The cost of replacement energy shall be calculated using the NSP
System Operations computer program and the following coefficients or
information:
(1) Total Steam Flow in MMBTU's to NORENCO
(2) Electric power MW hours lost per MMBTU delivered to
NORENCO
(3) Cost of replacement energy per MW Hour
-6-
<PAGE> 7
3.2 Cost to Provide Steam from the King Heating Boiler
The King Plant heating boiler may be used to provide Steam to
Andersen and the State when the King Plant turbine generator is not in
operation. NORENCO will be charged for operation of the heating boiler
(including standby operation) as provided in 3.2.1 - 3.2.3.
3.2.1 Fuel Cost
(a) NORENCO will be charged for any incremental fuel used due to
heating boiler operations for NORENCO. For oil usage the cost will be calculated
as follows:
Cost = Gallons of oil used for x Oil cost per
NORENCO gallon
(b) For gas usage, the cost will be calculated as follows:
Cost = Millions of BTU of gas x Gas cost per
used for NORENCO million BTU
(c) The King Plant will report monthly the gallons of oil and the
millions of BTU's of gas used for the heating boiler. If the heating boiler
is used to supply steam to both NSP and NORENCO, the costs will be prorated
based on NORENCO Steam Flow and NSP steam flow.
3.2.2 Incremental Maintenance Cost
Each month, NORENCO shall pay NSP for the cost of
-7-
<PAGE> 8
incremental maintenance of the King Plant heating boiler as calculated using NSP
Power Production's incremental maintenance coefficient.
3.2.3 Incremental Auxiliary Cost
Each month, NORENCO shall pay NSP for the cost of incremental
auxiliary electrical power usage for the King Plant heating boiler as calculated
using the average incremental system generation cost for that month.
3.3 Incremental Operating Cost
Any other incremental operating costs including overtime or
operating personnel required by NSP to provide Steam to NORENCO shall be
reported and charged to NORENCO.
3.4 Thermal Equipment Operation and Maintenance
Any operation or maintenance of thermal only equipment (equipment
installed for thermal use only) will be charged on separate work orders to
NORENCO.
3.5 Supply of Gas or Oil
If NSP supplies any oil or natural gas to NORENCO, NORENCO shall
reimburse NSP for the replacement cost of that oil or natural gas including
appropriate carrying and handling charges.
3.6 Administrative and General Costs
Administrative and general costs are covered by the Administrative
Services Agreement dated January 1, 1983, and any amendments thereto, between
NSP and NORENCO.
3.7 NSP Surcharge
-8-
<PAGE> 9
A 5% surcharge will be added to items 3.2.2 through 3.4.
4. Sale of wood Byproduct to NSP
4.1 NORENCO is responsible for transporting and for all costs related to
transporting the wood byproduct from Andersen to the King Plant site or to other
mutually agreed to NSP sites if King Plant is out of service.
4.2 NSP agrees to use reasonable efforts to burn wood byproduct from
NORENCO up to thirteen (13) tons per hour and up to 80,000 tons per year of wood
byproduct when the King Plant is operating or to utilize it at other NSP
generating plants capable of handling and burning such wood byproduct when the
King Plant is out of service. NORENCO will annually provide NSP with a
forecasted wood byproduct delivery schedule. NORENCO agrees to supply all such
wood byproduct received from Andersen to NSP at the locations specified in 4.1
above unless NSP in its sole discretion is unable to utilize such wood
byproduct.
4.3 Whenever NSP receives wood byproduct from NORENCO, NSP shall pay for
all such wood byproduct at the following rate:
(a) For wood byproduct burned at the King Plant NSP shall pay
NORENCO at the average cost per MMBTU for solid fuel delivered to the King Plant
during the calendar year on a BTU equivalent basis.
(b) For wood byproduct delivered to other NSP generating plants, NSP
shall pay NORENCO the average cost per
-9-
<PAGE> 10
MMBTU of solid fuel (on an equivalent BTU basis) during the calendar year at
such other NSP plants. The cost per MMBTU in (a) and (b) above shall be
estimated at the beginning of each calendar year for billing purposes and the
billings adjusted after the close of the year to reflect the year's actual
average cost.
5. Billing
5.1 NSP will bill NORENCO, and NORENCO will bill NSP, by the 20th of the
month following the month in which the costs were incurred. The amount of each
month's bill shall be increased by 1% to cover working capital and miscellaneous
costs.
5.2 NORENCO will pay NSP, and NSP will pay NORENCO, no later than ten
(10) days following the date of NSP's bill and the date of NORENCO's bill,
respectively. Interest shall accrue on payments which are overdue at the daily
commercial prime rate in effect at the Norwest Bank Minneapolis.
5.3 NSP will provide NORENCO with a cost component schedule along with its
bill similar to that shown in Table 1. NORENCO will provide NSP with a cost
component schedule along with its bill similar to that shown in Table II.
5.4 The total monthly cost billed shall be calculated pursuant to Articles
3 and 4 of this Agreement.
6. Liability
6.1 NORENCO shall hold harmless and indemnify NSP from
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<PAGE> 11
any and all claims, loss, damage or liability, including injury to and death of
persons, caused directly or indirectly by the Steam or the use of NORENCO's
facilities after the delivery of Steam to NORENCO, other than those resulting
solely from the negligence of NSP or its agents or employees (excluding persons
assigned to NORENCO on a full-time basis). NSP likewise shall hold harmless and
indemnify NORENCO from any and claims, loss, damage or liability, including
injury to and death of persons, caused directly or indirectly by steam or the
use of NSP's facilities before the delivery of steam to NORENCO, other than
those resulting solely from the negligence of NORENCO or its agents or employees
(including those persons assigned to NORENCO on a full-time basis).
6.2 Notwithstanding any other provision of this Agreement, neither NSP nor
NORENCO in any event shall be liable to the other, whether arising under
contract, tort (including negligence), or otherwise, for claims of customers or
any other third parties, or for loss of use of capital or revenue, or for loss
of anticipated profits, or for any other special, indirect, incidental or
consequential loss or damage of any nature arising at any time or from any cause
whatsoever.
6.3 No provision of this Agreement shall in any way inure to the benefit
of any third person (including the public at large) so as to constitute any such
person a third party beneficiary of this Agreement or of any one or more of the
terms
-11-
<PAGE> 12
hereof, or otherwise give rise to any cause of action in any person not a party
hereto.
6.4 The provisions of this section and of any other sections of this
Agreement providing for limitation, of or protection against liability shall
apply to the full extent permitted by law and regardless of fault and shall
survive the expiration or termination of this Agreement.
7. Continuity of Service
7.1 NSP shall not be liable to NORENCO for its failure to deliver Steam,
and NORENCO shall not be liable to NSP for its failure to receive Steam, when
such failure on the part of either party shall be due to accident to or breakage
of pipelines or equipment, fires, floods, storms, weather conditions, strikes,
lockouts or other industrial disturbances, riots, legal interference, acts of
God or public enemy, shutdowns for necessary repairs and maintenance, or,
without limitation by enumeration, any other cause beyond the reasonable control
of the party failing to deliver or receive Steam provided such party shall
promptly and diligently take such action as may be necessary and practicable
under the then existing circumstances to remove the cause of failure and resume
the delivery or receipt of Steam.
Furthermore, NSP shall not be liable for its failure to deliver
Steam provided that such failure is (i) due to any scheduled or unscheduled
maintenance shutdown of King Plant
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<PAGE> 13
boilers or (ii) due to operating conditions on King Plant boilers and turbine
that warrant curtailment of the delivery of Steam to NORENCO. NSP shall have the
sole right to determine when those conditions exist. NSP and NORENCO shall
cooperate with each other regarding maintenance and Steam service curtailment,
and shall use their best efforts to coordinate inspections, maintenance and
repairs to their respective facilities. NSP shall provide NORENCO with
reasonable advance notice as possible of scheduled interruption or curtailment
of Steam service.
8. Miscellaneous
8.1 This Agreement shall bind and inure to the benefit of the respective
successors and assigns of the parties hereto, and any reference to any of the
parties hereto shall be deemed to include all successors and assigns.
Notwithstanding the foregoing, no assignment shall relieve a party of its duties
and obligations to the other party under this Agreement if the assignee defaults
in such duty or obligation, unless such other party consents to the novation in
writing.
8.2 Unless designated otherwise in writing, all notices from NORENCO to
NSP shall be delivered to:
D. E. Gilberts
Senior Vice President-Power Supply
Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
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<PAGE> 14
Unless designated otherwise in writing, all notices from NSP to NORENCO
shall be delivered to:
H. S. Wick
Vice President
NORENCO Corporation
414 Nicollet Mall
P.O. Box 1396
Minneapolis, MN 55440
8.3 All payments and reimbursements required to be made by NORENCO to NSP
pursuant to this Agreement shall be directed to:
Manager, General Accounting
Northern States Power Company
414 Nicollet Mall
Minneapolis, MN 55401
8.4 All payments and reimbursements required to be made by NSP to NORENCO
pursuant to this Agreement shall be directed to:
Manager, Business Operations
NORENCO Corporation
P.O. Box 1396
Minneapolis, MN 55440
8.5 The costs and charges provided for herein are exclusive of any
present or future federal, state, municipal or other sales or use tax with
respect to the personnel or products covered hereby, or any other present or
future excise tax upon or measured by the gross receipts from this transaction
or any allocated portion thereof or by the gross value of the personnel or
products covered hereby. If NSP is required by applicable law or regulations to
pay or collect any such tax or taxes on account of this transaction or the
personnel or products covered hereby, then such amount shall be paid by NORENCO
in addition to the costs or charges provided for herein.
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<PAGE> 15
8.6 This Agreement shall be construed in accordance with and be governed
by the laws of the State of Minnesota.
IN WITNESSETH WHEREOF, the parties hereto have caused this instrument to
be executed by their respective officers thereunto duly authorized as of the day
and year below written.
NORENCO CORPORATION NORTHERN STATES POWER COMPANY
By______________________________ By__________________________________
Its_____________________________ Its_________________________________
Date____________________________ Date________________________________
00476
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<PAGE> 16
TABLE I
NSP CHARGES TO NORENCO
3.1(a) Cost for Replacement Generation $
-------------
(b) Lost Opportunity Cost $
-------------
3.2.1 Heating Boiler Fuel Cost Gas $
-------------
Oil $
-------------
3.2.2 Incremental Maintenance Cost $
-------------
3.2.3 Incremental Auxiliary Cost $
-------------
3.3 Incremental Operating Cost $
-------------
3.4 Thermal Equipment Operation and
Maintenance $
-------------
3.5 Supply of Gas and Oil $
-------------
3.6 Administrative and General Costs $
-------------
3.7 NSP Surcharge $
-------------
00476.4
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<PAGE> 17
TABLE II
NORENCO WOOD BYPRODUCT SALE TO NSP
Tons of wood byproduct delivered to NSP _______________ Tons
BTU's per pound _______________ BTU/lb.
* NSP Equivalent cost for coal
delivered to King Plant during
the year $ _______________ /MMBTU
* An estimated cost will be used during the year and retroactively adjusted as
necessary at the end of the year.
00476.5
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<PAGE> 1
EXHIBIT 10.37
[NSP LOGO] NORTHERN STATES POWER COMPANY
414 NICOLLET MALL ROGER D. SANDEEN
MINNEAPOLIS, MINNESOTA 55401-1993 VICE PRESIDENT
TELEPHONE (612) 330-5907 AND CONTROLLER
April 4, 1991
Mr. Roland J. Jensen, President
NRG Group, Inc
1221 Nicollet Avenue
Minneapolis, MN 55403
Subject: Federal and State Income Tax Sharing Agreement Between Northern
States Power Company (NSP) and NRG Group, Inc.
Dear Mr. Jensen,
To formalize the system of determining the income tax liability attributable to
each corporation that joins in filing consolidated Federal and State income tax
returns with NSP the following agreement is proposed.
The subsidiaries that comprise NRG Group, Inc shall pay to NSP the amount of
Federal and State income tax computed as if the NRG Group had actually filed
separate Federal and separate State tax returns. Payments shall be made on or
about the time that estimate payments or income tax returns are due. If the NRG
Group incurs tax losses, NSP shall reimburse NRG to the extent there is a tax
benefit from the consolidated returns.
NRG Group shall join in an election to this effect in the 1991 tax returns.
Sincerely,
/s/ Roger D. Sandeen
Roger D. Sandeen
/s/ Roland J Jensen
- -------------------------
Approved
Roland J Jensen
<PAGE> 1
EXHIBIT 10.38
EXECUTION COPY
SUPPORT AGREEMENT
THIS SUPPORT AGREEMENT (this "AGREEMENT"), dated as of March 27, 2000, is
made by NORTHERN STATES POWER COMPANY, a Minnesota corporation ("PARENT"), in
favor of Citicorp USA, Inc., as agent for the lenders party to the Credit
Agreement referred to below (the "AGENT").
WHEREAS, Parent is the owner of 100% of the outstanding common stock of
NRG Energy, Inc., a Delaware corporation (the "Subsidiary");
WHEREAS, Subsidiary intends from time to time to make borrowings from the
lenders party to the $300,000,000 Credit Agreement, dated as of the date hereof
(such agreement as it may be amended and in effect from time to time, the
"CREDIT AGREEMENT"), among Subsidiary, the lenders party thereto and Citicorp
USA, Inc., as Administrative Agent (such lenders and the Administrative Agent
being hereinafter collectively referred to as the "LENDERS"), and to issue debt
securities to the Lenders pursuant to the Credit Agreement (such borrowings and
debt securities, including without limitation all interest, fees, expenses and
other amounts payable in accordance with the documentation relating to such
borrowings and debt securities being hereinafter collectively referred to as the
"DEBT");
WHEREAS, Parent desires to take certain actions to enhance and maintain the
financial condition of Subsidiary as hereinafter set forth in order to enable
Subsidiary and its subsidiaries to incur indebtedness on more advantageous and
reasonable terms; and
WHEREAS, the Lenders will rely upon this Agreement in making loans or
extending credit to Subsidiary under the Credit Agreement;
NOW, THEREFORE, in consideration of the premises, and other good and
valuable consideration, the receipt and sufficiency of which is hereby
acknowledged, and in order to induce the Lenders to enter into, and extend
credit to Subsidiary under, the Credit Agreement:
SECTION 1. STOCK OWNERSHIP. During the term of this Agreement, Parent will
own all of the voting common stock now or hereafter issued and outstanding of
Subsidiary and all other subsidiaries of Parent.
SECTION 2. SUFFICIENT FUNDS. Parent intends to manage the affairs of
Subsidiary consistent with Subsidiary's having sufficient funds to make payments
in respect of the Debt in accordance with the terms of the Credit Agreement.
Parent hereby agrees that, if and to the extent that it provides funds to
Subsidiary in furtherance of its intention described above, Parent will provide
those funds to Subsidiary in the form of equity and not in the form of debt.
SECTION 3. WAIVERS. Parent hereby waives any failure or delay on the part
of any Lender in asserting or enforcing any of its rights or in making any
claims or demands hereunder
<PAGE> 2
and agrees that Subsidiary need not assert or enforce any such rights or make
any such claims or demands hereunder. Subsidiary or any Lender may at any time,
without Parent's consent, without notice to Parent and without affecting or
impairing any Lender's rights or Parent's obligations hereunder, do any of the
following with respect to the Debt: (a) make changes modifications, amendments
or alterations, by operation of law or otherwise, including, without limitation,
any increase in the principal amount of such Debt or the rate of interest
payable thereon or any changes in the method of calculating the rate of interest
payable thereon, (b) grant renewals and extensions and extensions of time, for
payment or otherwise, (c) accept new or additional documents, instruments or
agreements relating to or in substitution of said Debt, or (d) otherwise handle
the enforcement of their respective rights and remedies in accordance with their
business judgment.
SECTION 4. AMENDMENT. This Agreement may be amended or terminated at any
time by written amendment or agreement signed by Parent and the Agent.
SECTION 5. RIGHTS OF LENDERS. Sections 1, 2 and 3 of this Agreement inure
to the benefit of the Lenders. In the event that Parent fails to comply with any
of its obligations hereunder, any Lender may enforce its rights under Sections
1, 2 and 3 hereof directly against Parent.
SECTION 6 NOTICES. Any notice, instruction, request, consent, demand or
other communication required or contemplated by this Agreement shall be in
writing, shall be given or made by United States first class mail, facsimile
transmission or hand delivery, addressed as follows:
If to Parent: Northern States Power Company
414 Nicolett Mall
5th Floor
Minneapolis, Minnesota 55401
Attention: Treasurer
Facsimile: (612) 330-6926
Telephone: (612) 330-7769
If to the Agent: Citicorp USA, Inc.
399 Park Avenue, 4th Floor Zone 20
New York, New York 10043
Attention: J. Nicholas McKee
Facsimile: 212-793-6130
Telephone: 212-559-1503
SECTION 7. SUCCESSORS. This Agreement shall be binding upon Parent and its
successors and assigns and is also intended for the benefit of Lenders, and,
each Lender shall be entitled to the full benefits of this Agreement and to
enforce the covenants and agreements contained herein as set forth in Section 5.
This Agreement is not intended for the benefit of any person other than Lenders
and shall not confer or be deemed to confer upon any such person any benefits,
rights or remedies hereunder.
<PAGE> 3
SECTION 8. GOVERNING LAW. This Agreement shall be governed by the laws of
the State of New York.
SECTION 9. COUNTERPARTS. This Agreement may be executed by the
parties in one or more separate counterparts, each of when executed shall be
deemed an original and all of which, when taken together, shall constitute one
and the same agreement.
<PAGE> 4
IN WITNESS WHEREOF, Parent has caused this Agreement to be executed by its
officer thereunto duly authorized, as of the date first above written.
NORTHERN STATES POWER
COMPANY
By Paul Pender
----------------------------
Name: Paul Pender
Title: Vice President-Finance &
Treasurer
Accepted and agreed to as of the date
first above written:
CITICORP USA, INC., as Agent
By
----------------------------
Name:
Title
<PAGE> 5
IN WITNESS WHEREOF, Parent has caused this Agreement to be executed by its
officer thereunto duly authorized, as of the date first above written.
NORTHERN STATES POWER
COMPANY
By
---------------------------
Name:
Title:
Accepted and agreed to as of the date
first above written:
CITICO USA, INC., as Agent
By SANDIP SEN
---------------------------
Name: SANDIP SEN
Title: Managing Director
<PAGE> 6
REFUSE DERIVED FUEL SUPPLY AGREEMENT
BETWEEN
NORTHERN STATES POWER COMPANY
AND
NRG RESOURCE RECOVERY, INC.
This Agreement shall, upon execution, govern the operational and financial
relationship between Northern States Power Company (hereinafter referred to as
"NSP") and NRG Resource Recovery, Inc. (hereinafter referred to as "NRG-RR"),
Whereas, NSP requires fuel for steam electric power plants operated at Mankato,
Minnesota and Red Wing, Minnesota known as the Wilmarth and Red Wing Steam
Plants, respectively (hereinafter referred to as the "Steam Plants"); and
Whereas, the Steam Plants consume volumes of refuse derived fuel (hereinafter
referred to as "RDF") as fuel for the generation of electrical energy in the
Steam Plants; and
Whereas, NRG-RR manages and operates Resource Recovery Facilities at Newport,
Minnesota and Elk River, Minnesota (hereinafter referred to as "Facilities") for
NSP; and
Whereas, the parties desire to increase landfill abatement through increased
production and combustion of RDF in a manner that is conomic, to NSP's
ratepayers.
Whereas, the Facilities produce RDF and deliver it to the Steam Plants;
Now, therefore NRG-RR and NSP mutually agree as follows:
1.0 TERM
1.1 This Agreement shall be in effect from January 1, 1992 through
December 31, 2001. The term of this Agreement shall thereafter
automatically renew and continue in full force and effect for
successive periods of five full years each unless either party
terminates this Agreement by delivering to the other party not
less than six months prior to the end of any five year term,
written notice of termination.
1.2 In the event the waste processing Service Agreement among NSP
and Ramsey and Washington Counties dated November 6, 1986, and
any subsequent amendments is terminated, NRG-RR shall
immediately notify NSP in writing and this Agreement shall
become null and void.
1
<PAGE> 7
2.0 SOURCE OF RDF
The primary sources of RDF to be transferred under this Agreement are the
Facilities. The Facilities process municipal solid waste under contract
with various counties in the Twin Cities Metropolitan Area.
3.0. QUANTITY OF RDF
3.1 NRG-RR agrees to process and deliver to the Steam Plants, and NSP
agrees to accept and to pay for quantities of RDF within the following
limits:
<TABLE>
<CAPTION>
TABLE I
RDF DELIVERY SCHEDULE
<S> <C>
MINIMUM EXPECTED
ANNUAL TONNAGE WEEKLY TONNAGE
-------------- --------------
340,000 6900 (+-) 500
</TABLE>
3.2 NRG-RR shall annually provide NSP with a written forecast of monthly
deliveries from the Facilities to NSP. This forecast shall be provided to
the NSP Fuel Resources Department and to the Steam Plants for inclusion in
the annual NSP Production Budget but in no event will the schedule be
delivered later than July 31 for deliveries to be made during the
following year. (The forecast of deliveries for calendar year 1992 is
included in Appendix A). The forecast shall reflect expected monthly waste
deliveries and processing at the Facilities as well as expected outages
scheduled at the steam Plants and the Facilities.
3.3 It is the expectation of the parties to increase RDF production and burning
to 350,000 tons by 1993, 360,000 tons by 1994, and 370,000 tons by 1995.
3.4 In the event that NSP can consume quantities of fuel at the Steam Plants in
excess of the Minimum Annual Tonnage of RDF identified in paragraph 3.1 in
this Agreement, NSP shall notify NRG-RR that it is soliciting bids to
supply such additional quantities. If NSP has identified other sources of
fuel acceptable to support the Steam Plants' operations, NSP shall allow
NRG-RR to offer additional quantities of RDF to satisfy the additional fuel
consumption. NRG-RR must provide such offer no later than five (5) working
days after NSP has notified NRG-RR of such opportunity to offer additional
quantities of RDF.
2
<PAGE> 8
In the event that NRG-RR offers terms for the supply of additional RDF
that NSP determines to meet or are better than offers from sources,
then NSP and NRG-RR will execute an agreement to provide additional
RDF that is acceptable to both parties.
4.0 QUALITY OF RDF
4 1.
<TABLE>
<CAPTION>
TABLE 2
RDF QUALITY CRITERIA
(PROXIMATE ANALYSIS)
EXPECTED
AVERAGE MAXIMUM MINIMUM
------- ------- -------
<S> <C> <C> <C>
BTU/lb 5,000-5,500 N/A 5,000
Ferrous Metals --- 1.00% ---
Glass --- 3.50% ---
Moisture --- 40.00% ---
Non-Ferrous Metal --- .75% ---
Rigid Particle Size --- 12"x12" ---
Ash (dry) --- 15% ---
</TABLE>
95% of all RDF delivered to the Steam Plants shall be less than 6
inches in any dimension. The Facilities shall attempt to the best of
their abilities to avoid delivery of material that includes
excessively long and fibrous material such as cords, hosiery,
belting, rope, etc. In the event that such long fibrous material may
be delivered, the Steam Plants shall accept and process such
materials if NSP determines that it is feasible to do so. If NSP
determines that it is not feasible to process such materials, NSP
shall reject and return the materials pursuant to paragraph 4.3
below. In the event that such material causes a Steam Plant to
curtail operations to clean and/or repair equipment such an event
will at the discretion of the Steam Plant be considered to be an
unexpected interruption.
4.2 It is anticipated that RDF shall have the maximum and minimum
characteristics shown above. In the event any one of the maximums or
minimums listed above is exceeded for a period of one week, NRG-RR
and NSP shall use reasonable efforts to resolve the problems causing
the RDF material to exceed the limitations stated above. If such
problems are not resolved within 30 days after the one week period,
NSP shall, in its sole discretion, have the option to suspend
performance under this Agreement. If NRG-RR cannot resolve the
problems or provide a substitute supply of RDF and give reasonable
assurance of performance within 30 days from the date of suspension,
NSP shall
3
<PAGE> 9
have the option to terminate this Agreement effective immediately by giving
written notice thereof to NRG-RR.
4.3. The Steam Plants shall have up to twelve (12) hours after arrival of a
truckload of RDF at the Steam Plants to reject the truckload based on RDF
quality criteria described in paragraph 4.1. Return of any rejected
truckloads shall be at NRG-RR's expense. NSP shall not have any
responsibility for its disposition or the cost of such disposition. The
Steam Plant shall not landfill RDF.
4.4. The Newport Facility will provide the Red Wing plant with two open top
trailers for collecting and hauling ferrous removed from RDF shipped to the
plant. The Newport Facility will be responsible for maintenance of the
ferrous trailers, transportation and disposal costs of the ferrous
providing that the trailers are used to dispose of ferrous only. Recovered
ferrous tons thus transported and disposed of will be subtracted from the
burn incentive tons delivered each month.
5.0. DELIVERY OF RDF
5.1. RDF is expected to be shipped to the Steam Plants by means of transfer
trailers. NRG-RR will pay for equipment and charges associated with
delivering RDF to the Steam Plants with the exceptions listed in (8.0.).
5.2. NRG-RR will also be responsible for the following fuel handling activities
at the Steam Plants:
a. Contact control room to enter gate and determine
where to stage trailer.
b. Stage trailers inside receiving building.
c. Crank down landing gear.
d. Hook-up hydraulic hoses.
e. Open trailer door.
f. Unhook tractor from full trailer.
g. Hook-up to empty trailer.
h. Clean off rear of trailers, doors, bumpers.
i. Close door and secure.
j. Crank up landing gear.
k. Disconnect hydraulic hoses and store properly.
1. Return tractor to Facility.
m. Notify control room of any problems which might
occur.
4
<PAGE> 10
5.3. Deliveries are expected to occur seven (7) days per week. NRG-RR shall use
all reasonable efforts to produce and deliver RDF consistent with
the Steam Plant burn requirements. The Steam Plants will use all reasonable
efforts to receive and burn RDF consistent with NRG-RR's production
requirements. In order to facilitate the coordination of daily deliveries,
each Steam Plant will, by 1300 hours each day, notify each Facility as to
the operating status and the estimated RDF deliveries needed for the next
day and immediately notify the Facilities of any unscheduled outages.
5.4. The Steam Plants shall each use all reasonable efforts to receive and burn
700 tons of RDF per day at each Steam Plant.
5.5. It is anticipated that deliveries shall be curtailed during scheduled
maintenance outages at the Steam Plants. It is expected that scheduled
outages will occur in November, December, January, and February, and should
be coordinated with NRG-RR so that outages at UPA's Elk River Station and
Hennepin County's HERC Facility can also be accommodated. Such scheduled
maintenance outages last approximately three weeks per plant and occur once
per year. NSP, and NRG-RR, will exchange projected annual maintenance
outage schedules no later than August 31 of the year preceding the
scheduled maintenance outages. In order to confirm the actual outage
dates, NSP shall notify NRG-RR at least two (2) weeks before the beginning
of such scheduled outages. Unexpected interruptions in the operation of the
Steam Plants may also occur that could require the curtailment of
deliveries of RDF. Unexpected interruptions shall include but not be
limited to events described in paragraph 4.1 above. In such an event, the
Steam Plants shall notify the Facilities within one (1) hour after the
beginning of such an interruption so that deliveries can be reduced or
curtailed. The Steam Plants shall notify the Facilities as soon as possible
that plant operations have resumed so that RDF deliveries can resume.
5
<PAGE> 11
It is also anticipated that operations at the Facilities will be
interrupted from time to time for scheduled maintenance and repairs. NRG-RR
shall notify the Steam Plants at least two (2) weeks prior to the beginning
of such interruptions. Unexpected interruptions in the operation of the
Facilities may also occur. In such an event, the Facilities will notify the
Steam Plants within one (1) hour after the beginning of such an
interruption if the interruption is expected to affect scheduled RDF
deliveries. The Facilities shall attempt, to the best of their abilities to
continue deliveries of RDF which meet the specifications set forth in this
Agreement during such interruptions.
6.0. WEIGHING AND ANALYSIS
6.1. The driver of each vehicle transporting RDF to the Steam Plants shall
deliver a weight ticket to the Steam Plant for each load delivered. Each
weight ticket shall include, as a minimum, the following information for
each delivery:
a. Ticket number
b. Location of originating RDF Facility
c. Loading date and time
d. Vehicle identification number
e. Gross and tare weight of vehicle and net tons of RDF
6.2. All loads will be weighed on the Facilities' scales and recorded by
Facilities' personnel on weight tickets. Facilities' plant scales shall be
certified semi-annually at Facility's expense. NSP Fuel Resource personnel
will be notified in advance and shall have the right to observe any such
certifications. Copies of all scale certifications will be forwarded to the
Fuel Resources Department. The net weights from the Facilities' weight
tickets will be used to determine amounts due under this Agreement.
6.3. Sampling of RDF deliveries shall be conducted by the Facilities in
accordance with Appendix B. Costs associated with testing of samples shall
be the responsibility of NSP.
6
<PAGE> 12
7.0. PRICE
7.1. Fuel Price Up To 196,560 Tons Per Year
The Fuel Price for the first 196,560 tons of RDF delivered per year
shall be $8.025 per ton which shall be effective January 1, 1991. The
as received heating value shall be guaranteed to be 5,500 BTU per
pound. In the event that the actual as received heating value is
greater than 5,600 BTU per pound or less than 5,400 BTU per pound, a
Fuel Price adjustment will be calculated by NSP as shown in the
following example:
If the actual as received heating value (AHV) is less than 5,400 BTU
per pound, the Fuel Price adjustment (FPAH) will be:
FPAL = (5,500 - AHV) * (Fuel Price)* 196,560
-------------------------------------
5,500
The Fuel Price Adjustment (FPAL) will be paid to NSP.
If the actual as received heating value (AHV) is greater than
5,600 BTU per pound, the Fuel Price Adjustment (FPAH) will be:
FPAH = (AHV - 5,500) * (Fuel Price)* 196,560
-------------------------------------
5,500
The Fuel Price Adjustment (FPAH) will be paid to NRG-RR.
The Fuel Price adjustment will be calculated by NSP and verified by
NRG-RR no later than 30 days after delivery of the first 196,560 tons
per year and payment will be due no later than 15 days after
calculation of the Fuel Price Adjustment.
7.2. Fuel Price above 196,560 Tons Per Year
The Fuel Price for tons of RDF burned above 196,560 tons per calendar
year shall be $0.00 FOB destination.
7.3. Fuel Price Escalation
An adjusted Fuel Price to be paid for the first 196,560 tons to be
delivered during the calendar year shall be calculated in February of
each year. The Fuel Price shall be adjusted annually at the same rate
of change as the Unweighted Arithmetic Average of the annual "as
delivered" fuel costs ($/Million BTU basis) at NSP's portion of
Sherburne County, A S King and Riverside generating facilities. The
annual "as delivered" fuel costs at the three generating facilities
shall be calculated based on the monthly reports submitted to the
Federal Energy Regulatory Commission on Form 423. These monthly
reports will be weight averaged to determine the annual "as
7
<PAGE> 13
delivered" fuel cost for each generating facility. See Appendix C for
example calculation.
7 4. RDF Burn Incentive
As an incentive to the Steam Plants to maximize RDF consumption,
NRG-RR will pay NSP a Burn Incentive Rate for each ton of RDF burned
at the Steam Plants when the total RDF consumed at the Steam Plants
exceeds 168,480 tons. The Burn Incentive Rate shall be $14.35 per ton
of RDF burned above 168,480 tons per calendar year, as of January 1,
1992. The incentive payments will be paid to NSP on a monthly basis
for burning amounts above 168,480/12 = 14,040 tons with monthly
true-ups for months where less tons are burned.
7.5 RDF Burn Incentive Escalation
An Adjusted Burn Incentive per ton shall be calculated in January of
each year by NRG Resource Recovery. The Burn Incentive Rate shall be
adjusted annually at the same rate of change to the CPI(U), as
published in the Bureau of Labor Statistics CPI detailed Report. An
Adjusted Burn Incentive Rate (ABI) shall be calculated in January of
each year based upon the most recent CPI(U) in effect at that time,
the CPI(U) inaffect as of January 1, 1992 which shall be 137.9 and
$14.35 per ton base Burn Incentive Rate. The calculation shall be as
follows: ABI = (CPI(U)/137.9) ($14-35/ton).
7.6 Minimum Delivery Guarantee
NRG-RR guarantees to deliver a minimum of 340,000 tons of RDF to the
Steam Plants each calendar year. If NRG-RR delivers less than 340,000
tons per year, and the failure to deliver said tons is due to
either the low supply of MSW or the inability of NRG-RR to process and
transport the guaranteed tonnage, then NRG-RR shall pay the RDF Burn
Incentive to the Steam Plants as though 340,000 tons were delivered.
7.7 Minimum Burn Guarantee
NSP guarantees to burn a minimum of 340,000 tons of RDF produced by
NRG-RR per year. If NSP is unable to burn 340,000 tons due
to lack of Steam Plant availability, then NSP will pay to NRG-RR an
amount equal to 340,000 tons minus total tons burned times the then
current RDF Burn Incentive Rate or Adjusted Burn Incentive Rate per
ton.
8
<PAGE> 14
8.0 PRICE ADJUSTMENT
The following circumstances may result in additional charges and
such charges shall be the responsibility of the appropriate Steam
Plant.
8.1 When a plant requests RDF to be delivered and the trailers have been
dispatched from the Facility but the plant is unable to accept the RDF
for reasons other than those listed in Section 4.3 requiring the RDF
to be transferred to another plant or returned to the Facility.
8.2 When a plant, during the handling or unloading of a trailer, damages
the trailer during some action that is not the direct responsibility
of the Facility or the hauler.
8.3 When a plant, during operations or the cessation of any operation,
causes a tractor to be held either at the Steam Plant or the Facility
or there is a delay in the return of the tractor to the Facility that
results in additional waiting time charges as defined in NRG-RR's
agreement with its contract haulers.
8.4 When a plant causes a tractor to return to the Facility without a
trailer and there is an additional trip charge to retrieve the trailer
from the plant and return it to the Facility.
8.5 In the event that the Steam Plants consume less than 196,560 tons
during any calendar year due to NSP's inability to perform, NRG-RR and
NSP shall share equally in all additional costs and penalties
associated with transportation and landfilling RDF assessed
against and actually incurred by NRG-RR as described in the terms of
the Service Agreement between NRG-RR and Ramsey and Washington
Counties in effect on the date of the execution of this Agreement.
RDF landfilled under conditions of "Uncontrollable Circumstances" as
defined in the Service Agreement between NRG-RR and Ramsey and
Washington Counties in effect on the date of the execution of this
Agreement and referenced in Section 11.0 of this Agreement, shall be
excluded from any cost sharing referenced in this paragraph 8.5.
8.6 In the event that NRG-RR or its contractors damage Steam Plant
equipment or facilities, NRG-RR or its contractors shall be liable for
required repairs.
9
<PAGE> 15
9.0. BILLING AND PAYMENT
9.1 By the fourth working day of each month, the Fuel Resources Department
shall provide to NSP's Financial Accounting Department, documentation
of tons of RDF and corresponding Million BTU's (MBTU's) consumed at
each Steam Plant and the total dollars to be paid to NRG-RR. An
informational copy of this documentation shall be sent to each
Facility as well as to the NRG-RR Accountant.
9.2. By the fifth working day each month, each Facility shall provide to
the NRG Accountant documentation of tons of RDF delivered to the Steam
Plants from each Facility, tons of ferrous landfilled from the Red
Wing Plant and RDF Burn Incentive Tons to be paid to the Steam Plants.
An informational copy of this documentation shall be sent to each
Steam Plant, as well as to the Fuel Resources Department.
9.3. Payment for items listed above will take place by the 20th of the
month through the NSP-NRG-RR "Intercompany Bill" transaction.
10.0.AUDIT OF SELLERS BOOKS AND RECORDS
NRG-RR agrees that NSP, at any time during normal business hours, shall
have access to and the right to examine and audit any documents or records
necessary to verify the tonnage amounts pertinent to the transactions
outlined in this Agreement. NSP shall conduct no less than one audit per
calendar year to verify quantities of RDF actually produced at the
Facilities and delivered to the Steam Plants during the then current year
and for the entire preceding year. All expenses incurred by the examining
party shall remain a cost of such party.
11.0.UNCONTROLLABLE CIRCUMSTANCES
NRG-RR and NSP recognize that NSP's agreements with the Counties provide
that the Facilities non-performance or delayed performance may at the
discretion of the Counties be excused in the event of "Uncontrollable
Circumstances" as defined in these agreements. NRG-RR and NSP agree that
any occurrence giving rise to a claim of uncontrollable circumstances shall
be immediately communicated to all representatives of the Operating
Committee. The Operating Committee shall decide whether to claim the excuse
and any other action to be taken.
12.0.OPERATING COMMITTEE
12.l Any controversies or claims arising out of or relating to any terms
of this Agreement or the inability of either NSP or NRG-RR to
perform shall be resolved by an Operating Committee consisting of
three NRG-RR representatives,three NSP
10
<PAGE> 16
NSP representatives, and a seventh member mutually agreed to by both
parties. The seventh member may change from time to time at the
request of either party. The Operating Committee shall resolve all
claims within thirty (30) days.
12.2.The Operating Committee will conduct at least once a year a formal
review of the overall operations of the production and use of RDF
during the year. This formal review meeting should be conducted
during the fourth calendar quarter and should include a review of at
least the following items:
* Actual Facilities performance including production rates,
production yield, RDF quality, etc.
* Actual Steam Plant performance including fuel handling
activities, plant heat rates, residuals disposal, etc.
* Scheduled and unscheduled outage events.
* Review existing and potential RDF production capacities.
* Review existing and potential RDF utilization capacities.
* Facility and Steam Plant Availabilities.
13.0.NOTIFICATIONS
Any notice, demand, or other communication required or permitted to be
served or given in writing by one party upon or to the other party hereto,
shall be deemed to have been duly given or served if mailed to the
respective parties hereto at the address stated, or elsewhere, as each may
direct by prior written notice:
Northern States Power Company
414 Nicollet Mall - RN09
Minneapolis, Minnesota 55401
Attn: Manager, Fuel Resources
Ramsey/Washington Resource Recovery Facility
2901 Maxwell Avenue
Newport, Minnesota 55055
Attn: Plant Superintendent
Elk River Resource Recovery Facility
10700 - 165th Ave. N. W.
Elk River, Minnesota 55303
Attn: Plant Superintendent
NRG Resource Recovery, Inc.
1221 Nicollet Mall
Minneapolis, Minnesota 55401
Attn: Vice President Operations
11
<PAGE> 17
14.0. ASSIGNMENT
Neither party shall assign or transfer any interest in this Agreement
without the prior written consent of the other party. Such consent shall
not be unreasonably withheld.
15.0. GOVERNING LAW
This Agreement shall be interpreted and construed according to the laws of
the State of Minnesota.
16.0. REGULATORY REVIEW
16.1 NSP and NRG-RR agree that regulatory approval by the Minnesota Public
Utilities Commission (MPUC) of the transactions covered by this
Agreement or any amendment to this Agreement shall be a
condition precedent to the effectiveness of this Agreement. Such
approval shall be by written order. In accordance with the
regulatory authority of the MPUC under the Minnesota Public
Utilities Act, including, but not limited to, Minnesota Statues
Sections 216B.09, 216B.23 and 216B.48 such written order must
authorize recovery from ratepayers of the Minnesota jurisdiction
portion of the amounts paid to NRG-RR by NSP under the terms of
this Agreement or any amendment to this Agreement.
16.2 NSP shall promptly file with the MPUC an application under 216B.48 for
any authority necessary to consummate this Agreement. NSP and NRG-RR
shall cooperate and use their best efforts to secure approval from the
MPUC. If the MPUC shall not approve the foregoing application in total
and without modification or condition, NSP and NRG-RR may then
mutually agree to amend this Agreement, or if mutual agreement is not
reached, this Agreement shall become null and void 90 days after
receipt of the final order.
17.0. TERMINATION OF PRIOR AGREEMENTS
This Agreement when duly executed by both parties supersedes and replaces
in its entirety all previous agreements both formal and informal whether
written or oral between the two parties.
12
<PAGE> 18
In Witness Whereof, the parties have caused this Agreement to be executed by
their duly Authorized representatives as of the day and year written above.
<TABLE>
<CAPTION>
NRG RESOURCE RECOVERY, INC. NORTHERN STATES POWER COMPANY
<S> <C>
By: By:
---------------------------------- ---------------------------------
K. E. Gelle C. J. Blair
President Executive Vice President
NRG Resource Recovery, Inc. Power Supply
And:
---------------------------------
P. D. Jones
Vice President Operations
NRG Resource Recovery, Inc.
Approved as to Form: Approved as to Form:
- ------------------------------------- -----------------------------------
Vice President & General Counsel Attorney
</TABLE>
13
<PAGE> 1
EXHIBIT 10.39
ADMINISTRATIVE SERVICES AGREEMENT
THIS AGREEMENT, effective as of the 1st day of January, 1992, by and
between Northern States Power Company, a Minnesota corporation
(hereinafter called "NSP"), and NRG THERMAL CORPORATION, a Minnesota
corporation (hereinafter called "Thermal") supersedes and replaces the
Administrative Services Agreement dated January 1, 1985, between NSP and
NORENCO Corporation, Thermal's predecessor in interest, which had been
previously approved by the Minnesota Public Utilities Commission ("MPUC")
pursuant to its Order dated March 18, 1986 in Docket No. E-002/M-86-21.
WITNESSETH:
WHEREAS, Thermal is a wholly-owned subsidiary of NRG Group, Inc., a
wholly-owned subsidiary of NSP, and is authorized to engage in general
non-utility business activities including, but not limited to, the design,
construction, ownership and operation of steam transmission and supply
facilities; and
WHEREAS, Thermal needs from time to time to retain the services of
certain NSP employees; and
WHEREAS, NSP is ready and willing to provide and assign
<PAGE> 2
such employees to Thermal if and when NSP determines such employees are
available; and
WHEREAS, the parties desire to enter into an agreement to provide for
the rendering of and charging for certain services by each party to the other
party, which services are not provided for in any other agreement between the
parties; and
WHEREAS, it is the intent of the parties that each party recover from
the other party any administrative and general costs actually incurred by one
party on behalf of the other party.
NOW THEREFORE, the parties agree as follows:
ARTICLE I
PERSONNEL ASSIGNED
1.01 If available and upon request, NSP agrees to provide and
assign certain NSP employees to Thermal. Determination of availability of such
employees shall be at NSP's sole discretion. The NSP employees assigned to
Thermal are specified in attached Appendix A which is incorporated by reference.
Appendix A will be updated and amended from time to time by the mutual agreement
of the parties.
2
<PAGE> 3
ARTICLE II
SERVICES RENDERED
2.01 If available and upon request or ratification, each party
will, at its cost, render management, supervisory, construction, engineering,
accounting, legal, financial and other similar services to the other party.
ARTICLE III
CHARGES
3.01 The charges to be billed and paid under this Agreement shall
consist of actual costs for labor, transportation and employee expenses,
materials and supplies and other expenses. These expenses are defined in
attached Appendix B which is incorporated by reference. Thermal shall be charged
according to the procedures specified in this Article III and in the attached
Appendix C which is incorporated by reference.
When one party renders services for which the other party is
proportionately chargeable, the party receiving the services shall pay the
proportional actual costs of the services.
3
<PAGE> 4
Bills shall be rendered by the 20th of the month following the
month in which the costs were incurred. Each month's bill shall be increased by
1% to cover handling costs, working capital requirements and miscellaneous
costs. Bills shall be paid no later than 10 days following the date of the
rendered bill.
Interest shall accrue on payments which are overdue at the daily
commercial prime rate in effect at the Norwest Bank of Minnesota, N.A. from the
date that interest first accrues through the date of payment.
ARTICLE IV
REGULATION
4.01 This Agreement is subject to the review of any regulatory
body which has jurisdiction.
ARTICLE V
ASSIGNMENT
5.01 This Agreement shall not be assigned by either party
without first obtaining the written consent to the assignment from the other
party.
4
<PAGE> 5
ARTICLE VI
TERM
6.01 This Agreement shall continue in effect unless cancelled by
either party upon sixty (60) days prior written notice to the other party or by
mutual agreement of the parties.
ARTICLE VII
GOVERNING LAW
7.01 This Agreement shall be construed in accordance with and be
governed by the laws of the State of Minnesota.
5
<PAGE> 6
IN WITNESS WHEREOF, the parties have caused this Agreement to be executed in
their respective corporate names by their respective duty authorized officers on
the day and year below written.
NRG THERMAL CORPORATION NORTHERN STATES POWER COMPANY
By Ronald J. Will By James T. Daudiet
---------------------------- ------------------------------------
Ronald J. Will James T. Daudiet
Executive Vice President - Finance
Its President and CEO Its and Chief Financial Officer
--------------------------- -----------------------------------
Date February 24, 1992 Date February 24, 1992
-------------------------- ----------------------------------
6
<PAGE> 7
APPENDIX A
NSP PERSONNEL ASSIGNED
January 1, 1992
NRG THERMAL CORPORATION
None
7
<PAGE> 8
APPENDIX B
COMPONENTS OF ACTUAL COSTS
Labor
Charges for engineering services shall be for time charged at an agreed upon
billing rate by classification of employee. The billing rate shall include an
average salary, by employee classification, plus engineering and supervision
costs and indirect labor costs. The engineering services billing rates shall be
reviewed and adjusted annually and at other times as necessary.
Labor costs for all services, other than engineering services, shall be for
the time charged at actual salary and wage rates paid to employees plus indirect
labor costs.
Indirect labor costs shall consist of non-productive labor costs (e.g.,
vacation, sickness and holidays) and other employee benefit costs (e.g., major
medical, pension and life insurance).
Transportation and Employee Expenses
Transportation costs charged to either party shall be for actual miles or
hours used.
8
<PAGE> 9
Employee expenses shall consist of meals, lodging, transportation and other
miscellaneous costs incurred by and reimbursable to employees when rendering
services to the receiving party.
Materials and Supplies
The cost of materials and supplies charged to either party shall be actual
costs plus purchasing and warehousing expenses and shipping expense.
Other Expenses
Costs included in the "other expenses" category shall include communication
services, accounting, printing, postage, permits, and other miscellaneous costs
directly attributable to work performed for the other party. Other Expenses also
shall include miscellaneous proratable operating expenses, such as invoiced
services, computer services, engineering, construction, research, testing lab,
etc.
9
<PAGE> 10
APPENDIX C
ACCOUNTING AND CHARGING PROCEDURES
Expenses as set forth below may be charged directly or through special work
orders. Special work orders are issued to record costs for functions which are
not assignable solely to either party. These work order costs shall be prorated
on a proper ratio reflecting the benefit to the respective parties. Whenever a
new work order is initiated involving costs that are assignable to both parties,
it shall be approved by the appropriate officer or department head of each
party. Work orders and applicable prorates shall be reviewed and revised as
needed, and at least annually.
LABOR
Employees of one party may charge time to the other party on either a fixed
payroll distribution basis or on an exception basis. Employees of one party
charging time to the other party on a fixed payroll distribution basis should
not charge time on an exception basis to the other party unless the
service performed was not contemplated in determining the fixed payroll
distribution.
Employees of one party who engage in work solely or primarily for the
10
<PAGE> 11
benefit of the other party on a regular basis, may charge their time on a fixed
payroll distribution basis, based upon a time analysis. The hours charged shall
be subject to review whenever the employee's duties change, whenever the
function of the department changes, and on an annual basis.
The party receiving charges for time should be advised of the name of the
employee (or in the case of engineering services the classification of the
employee), the service he or she performs and the percent of time engaged in
work for the other party. These charges will be subject to review and
approval by the department head or an officer of the party receiving those
charges.
Exception time charges must be reviewed and approved by the department head
from which the service originates. Exception time charges received from one
party also will be subject to review and approval by the department head or an
officer of the receiving party.
Charges for time from employees on bi-weekly and weekly payrolls should be
handled in the same manner as described above.
Transportation and Employee Expenses
Transportation shall be recorded on transportation sheets for the actual
miles or hours used for the benefit of the receiving company. The miles or
11
<PAGE> 12
hours used shall be charged at prevailing rates.
Employee expenses shall be charged on the basis of expenses submitted for
reimbursement by employees and approved by the appropriate department head or
officer.
Materials and Supplies
Materials and supplies provided by one party for the benefit of the other
party shall be received by and charged upon the basis of requisition orders.
Other Expenses
Approved copies of invoices for materials or services or other appropriate
documentation shall provide the accounting basis for these charges.
12
<PAGE> 1
EXHIBIT 21.1
NRG SUBSIDIARY LIST APRIL 17, 2000
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
1. Arthur Kill Power LLC Delaware
2. Astoria Gas Turbine Power LLC Delaware
3. Bioconversion Partners, L.P. California
4. Brimsdown Power Limited England and
Wales
5. Cabrillo Power I LLC Delaware
6. Cabrillo Power II LLC Delaware
7. Cadillac Renewable Energy LLC Delaware
8. Camas Power Boiler Limited Partnership Oregon
9. Camas Power Boiler, Inc. Oregon
10. Carolina Energy, Limited Partnership Delaware
11. Carquinez Strait Preservation Trust, Inc. California
12. Cobee Energy Development LLC Delaware
13. Cobee Holdings Inc. Delaware
14. Cogeneration Corporation of America Delaware
15. Collinsville Operations Pty Ltd Australia
16. Collinsville Power Joint Venture (unincorporated) Australia
17. Compania Boliviana de Energia Electrica S.A. Canada (Nova
Scotia
18. Compania Electrica Central Bulo Bulo S.A. Bolivia
19. Coniti Holding B.V. Netherlands
20. Connecticut Jet Power LLC Delaware
21. Croatia Power Group Cayman Islands
22. Crockett Cogeneration, A California Limited Partnership California
23. Curtis/Palmer Hydroelectric Company New York
24. Cypress Energy Partners, Limited Partnership Delaware
25. Devon Power LLC Delaware
26. Dunkirk Power LLC Delaware
27. ECK Generating, s.r.o. Czech Republic
28. El Segundo Power, LLC Delaware
29. Elk River Resource Recovery, Inc. Minnesota
30. Energeticke Centrum Kladno, s.r.o. Czech Republic
31. Energy Developments Limited Australia
(Queensland)
32. Energy Investors Fund, L.P. Delaware
33. Energy National, Inc. Utah
34. Enfield Energy Centre Limited England and
Wales
</TABLE>
Page 1
<PAGE> 2
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
35. Enfield Holdings B.V. Netherlands
36. Enfield Operations (UK) Limited England and
Wales
37. Enfield Operations, L.L.C. Delaware
38. ENI Chester, Limited Partnership Oregon
39. ENI Crokett Limited Partnership Oregon
40. ENI Curtis Falls, Limited Partnership Oregon
41. Enifund, Inc. Utah
42. Enigen, Inc. Utah
43. ESOCO Crockett, Inc. Oregon
44. ESOCO Fayetteville, Inc. Oregon
45. ESOCO Molokai, Inc. Utah
46. ESOCO Orrington, Inc. Utah
47. ESOCO Soledad, Inc. Utah
48. ESOCO Wilson, Inc. Oregon
49. ESOCO, Inc. Utah
50. Four Hills, LLC Delaware
51. Gladstone Power Station Joint Venture (unincorporated) Australia
52. Graystone Corporation Minnesota
53. Gunwale B.V. Netherlands
54. Huntley Power LLC Delaware
55. Interenergy Limited Ireland
56. Inversiones Bulo Bulo S.A. Bolivia
57. Jackson Valley Energy Partners, L.P. California
58. Kanel Kangal Elektrik Limited Sirketi Turkey
59. Kiksis B.V. Netherlands
60. Killingholme Generation Limited United Kingdom
61. Killingholme Holdings Limited United Kingdom
62. Killingholme Power Limited United Kingdom
63. Kingston Cogeneration Limited Partnership Canada (Ontario)
64. Kissimee Power Partners, Limited Partnership Delaware
65. Kladno Power (No. 1) B.V. Netherlands
66. Kladno Power (No. 2) B.V. Netherlands
67. Kraftwerk Schkopau Betriebsgesellschaft mbH Germany
68. Kraftwerk Schkopau GbR Germany
69. KUSEL Kutahya Seyitomer Elektrik Limited Sirketi
70. Lakefield Junction LLC Delaware
71. Lakefield Junction LP Delaware
72. Lambique Beheer B.V. Netherlands
73. Landfill Power LLC Wyoming
</TABLE>
Page 2
<PAGE> 3
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
74. Langage Energy Park Limited United Kingdom
75. Le Paz Incorporated Minnesota
76. LFG Partners, L.L.C. Delaware
77. Long Beach Generation LLC Delaware
78. Long Island Cogeneration, L.P. New York
79. Louisiana Energy Services, L.P. Delaware
80. Louisiana Generating LLC Delaware
81. Loy Yang Power Management Pty Ltd Australia
(Victoria)
82. Loy Yang Powers Partners Australia
83. Loy Yang Power Projects Pty Ltd Australia
(Victoria)
84. Maine Energy Recovery Company Maine
85. Matra Powerplant Holding B.V. Netherlands
86. MIBRAG B.V. Netherlands
87. Mid-Continent Power Company, L.L.C. Delaware
88. Middletown Power LLC Delaware
89. Minnesota Methane Holdings LLC Delaware
90. Minnesota Methane II LLC Delaware
91. Minnesota Methane LLC Wyoming
92. Minnesota Waste Processing Company, L.L.C. Delaware
93. Mitteldeutsche Braunkohlengesellschaft mbH Germany
94. MM Albany Energy LLC Delaware
95. MM Biogas Power LLC Delaware
96. MM Burnsville Energy LLC Delaware
97. MM Corona Energy LLC Delaware
98. MM Cuyahoga Energy LLC Delaware
99. MM El Sobrante Energy LLC Delaware
100. MM Erie Power LLC Delaware
101. MM Ft. Smith Energy LLC Delaware
102. MM Hackensack Energy LLC Delaware
103. MM Hartford Energy LLC Delaware
104. MM Lopez Energy LLC Delaware
105. MM Lowell Energy LLC Delaware
106. MM Martinez Energy LLC Delaware
107. MM Nashville Energy LLC Delaware
108. MM Northern Tier Energy LLC Delaware
109. MM Phoenix Energy LLC Delaware
110. MM Prima Deshecha Energy LLC Delaware
111. MM Prince William Energy LLC Delaware
</TABLE>
Page 3
<PAGE> 4
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
112. MM Riverside LLC Delaware
113. MM San Diego LLC Delaware
114. MM SKB Energy LLC Delaware
115. MM Spokane Energy LLC Delaware
116. MM Tacoma LLC Delaware
117. MM Tajiguas Energy LLC Delaware
118. MM Tauton Energy LLC Delaware
119. MM Tonoka Farms Energy LLC Delaware
120. MM Tri-Cities Energy LLC Delaware
121. MM Tulare Energy LLC Delaware
122. MM West Covina LLC Delaware
123. MM Woodville Energy LLC Delaware
124. MM Yolo Power LLC Delaware
125. MMSB Transco Holdings LLC Delaware
126. Montville Power LLC Delaware
127. Mt. Poso Cogeneration Company, A California Limited California
Partnership
128. NEO Albany, L.L.C. Delaware
129. NEO Burnsville, LLC Delaware
130. NEO Corona LLC Delaware
131. NEO Corporation Minnesota
132. NEO Cuyahoga, LLC Delaware
133. NEO Edgeboro, LLC Delaware
134. NEO El Sobrante LLC Delaware
135. NEO Erie LLC Delaware
136. NEO Findlay, LLC Delaware
137. NEO Fitchburg LLC Delaware
138. NEO Ft. Smith LLC Delaware
139. NEO Hackensack, LLC Delaware
140. NEO Hartford, LLC Delaware
141. NEO Landfill Gas Holdings Inc. Delaware
142. NEO Landfill Gas Inc. Delaware
143. NEO Lopez Canyon LLC Delaware
144. NEO Lowell LLC Delaware
145. NEO Martinez LLC Delaware
146. NEO MESI LLC Delaware
147. NEO Nashville LLC Delaware
148. NEO Northern Tier LLC Delaware
149. NEO Phoenix LLC Delaware
150. NEO Prima Deshecha LLC Delaware
</TABLE>
Page 4
<PAGE> 5
PLACE OF
SUBSIDIARY NAME INCORPORATION
151. NEO Prince William, LLC Delaware
152. NEO Riverside LLC Delaware
153. NEO San Bernardino LLC Delaware
154. NEO San Diego LLC Delaware
155. NEO SKB LLC Delaware
156. NEO Spokane LLC Delaware
157. NEO Tacoma, L.L.C. Delaware
158. NEO Tajiguas LLC Delaware
159. NEO Taunton LLC Delaware
160. NEO Tomoka Farms LLC Delaware
161. NEO Tri-Cities LLC Delaware
162. NEO Tulare LLC Delaware
163. NEO West Covina LLC Delaware
164. NEO Woodville LLC Delaware
165. NEO Yolo LLC Delaware
166. North American Thermal Systems Limited Liability Ohio
Company
167. Northbrook Acquisition Corp. Delaware
168. Northbrook Carolina Hydro, L.L.C. Delaware
169. Northbrook Energy, L.L.C. Delaware
170. Northeast Generation Holding LLC Delaware
171. Norwalk Power LLC Delaware
172. NR(Gibraltar) Gibralter
173. NRG Affiliate Services Inc. Delaware
174. NRG Artesia Operations Inc. Delaware
175. NRG Arthur Kill Operations Inc. Delaware
176. NRG Asia-Pacific, Ltd. Delaware
177. NRG Astoria Gas Turbine Operations Inc. Delaware
178. NRG Cabrillo Power Operations Inc. Delaware
179. NRG Cadillac Inc. Delaware
180. NRG Cadillac Operations Inc. Delaware
181. NRG Caymans Company Cayman Islands
182. NRG Caymans-C Cayman Islands
183. NRG Caymans-P Cayman Islands
184. NRG Central U.S. LLC Delaware
185. NRG Collinsville Operating Services Pty Ltd Australia
186. NRG Connecticut Affiliate Services Inc. Delaware
187. NRG Connecticut Generating LLC Delaware
188. NRG del Coronado Inc. Delaware
189. NRG Development Company Inc. Delaware
Page 5
<PAGE> 6
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
190. NRG Devon Operations Inc. Delaware
191. NRG Dunkirk Operations Inc. Delaware
192. NRG Eastern LLC Delaware
193. NRG El Segundo Operations Inc. Delaware
194. NRG Energeticky Provoz, s.r.o. Czech Republic
195. NRG Energy Center Grand Forks LLC Delaware
196. NRG Energy Center Minneapolis LLC Delaware
197. NRG Energy Center Pittsburgh LLC Delaware
198. NRG Energy Center Rock Tenn LLC Delaware
199. NRG Energy Center San Diego LLC Delaware
200. NRG Energy Center San Francisco LLC Delaware
201. NRG Energy Center Washco LLC Delaware
202. NRG Energy CZ, s.r.o. Czech Republic
203. NRG Energy Development GmbH Germany
204. NRG Energy Jackson Valley I, Inc. California
205. NRG Energy Jackson Valley II, Inc. California
206. NRG Energy Ltd. England and
Wales
207. NRG Energy PL Sp. z.o.o. Warsaw, Poland
208. NRG Energy, Inc. Delaware
209. NRG Gladstone Operating Services Pty Ltd Australia
210. NRG Gladstone Superannuation Pty Ltd Australia
211. NRG Huntley Operations Inc. Delaware
212. NRG International Development Inc. Delaware
213. NRG International II Inc. Delaware
214. NRG International Services Company Delaware
215. NRG International, Inc. Delaware
216. NRG Lakefield Inc. Delaware
217. NRG Lakefield Junction LLC Delaware
218. NRG Latin America Inc. Delaware
219. NRG Long Beach Operations Inc. Delaware
220. NRG Louisiana LLC Delaware
221. NRG Mextrans Inc. Delaware
222. NRG Middletown Operations Inc. Delaware
223. NRG Montville Operations Inc. Delaware
224. NRG Morris Operations Inc. Delaware
225. NRG New Roads Generating LLC Delaware
226. NRG New Roads Holdings LLC Delaware
227. NRG Northeast Affiliate Services Inc. Delaware
228. NRG Northeast Generating LLC Delaware
</TABLE>
Page 6
<PAGE> 7
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
229. NRG Norwalk Harbor Operations Inc. Delaware
230. NRG Oklahoma Operations Inc. Delaware
231. NRG Operating Services, Inc. Delaware
232. NRG Oswego Harbor Power Operations Inc. Delaware
233. NRG PacGen Inc. Delaware
234. NRG Pittsburgh Thermal Inc. Delaware
235. NRG Power Marketing Inc. Delaware
236. NRG Rocky Road LLC Delaware
237. NRG San Diego Inc. Delaware
238. NRG San Francisco Thermal Inc. Delaware
239. NRG Services Corporation Delaware
240. NRG South Central Generating LLC Delaware
241. NRG Sunnyside Operations GP Inc. Delaware
242. NRG Sunnyside Operations LP Inc. Delaware
243. NRG Thermal Corporation Delaware
244. NRG Thermal Operating Services LLC Delaware
245. NRG Victoria I Pty Ltd Australia
246. NRG Victoria II Pty Ltd Australia
247. NRG Victoria III Pty Ltd Australia
248. NRG West Coast Inc. Delaware
249. NRG Western Affiliate Services Inc. Delaware
250. NRGenerating Energy Trading Ltd. United Kingdom
251. NRGenerating Holdings (No. 1) B.V. Netherlands
252. NRGenerating Holdings (No. 11) B.V. Netherlands
253. NRGenerating Holdings (No. 12) B.V. Netherlands
254. NRGenerating Holdings (No. 13) B.V. Netherlands
255. NRGenerating Holdings (No. 14) B.V. Netherlands
256. NRGenerating Holdings (No. 15) B.V. Netherlands
257. NRGenerating Holdings (No. 16) B.V. Netherlands
258. NRGenerating Holdings (No. 17) B.V. Netherlands
259. NRGenerating Holdings (No. 18) B.V. Netherlands
260. NRGenerating Holdings (No. 19) B.V. Netherlands
261. NRGenerating Holdings (No. 20) B.V. Netherlands
262. NRGenerating Holdings (No. 21) B.V. Netherlands
263. NRGenerating Holdings (No. 22) B.V. Netherlands
264. NRGenerating Holdings (No. 23) B.V. Netherlands
265. NRGenerating Holdings (No. 3) B.V. Netherlands
266. NRGenerating Holdings (No. 4) B.V. Netherlands
267. NRGenerating Holdings (No. 5) B.V. Netherlands
268. NRGenerating Holdings (No. 6) B.V. Netherlands
</TABLE>
Page 7
<PAGE> 8
PLACE OF
SUBSIDIARY NAME INCORPORATION
269. NRGenerating Holdings (No. 7) B.V. Netherlands
270. NRGenerating Holdings (No. 8) B.V. Netherlands
271. NRGenerating Holdings (No. 9) B.V. Netherlands
272. NRGenerating Holdings GmbH Switzerland
273. NRGenerating International B.V. Netherlands
274. NRGenerating Rupali B.V. Netherlands
275. NRGenerating, Ltd. United Kingdom
276. O Brien Biogas (Mazzaro), Inc. Delaware
277. O Brien Biogas IV LLC Delaware
278. O Brien California Cogen Limited California
279. O Brien Cogeneration, Inc. II Delaware
280. O Brien Standby Power Energy, Inc. Delaware
281. Okeechobee Power I, Inc. Delaware
282. Okeechobee Power II, Inc. Delaware
283. Okeechobee Power III, Inc. Delaware
284. ONSITE Energy, Inc. Oregon
285. ONSITE Funding Corporation Oregon
286. ONSITE Limited Partnership No. 1 Oregon
287. ONSITE Marianas Corporation Commonwealth
of the Northern
Marianas Islands
288. ONSITE Soledad, Inc. Oregon
289. ONSITE/US Power Limited Partnership No. 1 New Jersey
290. Orrington Waste, Ltd. Limited Partnership Oregon
291. Oswego Harbor Power LLC Delaware
292. P.T. Dayalistrik Pratama Indonesia
293. Pacific Crockett Energy, Inc. Utah
294. Pacific Crockett Holdings, Inc. Oregon
295. Pacific Generation Company Oregon
296. Pacific Generation Development Company Oregon
297. Pacific Generation Holdings Company Oregon
298. Pacific Generation Resources Company Oregon
299. Pacific Kingston Energy, Inc. Canada (Ontario)
300. Pacific Orrington Energy, Inc. Oregon
301. Pacific Recycling Energy, Inc. Oregon
302. Pacific-Mt. Poso Corporation Oregon
303 Penobscot Energy Recovery Company, Limited Maine
Partnership
304. Pittsburgh Thermal, Limited Partnership Delaware
305. Power Operations, Inc. Delaware
Page 8
<PAGE> 9
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
306. Project Finance Fund III, L.P. Delaware
307. Pyro-Pacific Operating Company California
308. Rocky Road LLC Delaware
309. RSD Power Partners, L.P. Delaware
310. Saale Energie GmbH Germany
311. Saale Energie Services GmbH Germany
312. Sachsen Holding B.V. Netherlands
313. San Bernardino Landfill Gas Limited Partnership, a California
California limited partnership
314. San Francisco Thermal, Limited Partnership Delaware
315. San Joaquin Valley Energy I, Inc. California
316. San Joaquin Valley Energy IV, Inc. California
317. San Joaquin Valley Energy Partners I, L.P. California
318. San Joaquin Valley Energy Partners IV, L.P. California
319. Scoria Incorporated Minnesota
320. Scudder Latin American Power I-C L.D.C. Cayman Islands,
British West
Indies
321. Scudder Latin American Power II-C L.D.C. Cayman Islands,
British West
Indies
322. Scudder Latin American Power II-Corporation A Cayman Islands,
British West
Indies
323. Scudder Latin American Power II-Corporation B Cayman Islands,
British West
Indies
324. Scudder Latin American Power II-P L.D.C. Cayman Islands,
British West
Indies
325. Scudder Latin American Power I-P L.D.C. Cayman Islands,
British West
Indies
326. Somerset Operations Inc. Delaware
327. Somerset Power LLC Delaware
328. South Central Generation Holding LLC Delaware
329. Sterling (Gibraltar) Gibraltar
330. Sterling Luxembourg (No. 1) s.a.r.l. Luxembourg
331. Sterling Luxembourg (No. 2) s.a.r.l. Luxembourg
332. Sterling Luxembourg (No. 3) s.a.r.l. Luxembourg
333. Sterling Luxembourg (No. 4) s.a.r.l. Luxembourg
</TABLE>
Page 9
<PAGE> 10
<TABLE>
<CAPTION>
PLACE OF
SUBSIDIARY NAME INCORPORATION
<S> <C> <C>
334. STS Hydropower Ltd. Michigan
335. STS Turbine & Development, L.L.C. Delaware
336. Suncook Energy LLC Delaware
337. Sunnyside Cogeneration Associates Utah
338. Sunnyside Operations Associates L.P. Delaware
339. Sunshine State Power (No. 2) B.V. Netherlands
340. Sunshine State Power B.V. Netherlands
341. Tacoma Energy Recovery Company Delaware
342. The PowerSmith Cogeneration Project, Limited Delaware
Partnership
343. Tosli (Gibraltar) B.V. Netherlands
344. Tosli Acquisition B.V. Netherlands
345. Tosli Investments N.V. Netherlands
346. Tosli Luxembourg (No. 1) s.a.r.l. Luxembourg
347. Tosli Luxembourg (No. 2) s.a.r.l. Luxembourg
348. Turners Falls Limited Partnership Massachusetts
349. Wainstones Power Limited England and
Wales
350. WCP (Generation) Holdings LLC Delaware
351. West Coast Power LLC Delaware
</TABLE>
Page 10
<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 relating to the consolidated financial
statements of NRG Energy, Inc., and our report dated March 7, 2000 relating to
the curve-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
April 18, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains financial information extracted from the December 31,
1999 Financial Statements included in the Company's Form 10-K and is qualified
in its entirety by reference to such Form 10-K.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 31,483
<SECURITIES> 0
<RECEIVABLES> 126,562
<ALLOWANCES> 186
<INVENTORY> 119,181
<CURRENT-ASSETS> 323,970
<PP&E> 2,076,172
<DEPRECIATION> 156,849
<TOTAL-ASSETS> 3,431,684
<CURRENT-LIABILITIES> 524,355
<BONDS> 1,941,398
0
0
<COMMON> 1
<OTHER-SE> 893,653
<TOTAL-LIABILITY-AND-EQUITY> 3,431,684
<SALES> 432,518
<TOTAL-REVENUES> 500,018
<CGS> 269,900
<TOTAL-COSTS> 390,498
<OTHER-EXPENSES> (78,406)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 93,376
<INCOME-PRETAX> 31,114
<INCOME-TAX> (26,081)
<INCOME-CONTINUING> 57,195
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 57,195
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
