e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
|
|
|
þ
|
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
|
|
|
For the Fiscal Year ended December 31, 2004. |
|
o
|
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
|
|
For the Transition period
from to . |
Commission file No. 001-15891
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
|
|
|
Delaware |
|
41-1724239 |
(State or other jurisdiction of
incorporation or organization) |
|
(I.R.S. Employer
Identification No.) |
|
211 Carnegie Center
Princeton, New Jersey |
|
08540 |
(Address of principal executive offices) |
|
(Zip Code) |
(609) 524-4500
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the
Act:
|
|
|
Title of Each Class |
|
Name of Exchange on Which Registered |
|
|
|
None
|
|
None |
Securities registered pursuant to Section 12(g) of the
Act:
Common Stock, par value $0.01 per share
Indicate by check mark whether the Registrant (1) has filed
all reports to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the Registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not
contained herein, and will not be contained, to the best of the
Registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this
Form 10-K. o
Indicate by check mark whether the registrant is an accelerated
filer as defined by Rule 12b-2 of the
Act. Yes þ No o
As of the last business day of the most recently completed
second fiscal quarter, the aggregate market value of the common
stock of the registrant held by non-affiliates was approximately
$1,943,806,466.
Indicate by check mark whether the registrant has filed all
documents and reports required to be filed by Section 12,
13 or 15(d) of the Securities Exchange Act of 1934 subsequent to
the distribution of securities under a plan confirmed by a
court. Yes þ No o
Indicate the number of shares outstanding of each of the
registrants classes of common stock as of the latest
practicable date.
|
|
|
Class |
|
Outstanding at March 28, 2005 |
|
|
|
Common Stock, par value $0.01 per share
|
|
87,045,104 |
Documents Incorporated by Reference:
Portions of the Proxy Statement for the 2005 Annual Meeting
of Stockholders
NRG ENERGY, INC. AND SUBSIDIARIES
INDEX
1
PART I
Item 1 Business
General
NRG Energy, Inc., or NRG Energy, the
Company, we, our, or
us is a wholesale power generation company,
primarily engaged in the ownership and operation of power
generation facilities, the transacting in and trading of fuel
and transportation services and the marketing and trading of
energy, capacity and related products in the United States and
internationally. We have a diverse portfolio of electric
generation facilities in terms of geography, fuel type and
dispatch levels. Our principal domestic generation assets
consist of a diversified mix of natural gas-, coal- and
oil-fired facilities, representing approximately 40%, 31% and
29% of our total domestic generation capacity, respectively. In
addition, 23% of our domestic generating facilities have dual-
or multiple-fuel capacity, which may allow plants to dispatch
with the lowest cost fuel option.
We seek to maximize operating income through the generation of
energy, marketing and trading of energy, capacity and ancillary
services into spot, intermediate and long-term markets and the
effective transacting in and trading of fuel supplies and
transportation-related services. We perform our own power
marketing (except with respect to our West Coast Power and Rocky
Road affiliates), which is focused on maximizing the value of
our North American and Australian assets through the pursuit of
asset-focused power and fuel marketing and trading activities in
the spot, intermediate and long-term markets. Our principal
objectives are the management and mitigation of commodity market
risk, the reduction of cash flow volatility over time, the
realization of the full market value of the asset base, and
adding incremental value by using market knowledge to
effectively trade positions associated with our asset portfolio.
Additionally, we work with markets, independent system operators
and regulators to promote market designs that provide adequate
long-term compensation for existing generation assets and to
attract the investment required to meet future generation needs.
As of December 31, 2004, we owned interests in 52 power
projects in five countries having an aggregate net generation
capacity of approximately 15,400 MW. Approximately
7,900 MW of our capacity consisted of merchant power plants
in the Northeast region of the United States. Certain of these
assets are located in transmission constrained areas, including
approximately 1,400 MW of in-city New York City
generation capacity and approximately 750 MW of southwest
Connecticut generation capacity. We also own approximately
2,500 MW of capacity in the South Central region of the
United States, with approximately 1,900 MW of that capacity
supported by long-term power purchase agreements.
As of December 31, 2004, our assets in the West Coast
region of the United States consisted of approximately
1,300 MW of capacity with the majority of such capacity
owned via our 50% interest in West Coast Power LLC, or West
Coast Power. Our assets in the West Coast region were supported
by a power purchase agreement with the California Department of
Water Resources that expired on December 31, 2004. One-year
term reliability must-run, or RMR, agreements with the
California Independent System Operator, or Cal ISO, for
approximately 568 MW in the San Diego area have been
renewed for 2005. On January 1, 2005, a new RMR agreement
for the 670 MW gross capacity of the West Coast Power El
Segundo generating facility became effective. In January 2005,
that generating facility entered into a tolling agreement for
its entire gross generating capacity of 670 MW commencing
May 1, 2005 and extending through December 31, 2005.
During the term of this agreement, the purchaser will be
entitled to primary energy dispatch right for the
facilitys generating capacity. The agreement is subject to
the amendment of the El Segundo RMR agreement to switch to RMR
Condition I and to otherwise allow the purchaser to exercise its
primary dispatch rights under this agreement while preserving
Cal ISOs ability to call on the El Segundo facility as a
reliability resource under the RMR agreement, if necessary.
Approximately 265 MW of capacity at the Long Beach
generating facility was retired January 1, 2005.
We own approximately 1,600 MW of net generating capacity in
other regions of the U.S. We also own interests in plants
having a net generation capacity of approximately 2,100 MW
in various international
2
markets, including Australia, Europe and Brazil. We operate
substantially all of our generating assets, including the West
Coast Power plants.
We were incorporated as a Delaware corporation on May 29,
1992. In March 2004, our common stock was listed on the New York
Stock Exchange under the symbol NRG. Our
headquarters and principal executive offices are located at 211
Carnegie Center, Princeton, New Jersey 08540. Our telephone
number is (609) 524-4500. The address of our website is
www.nrgenergy.com. Our recent annual reports, quarterly reports,
current reports and other periodic filings are available free of
charge through our website. Our Corporate Governance Guidelines
and the charters of our Audit, Compensation and Governance and
Nominating Committees are also available on our website at
www.nrgenergy.com/investor/corpgov.htm. These charters are
available in print to any shareholder who requests them.
Strategy
We are a significant owner and operator of a diverse portfolio
of electric generation facilities. We are focused on owning,
operating and maximizing the value of our generation assets in
our core regions, which are the Northeast, South Central and
West Coast regions of the United States, as well as Australia.
Our two principal objectives are: (i) to maximize the
operating performance of our entire portfolio, and (ii) to
protect and enhance the market value of our physical and
contractual assets through the execution of asset-based risk
management, marketing and trading strategies within well-defined
risk and liquidity guidelines.
To achieve our principal objectives, we intend to pursue the
following strategies, among others:
|
|
|
|
|
Develop the assets in our core regions into integrated
businesses well suited to serve the requirements of the
load-serving entities in our core markets; |
|
|
|
Reinvest our capital in our existing assets for reasons of
repowering, expansion, environmental remediation, operating
efficiency, reliability programs, greater fuel optionality,
greater merit order diversity, enhanced portfolio effect or
alternative use, among others; and |
|
|
|
Where consistent with our core region strategy,
pursue selective acquisitions to complement the assets and
portfolios in our core regions. |
From time to time we may also consider and undertake other
merger and acquisition transactions that are consistent with our
strategy. We continue to market our interest in our remaining
non-core assets. Thereafter, we have no current plans to market
actively any of our core assets, although our intention to
maximize over time the value of all of our assets could lead to
additional asset sales.
Competition
Wholesale power generation is a capital-intensive,
commodity-driven business with numerous industry participants.
Many of our large competitors are facing restructuring,
bankruptcy or liquidation. Many U.S. markets have a glut of
generation capacity. New sources of capital have entered the
industry, including well-capitalized financial players seeking
to acquire assets at distressed prices. Regulatory bodies,
including the Federal Energy Regulatory Commission, or FERC,
regional independent system operators, state public utility
commissions and other regulatory participants are considering
significant changes to the structure of certain wholesale
utility markets.
Many companies in the regulated utility industry, with which the
wholesale power industry is closely linked, are also
restructuring or reviewing their strategies. Several of those
companies are discontinuing their unregulated activities,
seeking to divest their unregulated subsidiaries or attempting
to have their regulated subsidiaries acquire assets out of their
or other companies unregulated subsidiaries. This may lead
to increased competition between the regulated utilities and the
unregulated power producers within certain markets.
3
Competitive Strengths
We believe that we benefit from the following competitive
strengths:
Plant Diversity. Our generation fleet in core regional
markets includes plants dispatched as baseload generation, on an
intermediate basis and during peak periods. Approximately
4,300 MWs of domestic baseload capacity provide stability
of cash flows, while 5,500 MWs of domestic peaking capacity
give us significant upside optionality. Our generation
facilities include a diversified fuel mix of natural gas, coal
and oil. A significant percentage of our core domestic
portfolio, approximately 31%, is fueled by coal, which is a
distinct advantage at a time of historically high natural gas
prices. We believe that our Huntley, Dunkirk, Big Cajun II
and Indian River coal-fired facilities will continue, for the
foreseeable future, to have competitive advantages in terms of
their marginal cost of production relative to the gas-fired
plants with which they compete. In addition, a significant
portion of our non-coal domestic generation facilities have dual
or multiple fuel capability, which allows most of these plants
to dispatch with the lowest cost fuel option. The volatility in
oil and gas prices versus the stability of low-sulfur western
coal prices creates opportunities for us because of our ability
to use low-sulfur coal in certain of our plants.
Locational Advantages. Owning multiple power plants in a
particular market provides greater dispatch flexibility and
increases power marketing and trading opportunities. We have
achieved this goal to a certain extent in the Northeast (New
York, New England Power Pool, or NEPOOL, and Pennsylvania,
Jersey, Maryland Interconnection, or PJM) and South Central
(Entergy) markets.
Transmission constraints and other market factors give certain
of our power plants locational advantages over the competition.
For example, the Astoria and Arthur Kill plants serve the New
York City market. Competitors outside the city limits are at a
disadvantage because transmission constraints restrict the
importation of power into New York City, providing an advantage
to in-city generation physically located within city
limits. Construction of new power plants in New York City is
limited because of the difficulties in finding sites for new
plants, obtaining the necessary permits and arranging fuel
delivery. In California, our facilities are located in the Los
Angeles and San Diego load basins where, similar to New
York City, transmission constraints restrict the import of power
from remotely located plants.
In some locations, a facilitys advantage is enhanced by
the potential for repowering or site expansion or alternative
use. Certain Connecticut facilities, for example, have
attractive locations in transmission-constrained areas in
southern Connecticut. The El Segundo plant located in the west
Los Angeles load basin is well positioned to serve the needs of
that region well into the future. Our California facilities
utilize ocean water cooling, which gives them competitive
advantages, especially during water shortages in California, and
provides a competitive advantage in the potential siting of
desalination projects or for other alternative uses. We are
working to preserve our options to expand or repower these
facilities when economically justifiable.
Risk Mitigation. As a wholesale generator, we are subject
to the risks associated with volatility in fuel and power
prices. We seek to mitigate these risks by managing a portfolio
of contractual relationships for power supply, fuel needs and
transportation services. We reduce spot price volatility
exposure via mid- and long-term contractual arrangements when
these markets economically justify such transactions. We plan to
trade around the contractual commitments consistent with our
market view in an effort to produce enhanced value from market
volatility.
Improved Financial Position. As part of our
reorganization (discussed below), we eliminated approximately
$5.2 billion of corporate level bank and bond debt and
approximately $1.3 billion of additional claims and
additional disputes. Since January 1, 2004, we have
successfully sold select non-core assets and eliminated
approximately $989.9 million of consolidated debt related
to those assets. We continued managing our balance sheet
throughout 2004 with the tack-on bond offering in January and
the refinancing of our credit facility in December.
Reorganization
We were formed in 1992 as the non-utility subsidiary of Northern
States Power Company, or NSP, which was itself merged into New
Century Energies, Inc. to form Xcel Energy, Inc., or Xcel
Energy, in 2000. While
4
owned by NSP and later by Xcel Energy, we pursued an aggressive
high growth strategy focused on power plant acquisitions, high
leverage and aggressive development, including site development
and turbine orders. In 2002, a number of factors, most notably
the aggressive prices paid by us for our acquisitions of
turbines, development projects and plants, combined with the
overall downturn in the power generation industry, triggered a
series of credit rating downgrades which, in turn, precipitated
a severe liquidity crisis at the Company. From May 14 to
December 23, 2003, we and a number of our subsidiaries
undertook a comprehensive reorganization and restructuring under
chapter 11 of the United States Bankruptcy Code. With the
exception of one subsidiary that remains in bankruptcy to effect
its liquidation, all NRG entities had emerged from
chapter 11 as of December 31, 2004.
As part of our reorganization, Xcel Energy relinquished its
ownership interest in us, and we became an independent public
company. We no longer have any material affiliation or
relationship with Xcel Energy. As part of the reorganization, we
eliminated approximately $5.2 billion of corporate level
bank and bond debt and approximately $1.3 billion of
additional claims and disputes by distributing a combination of
equity and $1.04 billion in cash to our unsecured creditors.
As part of our restructuring, on December 23, 2003, we used
the proceeds of a new $1.25 billion offering of 8% second
priority senior secured notes due 2013, and borrowings under a
new $1.45 billion secured credit facility, to retire
approximately $1.7 billion of project-level debt. In
January 2004, we used proceeds of a tack-on bond offering of the
same notes to repay $503.5 million of the outstanding
borrowings under the secured credit facility.
In 2004, we completed our post-confirmation bankruptcy
initiatives, including the liquidation of the chapter 11
subsidiaries deemed to be of no value to NRG Energy
(LSP-Nelson Energy LLC and NRG Nelson Turbines LLC); the
collection and distribution to creditors of amounts owing by our
pre-bankruptcy parent company, Xcel Energy, Inc., under the plan
of reorganization and related documents; and the settlement of
several large disputed claims. We are still litigating or
seeking to settle a number of unresolved disputed claims, for
which we believe we have established an adequate disputed claims
reserve pursuant to the NRG plan of reorganization. In all other
respects, the reorganization process was completed in 2004.
On December 24, 2004, we entered into an amendment and
restatement of our $1.45 billion seven-year secured credit
facility, recasting it as a $950 million seven-year secured
credit facility with more favorable covenants and interest
rates, scheduled to expire in December 2011. On
December 27, 2004, we completed the issuance of
$420 million of perpetual convertible preferred stock, and
used the proceeds to redeem $375 million of our 8% second
priority senior secured notes on February 4, 2005. In
January 2005 and in March 2005, we purchased $25 million
and $15.8 million, respectively, of the notes.
Fresh Start Reporting
As a result of our emergence from bankruptcy, we adopted Fresh
Start Reporting, or Fresh Start. Under Fresh Start, our
confirmed enterprise value was allocated to our assets and
liabilities based on their respective fair values. See
Item 7 Managements Discussion and
Analysis of Financial Condition and Results of
Operation Reorganization and Emergence from
Bankruptcy for additional information. 2004 was our first
complete year following the adoption of Fresh Start.
5
Performance Metrics
The following table contains a summary of our North American
power generation revenues from majority-owned subsidiaries for
the year 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Alternative |
|
|
|
|
|
|
|
|
Energy |
|
Capacity |
|
Energy |
|
|
|
Other |
|
Total |
Region |
|
Revenues |
|
Revenues |
|
Revenues |
|
O&M Fees |
|
Revenues*** |
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Northeast
|
|
$ |
853,454 |
|
|
$ |
264,624 |
|
|
$ |
49 |
|
|
$ |
|
|
|
$ |
133,026 |
|
|
$ |
1,251,153 |
|
South Central
|
|
|
219,112 |
|
|
|
183,483 |
|
|
|
|
|
|
|
|
|
|
|
15,550 |
|
|
|
418,145 |
|
West Coast*
|
|
|
9,276 |
|
|
|
(3,709 |
) |
|
|
|
|
|
|
(2 |
) |
|
|
(3,096 |
) |
|
|
2,469 |
|
Other
|
|
|
27,816 |
|
|
|
84,097 |
|
|
|
1,748 |
|
|
|
186 |
|
|
|
(8,203 |
) |
|
|
105,644 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total North America Power Generation**
|
|
$ |
1,109,658 |
|
|
$ |
528,495 |
|
|
$ |
1,797 |
|
|
$ |
184 |
|
|
$ |
137,277 |
|
|
$ |
1,777,411 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
Consists of our wholly-owned subsidiary, NEO California LLC.
Does not include revenues which were produced by assets in which
we have a 50% equity interest, primarily West Coast Power, and
are reported under the equity method of accounting. |
|
|
|
|
** |
For additional information see
Item 15 Note 23 of the Consolidated
Financial Statements for our consolidated revenues by segment
disclosures. |
|
|
*** |
Includes miscellaneous revenues from the sale of natural gas,
recovery of incurred costs under reliability must- run
agreements, revenues received under leasing arrangements,
revenues from maintenance, revenues from the sale of ancillary
services and revenues from entering into certain financial
transactions, offset by contract amortization. |
In understanding our business, we believe that certain
performance metrics are particularly important. These are
industry statistics defined by the North American Electric
Reliability Council and are more fully described below:
Annual Equivalent Availability Factor, or EAF: is the
total available hours a unit is available in a year minus the
sum of all partial outage events in a year converted to
equivalent hours (EH), where EH is partial megawatts lost
divided by unit net available capacity times hours of each
event, and the net of these hours is divided by hours in a year
to achieve EAF in percent.
Average gross heat rate: We calculate the average heat
rate for our fossil-fired power plants by dividing (a) fuel
consumed in Btus by (b) KWh generated. The resultant heat
rate is a measure of fuel efficiency.
Net Capacity Factor: Net actual generation divided by net
maximum capacity for the period hours.
The table below presents the North American power generation
performance metrics for owned assets discussed above for the
year ended December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual |
|
|
|
|
|
|
|
|
Net |
|
Equivalent |
|
Average Gross |
|
|
|
|
Net Owned |
|
Generation |
|
Availability |
|
Heat Rate |
|
Net Capacity |
Region |
|
Capacity (MW) |
|
(MWh) |
|
Factor |
|
Btu/KWh |
|
Factor |
|
|
|
|
|
|
|
|
|
|
|
Northeast*
|
|
|
7,884 |
|
|
|
13,205,017 |
|
|
|
85.6 |
% |
|
|
10,174 |
|
|
|
19.8 |
% |
South Central
|
|
|
2,469 |
|
|
|
10,470,786 |
|
|
|
92.1 |
% |
|
|
9,965 |
|
|
|
52.9 |
% |
West Coast**
|
|
|
1,315 |
|
|
|
2,354,668 |
|
|
|
80.0 |
% |
|
|
10,121 |
|
|
|
20.4 |
% |
Other North America
|
|
|
1,591 |
|
|
|
2,925,653 |
|
|
|
96.3 |
% |
|
|
N/A |
|
|
|
12.0 |
% |
|
|
|
|
* |
Net Generation and the other metrics do not include Keystone and
Conemaugh. |
|
|
** |
Includes 50% of the generation owned through our West Coast
Power partnership. |
6
The table below presents the Australian power generation
performance metrics discussed above for the year ended
December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual |
|
|
|
|
|
|
|
|
Net |
|
Equivalent |
|
Average Gross |
|
|
|
|
Net Owned |
|
Generation |
|
Availability |
|
Heat Rate |
|
Net Capacity |
Region |
|
Capacity (MW) |
|
(MWh) |
|
Factor |
|
Btu/KWh |
|
Factor |
|
|
|
|
|
|
|
|
|
|
|
Flinders Northern Power Station
|
|
|
520 |
|
|
|
3,924,196 |
|
|
|
93.2 |
% |
|
|
11,400 |
|
|
|
93.1 |
% |
Flinders Playford Power Station
|
|
|
240 |
|
|
|
365,642 |
|
|
|
46.0 |
% |
|
|
16,300 |
|
|
|
18.9 |
% |
Gladstone*
|
|
|
630 |
|
|
|
3,065,044 |
|
|
|
83.2 |
% |
|
|
9,600 |
|
|
|
55.4 |
% |
|
|
* |
Includes 37.5% of the generation owned through our Gladstone
partnership. |
Power Generation
Facilities. As of December 31, 2004, we owned
7,884 MW of net generation capacity in the Northeast region
of the United States, primarily in New York, Connecticut and
Delaware. These generation facilities are diversified in terms
of dispatch level (base-load, intermediate and peaking), fuel
type (coal, natural gas and oil) and customers.
The Northeast regions power generation assets as of
December 31, 2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
Power |
|
Capacity |
|
Ownership |
|
|
Name and Location of Facility |
|
Market |
|
(MW) |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
Oswego, New York
|
|
|
NYISO |
|
|
|
1,700 |
|
|
|
100 |
% |
|
|
Oil/Gas |
|
Huntley, New York
|
|
|
NYISO |
|
|
|
760 |
|
|
|
100 |
% |
|
|
Coal |
|
Dunkirk, New York
|
|
|
NYISO |
|
|
|
600 |
|
|
|
100 |
% |
|
|
Coal |
|
Arthur Kill, New York
|
|
|
NYISO |
|
|
|
842 |
|
|
|
100 |
% |
|
|
Gas/Oil |
|
Astoria Gas Turbines, New York
|
|
|
NYISO |
|
|
|
600 |
|
|
|
100 |
% |
|
|
Gas/Oil |
|
Somerset, Massachusetts
|
|
|
ISO-NE |
|
|
|
136 |
|
|
|
100 |
% |
|
|
Coal/Oil |
|
Middletown, Connecticut
|
|
|
ISO-NE |
|
|
|
786 |
|
|
|
100 |
% |
|
|
Oil/Gas/Jet Fuel |
|
Montville, Connecticut
|
|
|
ISO-NE |
|
|
|
498 |
|
|
|
100 |
% |
|
|
Oil/Gas/Diesel |
|
Devon, Connecticut
|
|
|
ISO-NE |
|
|
|
401 |
|
|
|
100 |
% |
|
|
Gas/Oil/Jet Fuel |
|
Norwalk Harbor, Connecticut
|
|
|
ISO-NE |
|
|
|
353 |
|
|
|
100 |
% |
|
|
Oil |
|
Connecticut Jet Power, Connecticut
|
|
|
ISO-NE |
|
|
|
127 |
|
|
|
100 |
% |
|
|
Jet Fuel |
|
Indian River, Delaware
|
|
|
PJM |
|
|
|
784 |
|
|
|
100 |
% |
|
|
Coal/Oil |
|
Vienna, Maryland
|
|
|
PJM |
|
|
|
170 |
|
|
|
100 |
% |
|
|
Oil |
|
Conemaugh, Pennsylvania
|
|
|
PJM |
|
|
|
64 |
|
|
|
4 |
% |
|
|
Coal/Oil |
|
Keystone, Pennsylvania
|
|
|
PJM |
|
|
|
63 |
|
|
|
4 |
% |
|
|
Coal/Oil |
|
Market Framework. Our largest asset base is located in
the Northeast region. This asset base is comprised of
investments in generation facilities primarily located in the
physical control areas of the New York Independent System
Operator, or NYISO, the ISO New England, Inc., or ISO-NE, and
the Pennsylvania, Jersey, Maryland Interconnection, or PJM.
Although each of the three northeast ISOs and their respective
energy markets are functionally, administratively and
operationally independent, they all follow, to a certain extent,
the FERC-endorsed model for Standard Market Design, or SMD. The
physical power deliveries in these markets are financially
settled by Locational Marginal Prices, or LMPs, which reflect
the value of energy at a specific location at the specific
7
time it is delivered. This value is determined by an ISO-
administered auction process, which evaluates and selects the
least costly supplier offers or bids to fill the
specific locational requirement. The ISO-sponsored LMP energy
marketplaces consist of two separate and characteristically
distinct settlement time frames. The first is a
security-constrained, financially firm, Day Ahead
unit commitment market. The second is a security-constrained,
financially settled, Real-time dispatch and
balancing market. In addition to energy delivery, the ISOs
manage secondary markets for installed capacity, ancillary
services and financial transmission rights.
Market Developments. ISO-NE and NEPOOL operate a
centralized energy market with Day-Ahead and
Real-time energy markets. On August 23, 2004,
ISO-NE filed its proposal for locational installed capacity, or
LICAP, with FERC, which will decide the issue in a litigated
proceeding before an administrative law judge. Under the
proposal, separate capacity markets would be created for
distinct areas of New England, including southwest Connecticut.
While we view this proposal as a positive development, as it is
currently proposed it would not permit us to recover all of our
fixed costs. In response, we have submitted testimony which
includes an alternative proposal. FERCs goal is to make a
decision on the precise terms of the NEPOOL LICAP market in the
fall of 2005, to be effective January 1, 2006.
On January 27, 2005, FERC approved the settlement of
various reliability must-run, or RMR, agreements between some of
our Connecticut generation and ISO-NE. Under the settlement, we
will receive monthly payments for the Devon 11-14, Montville and
Middletown facilities until December 31, 2005, the day
before the expected implementation date for LICAP. The
settlement also requires the payment of third party maintenance
expenses by NEPOOL participants incurred by Devon 11-14,
Middletown, Montville and Norwalk Harbor and are capped at
$30 million for the period April 1, 2004 through
December 31, 2005. The settlement also approves prior RMR
agreements involving Devon 7 and 8, both of which are on
deactivated reserves.
The NYISO operates an energy market that is structurally the
same as the New England energy markets. In April 2003, NYISO
implemented a demand curve in its capacity market and scarcity
pricing improvements in its energy market. The New York demand
curve eliminated the previous market structures tendency
to price capacity at either its cap (deficiency rate) or near
zero. FERC had previously approved the demand curve, but on
December 19, 2003, the Electricity Consumers Resource
Council appealed the FERC decision to the United States Court of
Appeals for the District of Columbia Circuit. On
December 3, 2004, NRG Energy and other suppliers filed a
brief in opposition. An adverse decision by the Court of Appeals
could require the elimination of the demand curve for the
capacity market, and would negatively impact the development of
LICAP in New England and PJM in addition to New York.
On January 7, 2005, NYISO filed proposed LICAP demand
curves for the following capacity years: 2005-06, 2006-07 and
2007-08. Under the NYISO proposal, the LICAP price for New York
City generation would be $126 per KW-year for the capacity
year 2006-07. On January 28, 2005, we filed a protest at
FERC asserting the LICAP price for this period should be at
least $140 per KW-year.
Our New York City generation is presently subject to price
mitigation in the installed capacity market. When the capacity
market is tight, the price we receive is limited by the
mitigation price. However when the New York City capacity market
is not tight, such as during the winter season, the proposed
demand curve price levels should increase our revenues from
capacity sales.
On January 25, 2005, FERC issued an order approving the PJM
proposal to increase the compensation for generators which are
located in load pockets and are mitigated at least 80% of their
running time. Specifically, when a generator would be subject to
mitigation, the generator would have the option of recovering
its variable cost plus $40 or a negotiated rate with PJM, based
on the facilitys going forward costs. If the generator
declines both options, it could file for an alternative rate
with FERC. FERC also substantially revised the exemption of
facilities built after 1996 from the energy price capping
mitigation rule. Several of our facilities are presently
mitigated 80% of the time and, therefore, are impacted by the
change.
8
Facilities. As of December 31, 2004, we owned
2,469 MW of net generating capacity in the South Central
region of the United States. The South Central regions
generating assets consist primarily of our power generation
facilities in New Roads, Louisiana, referred to as the Cajun
Facilities, and the Sterlington and Bayou Cove generating
facilities.
Our portfolio of plants in Louisiana comprises the third largest
generator in the Southeastern Electric Reliability Council/
Entergy, or SERC-Entergy region. Our primary assets are the
Cajun Facilities, which are primarily coal-fired assets
supported by long-term power purchase agreements with regional
cooperatives.
The South Central regions power generation assets as of
December 31, 2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
Power |
|
Capacity |
|
Ownership |
|
Fuel |
Name and Location of Facility |
|
Market |
|
(MW) |
|
Interest |
|
Type |
|
|
|
|
|
|
|
|
|
Big Cajun II, Louisiana*
|
|
|
SERC-Entergy |
|
|
|
1,489 |
|
|
|
86 |
% |
|
|
Coal |
|
Big Cajun I, Louisiana
|
|
|
SERC-Entergy |
|
|
|
458 |
|
|
|
100 |
% |
|
|
Gas/Oil |
|
Bayou Cove, Louisiana
|
|
|
SERC-Entergy |
|
|
|
320 |
|
|
|
100 |
% |
|
|
Gas |
|
Sterlington, Louisiana
|
|
|
SERC-Entergy |
|
|
|
202 |
|
|
|
100 |
% |
|
|
Gas |
|
|
|
* |
We own 100% of Units 1 and 2 and 58% of Unit 3. |
Market Framework. Our South Central regions assets
are located within the franchise territory of Entergy, a
vertically-integrated utility. Entergy performs the scheduling,
reserve and reliability functions that are administered by ISOs
in certain other regions of the United States and Canada. We
operate a North American Electric Reliability Council, or NERC,
certified-control area within the Entergy franchise territory,
which is comprised of our generating assets and our
cooperatives customer loads. In the South Central region,
including Entergys franchise territory, the energy market
is not a centralized market and it does not have an independent
system operator as is found in the northeast markets. All power
sales and purchases are consummated bilaterally between
individual counter-parties, and physically delivered either
within or across the physical control areas of the transmission
owners. Transacting counter-parties are required to reserve and
purchase transmission services from the intervening transmission
owners at their FERC-approved tariff rates. Included with these
transmission services are the reserve and ancillary costs.
Energy prices in the South Central region are determined and
agreed to in bilateral negotiations between representatives of
the transacting counter-parties, using market information
gleaned by the individual marketing agents arranging the
transactions.
Market Developments. We have long-term all
requirements contracts with 11 Louisiana distribution
cooperatives, serving approximately 350,000 retail customers,
and long-term contracts with the Municipal Energy Agency of
Mississippi, South Mississippi Electric Power Association and
Southwestern Electric Power Company. With limited exceptions,
the all-requirements nature of certain of the power supply
agreements between Louisiana Generating and its cooperative
customers requires Louisiana Generating to serve future
expansion of those cooperative loads at existing contract rates.
Additionally, at times of maximum demand, our generating
facilities do not produce enough power to serve their customers,
and we purchase power in the market to make up the shortfall.
Entergy has filed an Independent Coordinator of Transmission, or
ICT, proposal at FERC and with the public service commissions of
the states of Louisiana, Mississippi and Arkansas. Entergy
states that this proposal will achieve greater oversight of its
transmission system operation and provide greater efficiency for
providing and pricing transmission service. On March 22,
2005, FERC approved the ICT proposal for a two-year period,
subject to certain conditions.
On December 17, 2004, FERC ordered that an investigation
and evidentiary hearing be held to determine whether Entergy is
providing access to its transmission system on a short-term
basis and in a just and
9
reasonable manner. On March 22, 2005, FERC suspended the
hearing until Entergy indicates whether it will accept the
FERCs conditional approval of its ICT proposal. On
March 25, 2005, FERC permitted Entergys proposal
regarding reserving 2,900 MWs of import capacity on its
transmission system for emergency purposes to go into effect
subject to refund. The case was set for hearing, which was then
suspended pending settlement discussions.
In December 2004, we entered into a long-term coal transport
agreement with the Burlington Northern and Santa Fe Railway
Company and affiliates of American Commercial Lines LLC to
deliver low sulfur coal to our Big Cajun II facility in New
Roads, Louisiana beginning April 1, 2005. In December 2004,
we also entered into coal purchase contracts extending through
2007. In March 2005, we entered into an agreement to purchase
23.75 tons of coal over a period of four years and nine
months from Buckskin Mining Company, or Buckskin. The coal will
be sourced from Buckskins mine in the Powder River Basin,
Wyoming, and will be used primarily in NRG Energys
coal-burning generation plants in the South Central region.
In August 2004, we entered into a contract to
purchase 1,540 aluminum railcars from Johnston America
Corporation to be used for the transportation of low sulfur coal
from Wyoming to NRG Energys coal burning generating
plants, including the Cajun Facilities. On February 18,
2005, we entered into a ten-year operating lease agreement with
GE Railcar Services Corporation, or GE, for the lease of 1,500
railcars and delivery commenced in February 2005. We have
assigned certain of our rights and obligations for 1,500
railcars under the purchase agreement with Johnston America to
GE. Accordingly, the railcars which we lease from GE under the
arrangement described above will be purchased by GE from
Johnston America in lieu of our purchase of those railcars.
Facilities. As of December 31, 2004, we owned
1,315 MW of net generating capacity in the West Coast
region, primarily in California and Nevada. Our West Coast
generation assets consist primarily of a 50% interest in West
Coast Power LLC, or West Coast Power. Effective January 1,
2005, the Long Beach Generating Station was permanently retired,
reducing our net generating capacity by 265 MW, to
1,050 MW. The ultimate disposition of the Long Beach plant
and property has yet to be determined. However, site demolition
and remediation costs, if required, are expected to approximate
the market value of the property. The Company has been
negotiating a sale of the Saguaro plant and closing is expected
to take place sometime during 2005.
In May 1999 we formed West Coast Power, along with Dynegy, Inc.,
to serve as the holding company for a portfolio of operating
companies that own generation assets in Southern California in
the California Independent System Operator, or Cal ISO, market.
This portfolio currently consists of the El Segundo
Generating Station, the Encina Generating Station and
13 combustion turbines in the San Diego area. Dynegy
provides power marketing and fuel procurement services to West
Coast Power, and we provide operations and management services.
On December 23, 2004, California Energy Commission, or CEC,
approved our application for a permit to repower the existing
El Segundo site and replace retired units 1 and 2 with
630 MW of new generation. On January 19, 2005, the CEC
voted unanimously to reconsider its December 23, 2004
decision to certify the repowering project. The reconsideration
hearing took place on February 2, 2005 and the permit was
approved by unanimous vote of the CEC. The reconsideration
extended the 30-day period in which parties may petition for
rehearing or seek judicial review to March 4, 2005. A
petition seeking review of the CEC final order was filed with
the California Supreme Court on March 14, 2005. We believe
this filing to be untimely.
Our West Coast Power assets were supported by a power purchase
agreement with the California Department of Water Resources that
expired on December 31, 2004. We do not anticipate that we
can replace that contract with one that has similar or more
attractive terms and conditions. One-year term RMR contracts
with Cal ISO for 576 MW of net owned capacity in the
San Diego area have been renewed for 2005. On
January 1, 2005, a new RMR agreement for the 670 MW
gross capacity of the West Coast Power El Segundo
generating facility became effective. In January 2005, that
generating facility entered into a tolling agreement for its
entire gross generating capacity of 670 MW commencing
May 1, 2005 and extending through
10
December 31, 2005. During the term of this agreement, the
purchaser will be entitled to primary energy dispatch right for
the facilitys generating capacity. The agreement is
subject to the amendment of the El Segundo
RMR agreement to switch to RMR Condition I and to
otherwise allow the purchaser to exercise its primary dispatch
rights under this agreement while preserving Cal ISOs
ability to call on the El Segundo facility as a reliability
resource under the RMR agreement, if necessary. The RMR contract
on approximately 45 MW of generating capacity at Red Bluff
expired on December 31, 2004 and will not be renewed for
2005.
The West Coast regions power generation assets as of
December 31, 2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
Power |
|
Capacity |
|
Ownership |
|
Fuel |
Name and Location of Facility |
|
Market |
|
(MW) |
|
Interest |
|
Type |
|
|
|
|
|
|
|
|
|
Encina, California
|
|
|
Cal ISO |
|
|
|
483 |
|
|
|
50 |
% |
|
|
Gas/Oil |
|
El Segundo Power, California
|
|
|
Cal ISO |
|
|
|
335 |
|
|
|
50 |
% |
|
|
Gas |
|
Long Beach Generating, California*
|
|
|
Cal ISO |
|
|
|
265 |
|
|
|
50 |
% |
|
|
Gas |
|
San Diego Combustion Turbines, California
|
|
|
Cal ISO |
|
|
|
85 |
|
|
|
50 |
% |
|
|
Gas/Oil |
|
Saguaro Power Co., Nevada
|
|
|
WECC |
|
|
|
53 |
|
|
|
50 |
% |
|
|
Gas/Oil |
|
Chowchilla, California
|
|
|
Cal ISO |
|
|
|
49 |
|
|
|
100 |
% |
|
|
Gas |
|
Red Bluff, California
|
|
|
Cal ISO |
|
|
|
45 |
|
|
|
100 |
% |
|
|
Gas |
|
|
|
* |
Retired effective January 1, 2005 |
Market Framework. Our West Coast region assets are
primarily located within the control area of Cal ISO. Cal ISO
operates a financially settled Real-time balancing
market similar to the regional ISOs in the northeast area of the
U.S. Cal ISOs Day Ahead energy markets
are similar to those in the South Central region, with all power
sales and purchases consummated bilaterally between individual
counter-parties and scheduled for physical delivery with Cal ISO.
Market Developments. In California, Cal ISO continues
with its plan to move toward markets similar to PJM, NYISO and
ISO-NE, with its Market Redesign & Technology Upgrade,
or MRTU, formerly known as MD02 (market design 2002). The
proposed changes will re-establish a real-time
market and allow for multiple settlements. NRG Energy views this
as an improvement to the existing structure. In general, Cal ISO
is continuing along a path of small incremental changes, rather
than implementing a comprehensive market restructuring. The
effect of the new MRTU changes on NRG Energy cannot be
determined at this time.
In addition to the Cal ISOs market changes, numerous
legislative initiatives in California create uncertainty and
risk for us. Most significantly, SB39XX mandates that the
California Public Utilities Commission, or CPUC, exercise
jurisdiction over the operating and maintenance procedures of
wholesale power generators including the setting of operating,
maintenance and logbook standards. On October 28, 2004, the
CPUC issued draft orders directing in-state utilities to meet a
15-17% reserve requirement by no later than June 2006, and
establishing a requirement that the utilities acquire 90% of
their capacity needs a year in advance. This order may present
opportunities for West Coast Power to enter into new bilateral
agreements.
In September 2004, Governor Schwarzenegger vetoed AB2006,
commonly referred to as the re-regulation
initiative, with a promise to the people of California to create
a competitive energy market in California that will attract the
investment capital required to meet growing load obligations.
Facilities. As of December 31, 2004, we owned
approximately 1,591 MW of net generating capacity in other
regions of the U.S.
11
Our Other North America power generation assets as of
December 31, 2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
|
|
Capacity |
|
Ownership |
|
Fuel |
Name and Location of Facility |
|
Power Market |
|
(MW) |
|
Interest |
|
Type |
|
|
|
|
|
|
|
|
|
Audrain, Missouri*
|
|
|
MAIN |
|
|
|
640 |
|
|
|
100% |
|
|
|
Gas |
|
Rockford I, Illinois
|
|
|
MAIN |
|
|
|
342 |
|
|
|
100% |
|
|
|
Gas |
|
Rockford II, Illinois
|
|
|
MAIN |
|
|
|
171 |
|
|
|
100% |
|
|
|
Gas |
|
Rocky Road Power, Illinois
|
|
|
PJM |
|
|
|
175 |
|
|
|
50% |
|
|
|
Gas |
|
Ilion, New York
|
|
|
NYISO |
|
|
|
60 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
Dover, Delaware
|
|
|
PJM |
|
|
|
106 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
James River, Virginia*
|
|
|
SERC-TVA |
|
|
|
55 |
|
|
|
50% |
|
|
|
Coal |
|
Paxton Creek Cogeneration
|
|
|
PJM |
|
|
|
12 |
|
|
|
100% |
|
|
|
Gas |
|
Other 3 projects*
|
|
|
Various |
|
|
|
30 |
|
|
|
Various |
|
|
|
Various |
|
|
|
* |
May sell or dispose of in the next 12 months. |
Facilities. As of December 31, 2004, we owned
approximately 1,390 MW of net generating capacity in
Australia. The Flinders assets are comprised of the Northern
Power Station which provides 520 MW, the refurbished
Playford Power Station, which provides 240 MW and the Leigh
Creek Coal Mine which supplies coal to both plants. The
1,680 MW Gladstone Plant, of which we own 37.5%, is
operated by NRG Energy.
Our Australian power generation assets as of December 31,
2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
|
|
Capacity |
|
Ownership |
|
Fuel |
Name and Location of Facility |
|
Purchaser/ Power Market |
|
(MW) |
|
Interest |
|
Type |
|
|
|
|
|
|
|
|
|
Flinders, South Australia
|
|
National Electricity Market |
|
|
760 |
|
|
|
100% |
|
|
|
Coal |
|
Gladstone Power Station, Queensland
|
|
Enertrade/Boyne Smelters |
|
|
630 |
|
|
|
37.5% |
|
|
|
Coal |
|
The National Electricity Market operates across the
interconnected states of southern and eastern Australia. The
market represents a physical wholesale trading exchange based on
merit order generation dispatch and gross pool settlement,
within an energy-only market design. The physical market is
managed by National Electricity Market Management Co. Ltd.,
or NEMMCO, as the independent market operator, with spot prices
determined on a regional basis in half-hourly trading intervals,
capped at a maximum of AUD 10,000/ MWh. The majority of
wholesale trading occurs through bilateral financial
(hedge) contracts between counter-parties on a regional
basis, with some limited financial trading through exchange
traded futures.
The Flinders plant operates within the market as a merchant
portfolio. Northern Power Station (520 MW base load) and
Playford Power Station (240 MW mid merit) are the only
coal-fired units in South Australia. Their output, together with
the output of the gas fired Osborne Power Station (output
purchased under long-term power purchase agreements, or PPAs)
supply over 40% of the states electricity. All output is
market traded, with revenue streams protected by hedge contracts
for a large proportion of forward output.
The output of Gladstone is fully contracted under long-term PPAs
to an adjacent aluminum smelter and a government entity that
trades its portion into the market.
12
In late 2003, the governments spanning the National Electricity
Market embarked upon a series of reforms to address perceived
deficiencies in the governance and institutional structure of
the market. These reforms are proceeding under cooperative
legislation expected to be in operation by mid-2005, and include
the creation of a new national energy regulator and the
establishment of a more efficient process to change and
administer the rules governing the operation of the market.
These reforms are not intended to alter the operation or
fundamental design of the market, but are designed to streamline
the administration of the wholesale market, increase regulatory
certainty for investors, and improve rule change and
decision-making processes in both the electricity and gas
sectors.
Further policy announcements are expected in the near future in
relation to electricity transmission planning and regulation,
trading region boundary change arrangements, and funding
arrangements for the new institutional bodies.
Facilities. Over the past decade, through our foreign
subsidiaries, we invested in international power generation
projects in Australia, Europe and Latin America. During 2002,
2003 and 2004, we sold international generation projects with an
aggregate total generating capacity of approximately
600 MW, 1,640 MW and 833 MW, respectively. As of
December 31, 2004, we had investments in power generation
projects located in the United Kingdom, Germany and Brazil with
approximately 768 MW of net generating capacity.
Our Other International power generation assets as of
December 31, 2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
Net Owned |
|
Percentage |
|
|
|
|
|
|
Capacity |
|
Ownership |
|
Fuel |
Name and Location of Facility |
|
Purchaser/ Power Market |
|
(MW) |
|
Interest |
|
Type |
|
|
|
|
|
|
|
|
|
Europe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Enfield Energy Centre, UK*
|
|
UK Electricity Grid |
|
|
95 |
|
|
|
25 |
% |
|
|
Gas |
|
Schkopau Power Station, Germany
|
|
Vattenfall Europe |
|
|
400 |
|
|
|
42 |
% |
|
|
Coal |
|
MIBRAG mbH, Germany**
|
|
ENVIA/MIBRAG Mines |
|
|
119 |
|
|
|
50 |
% |
|
|
Coal |
|
Brazil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Itiquira Energetica, Brazil*
|
|
COPEL |
|
|
154 |
|
|
|
99 |
% |
|
|
Hydro |
|
|
|
|
|
* |
NRG may sell or dispose of in the next 12 months. |
|
|
** |
Primarily a coal mining facility. |
|
|
|
Alternative Energy and Services |
We own alternative energy generation facilities through NEO
Corporation, or NEO, and through our NRG Resource Recovery
business division, which converts municipal solid waste, or MSW,
into refuse derived fuel suitable to burn in third party power
plants.
NEO Corporation. NEO is a wholly-owned subsidiary that
was formed to develop power generation facilities ranging in
size from one to 49 MW in the United States. As of
December 31, 2004, NEO had 41 MW of net ownership
interests in 15 hydroelectric facilities and 98.6 MW
of net ownership interests in four distributed generation
facilities including 94 MW of gas-fired peaking engines in
California (referred to as the Red Bluff and Chowchilla
facilities and included in our summary of the West Coast
region). Certain of the assets owned by NEO are currently being
marketed. See Significant Dispositions of Non-Strategic
Assets under this Item 1 for more information.
13
Resource Recovery Facilities. Our Resource Recovery
business is focused on owning and operating alternative
fuel/green power generation and fuels processing
projects. The alternative fuels currently processed and
combusted are municipal solid waste, urban wood waste (pallets,
clean construction debris, etc.), and non-recyclable waste paper
and compost. Our Resource Recovery business has municipal solid
waste processing capacity of approximately 2,800 tons per
day. Our Resource Recovery business owns and operates municipal
solid waste processing facilities in Minnesota, as well as NRG
Processing Solutions, including ten composting and biomass fuel
processing sites in Minnesota, three of which are permitted to
operate as municipal solid waste transfer stations.
Our significant Resource Recovery assets as of December 31,
2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Net Owned |
|
Ownership |
|
|
Name and Location of Facility |
|
Purchaser/ MSW Supplier |
|
Capacity |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
Newport, MN*
|
|
Ramsey and Washington Counties |
|
1,500 tons/day |
|
|
100% |
|
|
Refuse Derived Fuel |
Elk River, MN**
|
|
Anoka, Hennepin and Sherburne Counties; Tri- County Solid Waste
Management Commission |
|
1,275 tons/day |
|
|
85% |
|
|
Refuse Derived Fuel |
|
|
|
|
* |
The Newport facilities are related strictly to municipal solid
waste processing (MSW). |
|
|
** |
Our 85% interest in the Elk River facility is related strictly
to municipal solid waste processing. |
In addition to our traditional power generation facilities
discussed above, we have interests in district heating and
cooling systems and steam transmission operations through our
subsidiary, NRG Thermal LLC. NRG Thermals steam and
chilled water businesses have a steam and chilled water capacity
of approximately 1,225 megawatt thermal equivalents, or MWt.
As of December 31, 2004, NRG Thermal owned five district
heating and cooling systems in Minneapolis, Minnesota;
San Francisco, California; Pittsburgh, Pennsylvania;
Harrisburg, Pennsylvania; and San Diego, California. These
systems provide steam heating to approximately
565 customers and chilled water to 90 customers. In
addition, NRG Thermal owns and operates three projects that
serve industrial/government customers with high-pressure steam
and hot water, an 88 MW combustion turbine peaking
generation facility and an 18 MW coal-fired cogeneration
facility in Dover, Delaware (included in the summary of the
Other North America region).
14
Our thermal and chilled water assets as of December 31,
2004 are summarized in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Net Owned |
|
Ownership |
|
|
Name and Location of Facility |
|
Customers |
|
Capacity* |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
NRG Energy Center Minneapolis, Minnesota
|
|
Approx. 100 steam customers and 45 chilled water
customers |
|
Steam: 1,203 mm Btu/hr. (353 MWt)
Chilled water: 41,630 tons (146 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center San Francisco, California
|
|
Approx. 170 steam customers |
|
Steam: 482 mm Btu/hr. (141 MWt) |
|
|
100% |
|
|
|
Gas |
|
NRG Energy Center Harrisburg, Pennsylvania
|
|
Approx. 270 steam customers and 3 chilled water
customers |
|
Steam: 440 mm Btu/hr. (129 MWt)
Chilled water: 2,400 tons (8 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center Pittsburgh, Pennsylvania
|
|
Approx. 25 steam and 25 chilled water customers |
|
Steam: 266 mm Btu/hr. (78 MWt)
Chilled water: 12,580 tons (44 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center San Diego, California
|
|
Approx. 20 chilled water customers |
|
Chilled water: 7,425 tons (26 MWt) |
|
|
100% |
|
|
|
Gas |
|
NRG Energy Center
St. Paul, Minnesota
|
|
Rock-Tenn Company |
|
Steam: 430 mm Btu/hr. (126 MWt) |
|
|
100% |
|
|
|
Coal/Gas/Oil |
|
Camas Power Boiler Washington
|
|
Georgia-Pacific Corp. |
|
Steam: 200 mm Btu/hr. (59 MWt) |
|
|
100% |
|
|
|
Biomass |
|
NRG Energy Center
Dover, Delaware
|
|
Kraft Foods, Inc. |
|
Steam: 190 mm Btu/hr. (56 MWt) |
|
|
100% |
|
|
|
Coal |
|
NRG Energy Center
Bayport, Minnesota
|
|
Andersen Corporation and Minnesota Correctional Facility |
|
Steam: 200 mm Btu/hr. (59 MWt) |
|
|
100% |
|
|
|
Coal/Gas/Propane |
|
|
|
* |
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. |
Energy Marketing
Our wholly-owned energy marketing subsidiary, NRG Power
Marketing, Inc., or PMI, began operations in 1998. PMI provides
a full range of energy management services for our domestic
generation facilities. These services are provided under
bilateral contracts or agreements pursuant to which PMI engages
in the sale,
15
purchase and trading of energy, capacity and ancillary services
from the facilities, transacts in and trades the fuel (coal, oil
and natural gas) and associated transportation, and manages and
trades the emission allowance credits for these facilities. A
significant responsibility of PMI is to recommend to senior
management commercial hedge transactions in an effort to manage
risk and to maximize earnings and cash flow for NRG Energy.
In addition, PMI provides all necessary ISO bidding, dispatch,
and transmission scheduling for the facilities. PMI also
utilizes its contractual arrangements with third parties to
procure fuel, to sell energy, capacity and ancillary services to
minimize administrative costs and burdens and reduce the
collateral requirements imposed by third party suppliers and
purchasers.
NRG Worldwide Operations
Our wholly-owned subsidiary, NRG Worldwide Operations, or NRG
Operations, provides operating and maintenance services to our
generation facilities. These services include providing
experienced personnel for the operation and administration of
each facility and oversight out of the corporate office to
balance resources, share expertise and best practices, and to
ensure the optimum utilization of resources available to the
facilities. In addition, NRG Operations provides overall
facilities management, strategic planning, and the development
and dissemination of consistent Company policies and practices
relating to operations.
Financial Information About Segments and Geographic Areas
For financial information on our operations on a geographical
and on a segment basis, see Item 15
Note 23 to the Consolidated Financial Statements.
Dispositions of Non-Strategic Assets
We continue to market our interest in our remaining non-core
assets. Since 2003, we sold or made arrangements to sell a
number of consolidated businesses and equity investments in an
effort to reduce our debt, improve liquidity and rationalize our
investments. Dispositions completed during 2004 are summarized
in the following chart:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/(Loss) on |
|
Debt |
Asset (Location) |
|
Segment |
|
Closing Date |
|
Proceeds |
|
Disposition |
|
Reduction |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Calpine Cogeneration
|
|
Other North America |
|
|
3/07/2004 |
|
|
$ |
3.0 |
|
|
$ |
0.7 |
|
|
$ |
|
|
Loy Yang (Australia)
|
|
Australia |
|
|
4/08/2004 |
|
|
|
26.7 |
|
|
|
(1.3 |
) |
|
|
|
|
PERC (Maine)
|
|
Other North America |
|
|
4/16/2004 |
|
|
|
18.4 |
|
|
|
3.2 |
|
|
|
25.2 |
|
Cobee (Bolivia)
|
|
Other International |
|
|
4/27/2004 |
|
|
|
50.0 |
|
|
|
2.8 |
|
|
|
24.1 |
|
Hsin Yu (Taiwan)
|
|
Other International |
|
|
5/13/2004 |
|
|
|
1.0 |
|
|
|
10.3 |
|
|
|
46.4 |
|
McClain (Oklahoma)
|
|
Other North America |
|
|
7/09/2004 |
|
|
|
160.2 |
|
|
|
(3.0 |
) |
|
|
156.5 |
|
Batesville (Mississippi)
|
|
Other North America |
|
|
7/24/2004 |
|
|
|
27.6 |
|
|
|
11.0 |
|
|
|
289.3 |
|
NEO projects
|
|
Alternative Energy |
|
|
9/30/2004 |
|
|
|
5.8 |
|
|
|
6.0 |
|
|
|
|
|
NEO equity projects
|
|
Alternative Energy |
|
|
9/30/2004 |
|
|
|
6.1 |
|
|
|
(3.8 |
) |
|
|
|
|
CALP, Virginia
|
|
Other North America |
|
|
11/30/2004 |
|
|
|
14.9 |
|
|
|
(4.6 |
) |
|
|
|
|
Kendall, Illinois
|
|
Other North America |
|
|
12/01/2004 |
|
|
|
1.0 |
|
|
|
(26.5 |
) |
|
|
448.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
$ |
314.7 |
|
|
$ |
(5.2 |
) |
|
$ |
989.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Significant Customers
For the year ended December 31, 2004, we derived
approximately 49.8% of our total revenues from majority-owned
operations from four customers: NYISO accounted for 28.5%, ISO
New England accounted for 9.1%, National Electricity Market
Management Co. Ltd (Australia) accounted for 6.8% and Vattenfall
Europe (Germany) accounted for 5.4%. We account for the revenues
attributable to NYISO and ISO-NE as
16
part of our North American power generation segment. We account
for the revenues attributable to National Electricity Market
Management and Vattenfall Europe as part of our International
segment. For the period December 6, 2003 through
December 31, 2003, we derived approximately 39.0% of our
total revenues from majority-owned operations from two
customers: NYISO accounted for 26.5% and ISO-NE accounted for
12.5%. ISO-NE and NYISO are ISOs or RTOs and are FERC-regulated
entities that administer a residual (spot) energy market
and manage transmission assets collectively under their
respective control to provide non-discriminatory access to the
transmission grid. The NYISO exercises operational control over
most of New York States transmission facilities. We
anticipate that NYISO will continue to be a significant customer
given the scale of our asset base in the NYISO control area.
For the period January 1, 2003 through December 5,
2003 and for the year ended December 31, 2002, sales to one
customer, NYISO, accounted for 33.4% and 26.0% of our total
revenues from majority-owned operations, respectively.
Seasonality and Price Volatility
Annual and quarterly operating results can be significantly
affected by weather and price volatility. Significant other
events, such as the demand for natural gas and relative levels
of hydroelectric capacity can increase seasonal fuel and power
price volatility. We derive a majority of our annual revenues in
the months of May through September, when demand for electricity
is the highest in our North American markets. Further,
volatility is generally higher in the summer months due to the
effect of temperature variations. Our second most important
season is winter when volatility and price spikes in underlying
fuel prices have tended to drive seasonal electricity prices.
Issues related to seasonality and price volatility are fairly
uniform across our business segments.
Sources and Availability of Raw Materials
Our raw material requirements primarily include various forms of
fossil fuel, including oil, natural gas and coal. We obtain our
oil, natural gas and coal from multiple sources and availability
is generally not an issue, although localized shortages,
transportation availability and supplier financial stability
issues can and do occur. The prices of oil, natural gas and coal
are subject to macro- and micro-economic forces that can change
dramatically in both the short-term and the long-term. For
example, the price of natural gas was particularly volatile in
mid-January 2004 due to the extreme temperatures experienced in
the Northeast. Additionally, throughout 2004, oil prices were
extremely high due to the geo-political uncertainty in the
Middle East and increased demand by China and India. The total
cost of oil, natural gas and coal represented approximately
41.6%, 37.5%, 42.4% and 15.1% of our total operating costs and
expenses for the year ended December 31, 2004, the periods
December 6, 2003 through December 31, 2003 and
January 1, 2003 through December 5, 2003, and for the
year ended December 31, 2002, respectively. Issues related
to the sources and availability of raw materials are fairly
uniform across our business segments.
Employees
As of December 31, 2004, we had 2,644 employees,
approximately 555 of whom are employed directly by us and
approximately 2,089 of whom are employed by our wholly-owned
subsidiaries and affiliates. Approximately 1,011 employees are
covered by bargaining agreements. During 2004, we experienced no
significant labor stoppages or labor disputes at our facilities.
Federal Energy Regulation
Federal Energy Regulatory Commission. The FERC is an
independent agency that regulates the transmission and wholesale
sale of electricity in interstate commerce under the authority
of the Federal Power Act, or FPA. In addition, FERC determines
whether a generation facility qualifies for Exempt Wholesale
Generator, or EWG, status under Public Utility Holding Company
Act of 1935, or PUHCA. FERC also
17
determines whether a generation facility meets the ownership and
technical criteria of a Qualifying Facility, or QF, under Public
Utility Regulatory Policies Act of 1978, or PURPA.
Federal Power Act. The FPA gives FERC exclusive
rate-making jurisdiction over wholesale sales of electricity and
transmission of electricity in interstate commerce. FERC
regulates the owners of facilities used for the wholesale sale
of electricity or transmission in interstate commerce as
public utilities. The FPA also gives FERC
jurisdiction to review certain transactions and numerous other
activities of public utilities. Our QFs are exempt from the
FERCs FPA rate regulation.
Public utilities are required to obtain FERCs acceptance
of their rate schedules for wholesale sales of electricity.
Because our non-QF generating companies are selling electricity
in the wholesale market, such generating companies are deemed to
be public utilities for purposes of the FPA. FERC has granted
our generating and power marketing companies the authority to
sell electricity at market-based rates. Usually, the FERCs
orders that grant our generating and power marketing companies
market-based rate authority reserve the right to revoke or
revise that authority if FERC subsequently determines that we
can exercise market power in transmission or generation, create
barriers to entry or engage in abusive affiliate transactions.
If our generating and power marketing companies were to lose
their market-based rate authority, such companies may be
required to obtain FERCs acceptance of a cost-of-service
rate schedule and may become subject to the accounting,
record-keeping and reporting requirements that are imposed on
utilities with cost-based rate schedules.
In addition, the FPA gives FERC jurisdiction over a public
utilitys issuance of securities or assumption of
liabilities. However, FERC usually grants blanket approval for
future securities issuances or assumptions of liabilities to
entities with market-based rate authority. In the event that one
of our public utility generating companies were to lose its
market-based rate authority, our future securities issuances or
assumptions of liabilities could require prior approval of the
FERC.
The FPA also requires the FERCs prior approval for the
transfer of control over assets subject to FERCs
jurisdiction. FERC has jurisdiction over certain facilities used
to interconnect our generating projects to the transmission
grid, and over the filed rate schedules and tariffs of our EWG
generating projects and power marketing operating companies.
Thus, transferring these assets would require FERC approval.
In New England, New York, the Mid-Atlantic region, the Midwest
and California, FERC has approved independent system operators
or regional transmission organizations, or ISOs or RTOs. Most of
these ISOs or RTOs administer a wholesale centralized bid-based
spot market in their regions pursuant to tariffs approved by
FERC. These tariffs/market rules dictate how the day-ahead and
real-time markets operate and how entities with market-based
rates shall be compensated within those markets. The ISOs or
RTOs in these regions also control access to and the operation
of the transmission grid within their footprint. Outside of ISO
or RTO-controlled regions, we are allowed to sell energy at
market-based rates as determined by willing buyers and sellers.
Access to, pricing for, and operation of the transmission grid
in such regions is controlled by the local transmission owning
utility according to its Open Access Transmission Tariff
approved by FERC.
Public Utility Holding Company Act. PUHCA defines as a
holding company any entity that owns, controls or
has the power to vote 10% or more of the outstanding voting
securities of a public utility company. Unless
exempt, a holding company is required to register with the
Securities and Exchange Commission, or the SEC, and it and its
Subsidiaries (i.e., a company with 10% of its voting securities
held by the registered holding company) become subject to
extensive regulation. Registered holding companies under PUHCA
are required to limit their utility operations to a single,
integrated utility system and divest any other operations that
are not functionally related to the operation of the utility
system. In addition, a company that is a Subsidiary of a
registered holding company is subject to financial and
organizational regulation, including approval by the SEC of
certain financings and transactions. Domestic generating
facilities that qualify as QFs and/or that have obtained EWG
status from FERC are exempt from PUHCA. Each of our domestic
generating subsidiaries has been designated by FERC as an EWG or
is otherwise exempt from PUHCA because it is a QF under PURPA.
Because our generating subsidiaries have EWG or QF status, we do
not qualify as a holding company under PUHCA. We
will not be subject to regulation under PUHCA as long as
(a) we do not become a Subsidiary of another registered
holding company and (b) the projects in which we
18
have an interest (1) qualify as QFs under PURPA,
(2) obtain and maintain EWG status under Section 32 of
PUHCA, (3) obtain and maintain Foreign Utility Company, or
FUCO, status under Section 33 of PUHCA, or (4) are
subject to another exemption or waiver. If our projects were to
cease to be exempt and we were to become subject to SEC
regulation under PUHCA, it would be difficult for us to comply
with PUHCA absent a substantial corporate restructuring.
Regulatory Developments. FERC is attempting to spur
deregulation of the wholesale markets by requiring transmission
owners to provide open, non-discriminatory access to electricity
markets and the transmission grid. In April 1996, FERC issued
Orders 888 and 889, which required all public utilities to file
open access transmission tariffs that give wholesale
generators, as well as other wholesale sellers and buyers of
electricity, access to transmission facilities on a
non-discriminatory basis. This led to the formation of the ISOs
described above. On December 20, 1999, FERC issued Order
2000, encouraging the creation of RTOs. On July 31, 2002,
FERC issued its Notice of Proposed Rulemaking regarding Standard
Market Design, or SMD. All three orders were intended to
eliminate market discrimination by incumbent vertically
integrated utilities and to provide for open access to the
transmission grid. The status of FERCs RTO and SMD
initiatives is uncertain. On April 28, 2003, FERC issued a
white paper describing proposed changes to the proposed SMD
rulemaking that would, among other things, allow for more
regional differences. In addition, the Energy Bill pending
before Congress could restrict FERCs ability to implement
these initiatives.
The full effect of these changes on us is uncertain at this
time, because in many parts of the United States it has not been
determined how entities will attempt to comply with FERCs
initiatives. At this time, five ISOs have been approved and are
operational: ISO-NE in New England; the NYISO in New York; PJM
in the Mid-Atlantic region; the Midwest Independent System
Operation, or MISO, in the Central Midwest region; and the Cal
ISO in California. Three of these ISOs: PJM, MISO and ISO-NE,
have been found to also qualify as RTOs.
We are affected by rule/tariff changes that occur in the
existing ISOs and RTOs. The ISOs and RTOs that oversee most of
the wholesale power markets have in the past imposed, and may in
the future continue to impose, price limitations and other
mechanisms to address some of the volatility in these markets.
For example, ISO-NE, NYISO, PJM and Cal ISO have imposed price
limitations. These types of price limitations and other
regulatory mechanisms may adversely affect the profitability of
our generation facilities that sell energy into the wholesale
power markets. In addition, the regulatory and legislative
changes that have recently been enacted in a number of states in
an effort to promote competition are novel and untested in many
respects. These new approaches to the sale of electric power
have very short operating histories, and it is not yet clear how
they will operate in times of market stress or pressure, 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.
Environmental Matters
We are subject to a broad range of foreign, federal, state and
local environmental and safety laws and regulations in the
development, ownership, construction and operation of our
domestic and international projects. These laws and regulations
impose requirements on discharges of substances to the air,
water and land, the handling, storage and disposal of, and
exposure to, hazardous substances and wastes and the cleanup of
properties affected by pollutants. These laws and regulations
generally require that we obtain governmental permits and
approvals before construction or operation of a power plant
commences, and after completion, that our facilities operate in
compliance with those permits and applicable legal requirements.
We could also be held responsible under these laws for the
cleanup of pollutants released at our facilities or at off-site
locations where we may have sent wastes, even if the release or
off-site disposal was conducted in compliance with the law.
Environmental laws have become increasingly stringent over time,
particularly the regulation of air emissions from our plants.
Such laws generally require regular capital expenditures for
power plant upgrades, modifications and the installation of
certain pollution control equipment. In addition, regulatory
compliance for the construction of new facilities is a costly
and time-consuming process. Intricate and rapidly changing
19
environmental regulations may require major capital expenditures
for permitting and create a risk of expensive delays or material
impairment of project value if projects cannot function as
planned due to changing regulatory requirements or local
opposition. In all cases, we seek to reflect environmental
impacts and mitigants in every business decision we make, and by
doing so, strive to improve our competitive advantage by meeting
or exceeding environmental and safety requirements in the
management and operation of our assets.
It is not possible at this time to determine when or to what
extent additional facilities or modifications to existing or
planned facilities will be required as a result of potential
changes to environmental and safety laws and regulations,
regulatory interpretations or enforcement policies. In general,
future laws and regulations are expected to require the addition
of pollution control equipment or the imposition of certain
restrictions on our operations. We expect that future liability
under, or compliance with, environmental and safety requirements
could have a material effect on our operations or competitive
position.
|
|
|
Domestic Environmental Regulatory Matters |
Power projects are subject to stringent environmental and safety
protection and land use requirements in the U.S. These laws
and regulations generally require lengthy and complex processes
to obtain licenses, permits and approvals from federal, state
and local agencies. If such laws and regulations become more
stringent and our facilities are not exempted from coverage, we
could be required to make extensive modifications to further
reduce potential environmental impacts.
We establish accruals where it is probable that we will incur
environmental costs under applicable law or contract and it is
possible to reasonably estimate those costs. We adjust the
accruals when new remediation or other environmental liability
responsibilities are discovered and probable costs become
estimable, or when current liability estimates are adjusted to
reflect new information or a change in the law.
|
|
|
U.S. Federal Environmental Initiatives |
Several federal regulatory and legislative initiatives to
further limit and control pollutant emissions from fossil
fuel-fired combustion units are currently underway. Although
neither the exact impact of these initiatives nor their final
form is known at this time, all of our power plants will likely
be affected in some manner by the expected changes in federal
environmental laws and regulations. In Congress, legislation has
been proposed that would impose annual caps on U.S. power
plant emissions of nitrogen oxides, or NOX, sulfur
dioxide, or SO2, mercury and, in some instances,
carbon dioxide, or CO2.
In December 2003, the U.S. Environmental Protection Agency,
or USEPA, proposed rules governing mercury emissions from power
plants. On March 15, 2005, USEPA issued the Clean Air
Mercury Rule, or CAMR, to permanently cap and reduce mercury
emissions from coal-fired power plants. CAMR imposes limits on
mercury emissions from new and existing coal-fired plants and
creates a market-based cap-and-trade program that will reduce
nationwide utility emissions of mercury in two phases (2010 and
2018), to achieve an ultimate reduction level of approximately
70%. The cap-and-trade program for mercury is expected to be
structured like the federal Acid Rain Program, allowing
generators to decide in each particular case the most effective
means for their compliance (i.e., install control technologies
and/or purchase emissions allowances in the market). As there
has been significant debate on whether USEPA has authority to
regulate mercury emissions through the proposed cap-and-trade
mechanism (as opposed to a command-and-control requirement to
install maximum achievable control technology, or
MACT, on a unit basis), it is reasonable to expect that the new
rule may be subject to legal challenge. Each of our coal-fired
electric power plants will be subject to mercury regulation.
However, since the final rule has yet to be implemented by
individual states pursuant to state-specific legislation, it is
not possible to identify in detail how the final mercury rules
will affect our operations located in those states.
Nevertheless, we continue to actively review emerging mercury
monitoring and mitigation technologies and assess appropriate
options for the Company in future.
The USEPA has also proposed MACT standards for nickel from
oil-fired units. The proposed nickel rule would accept the use
of an electrostatic precipitator, or ESP, as the appropriate
MACT control, with an implementation date of three years after
rule promulgation. Eight of the Companys oil-fired
generating units are not equipped with an ESP: Middletown
Unit 4, Montville Unit 6, Vienna and Encina Units 1-5.
While
20
USEPAs final decision regarding nickel emissions from
oil-fired units is still pending, USEPA is reconsidering
whether, based on the scientific data, any new controls on
nickel emissions from oil-fired generators are in fact needed.
Given the current situation, we do not consider any material
expenditure for nickel emission mitigation by the Company to be
probable at this time.
The USEPA has finalized federal rules governing ozone season
NOX emissions across the eastern U.S. Current
ozone season rules are being implemented within two programs.
Restrictions exist in the Ozone Transport Region, or OTR,
through annual ozone seasons (May September) and all
of the Companys generating units located in the OTR are
included in this program (which was effective in 2003).
NOX allowance allocations are based on an equivalent
emissions rate of 0.15 lbs/MMBtu, with each OTR state managing
its own NOX Budget Program and specific rules for
allowance distribution. The second program, in effect from May
2004, is similar to the OTR program, and extends to states
within the Ozone Transport Assessment Group, or OTAG, region.
This restricts 2004 and subsequent ozone season NOX
emissions in most states east of the Mississippi River. These
rules essentially require one NOX allowance to be
held for each ton of NOX emitted from fossil
fuel-fired stationary boilers, combustion turbines, or combined
cycle systems. NOX allowance allocation is similar to
the OTR and each of the Companys facilities that is
subject to these rules has been allocated NOX
emissions allowances. While the portfolio total is currently
sufficient to cover operations at these facilities, if at any
point allowances are insufficient for the anticipated operation
of each of these facilities, the Company must purchase
NOX allowances. Any need to purchase additional
NOX allowances could have a material adverse effect
on our operations.
On March 10, 2005, the USEPA announced the Clean Air
Interstate Rule, or CAIR, originally proposed in January 2004.
The new rule applies to 28 eastern states and the District of
Columbia and caps SO2 and NOX emissions
from power plants in two phases: 2010 and 2015 for
SO2 and 2009 and 2015 for NOX. CAIR will
reduce such emissions in aggregate by just over 70% in the case
of SO2 and just under 70% in the case of
NOX and will apply to certain of the Companys
power plants located in New York, Massachusetts, Connecticut,
Delaware (NOX only) and Louisiana. States must
achieve the required emission reductions using one of two
compliance options: (a) meet the states emission
budget by requiring power plants to participate in a
USEPA-administered interstate cap-and-trade system; or
(b) meet an individual state emissions budget through
measures selected by individual states. While the Companys
current business plans include initiatives (for example, the
conversion of Huntley and Dunkirk to burn low sulfur coal) in
part to address the new emissions caps, until the final rule as
issued by USEPA is actually implemented by specific state
legislation, it is not possible to identify with greater
specificity the effect of CAIR on the Company.
In 2004, USEPA reproposed the 1999 Regional Haze Rule, designed
to improve air quality in national parks and wilderness areas.
This rule requires regional haze controls (by targeting
SO2 and NOX emissions from sources
including power plants) through the installation of Best
Available Retrofit Technology, or BART, for certain sources put
into operation between 1962 and 1977. The so-called BART rule is
expected to be finalized in April 2005, with states required to
submit their implementation plans by 2008. It is likely that the
BART rule, if implemented, will affect many of the
Companys facilities. However, it is also expected that
required actions taken for compliance with CAIR (when it is
fully implemented) and certain state initiatives will also
achieve compliance with the BART rule as currently proposed.
During the first quarter of 2002, USEPA proposed new rules
governing cooling water intake structures at existing power
facilities (the Phase II 316(b) Rules). These rules were
finalized in February 2004. The Phase II 316(b) Rules
specify certain location, design, construction, and capacity
standards for cooling water intake structures at existing power
plants using the largest amounts of cooling water. These rules
will require implementation of the Best Technology Available, or
BTA, for minimizing adverse environmental impacts unless a
facility shows that such standards would result in very high
costs or little environmental benefit. The
Phase II 316(b) Rules require the Companys
facilities that withdraw water in amounts greater than
50 million gallons per day to submit certain surveys,
plans, operational measures, and restoration measures (with
wastewater permit applications or renewal applications) that
would minimize certain adverse environmental impacts of
impingement or entrainment. The Phase II 316(b) Rules
affect a number of the Companys plants, specifically those
with once-through cooling systems. Compliance options include
the addition of control technology, modified operations,
restoration, or a combination of these, and are subject to a
21
comparative cost and cost/benefit justification. While we have
conducted a number of the requisite studies (and in one case
already budgeted to install BTA), until all the needed studies
throughout our fleet have been completed and consultations on
the results have occurred with USEPA (or its delegated state or
regional agencies), it is not possible to estimate the capital
costs that will be required for compliance with the
Phase II 316(b) Rules.
Federal legislation, such as the Clear Skies Act, or Clear
Skies, has been proposed that would impose annual caps on
U.S. power plant emissions of NOX,
SO2, mercury, and, in some instances, CO2.
Under Clear Skies, these caps would go into effect in two
phases: 2010 and 2016 for SO2; 2008 and 2016 for
NOX; and 2010 and 2016 for mercury, with the proposed
final reduction level in 2016 for SO2, NOX
and mercury being approximately 70%. Clear Skies was first
proposed in 2002 and while the bill stalled in Senate Committee
on March 9, 2005, the Bush Administration continues to
support, and work with Congress to achieve, passage of Clear
Skies in 2005. Clear Skies overlaps to a significant degree with
the USEPA CAIR and CAMR, and would modify or supersede those
rules if enacted as federal legislation.
While the Bush Administration has publicly stated that it does
not support mandatory national restrictions on greenhouse gas,
or GHG, emissions, it supports a number of initiatives with
respect to voluntary reductions of carbon intensity
(a measure of carbon emissions per unit of GDP). A number of
members of the Senate and Congress continue to call for federal
GHG regulation and to propose legislation. Additionally, there
have been several petitions from states and other parties to
compel USEPA to regulate GHGs under the Clean Air Act, or CAA.
On September 3, 2003, USEPA denied a petition by
Massachusetts, Maine and Connecticut to require USEPA to
establish a National Ambient Air Quality Standard, or NAAQS, for
CO2. Since that time, twelve states and other
territorial entities have filed suit against USEPA asking the
Court to address whether USEPA has an existing obligation to
regulate GHGs under the CAA. Oral arguments in the case are
scheduled for April, 2005. Additionally, eight states and the
City of New York filed suit on July 21, 2004 against
American Electric Power Company, Southern Company, Tennessee
Valley Authority, Xcel Energy, Inc. and Cinergy Corporation,
alleged to be the nations five largest emitters of GHGs
and all of which are owners of electric generation. On the same
day, a similar complaint was filed in the same court against the
same defendants by the Natural Resources Defense Council on
behalf of certain special interest groups. In both cases, the
complaint seeks an injunction against each defendant forcing it
to abate its contribution to the global warming
nuisance by requiring it to cap its CO2
emissions and then reduce them by a specified percentage each
year for at least a decade. The outcome of this litigation and
proposed legislation cannot be predicted. The Companys
compliance costs with any mandated GHG reductions in the future
could be material.
Other federal initiatives that could affect the Companys
generating facilities with respect to fine particulate matter
(PM2.5), and ozone are underway, with compliance implementation
timeframes expected from 2009.
|
|
|
Regional U.S. Regulatory Initiatives |
Northeast Region. Connecticut rules on air regulation
require certain reductions in emissions of SO2 (in
two steps: 2002 and 2003). The Companys Connecticut plants
have operated in compliance with both phases of the rule. The
Company also complies with Connecticuts NOX
emission rules (restricting the average, non-ozone season
NOX emission rate to 0.15 lbs/ MMBtu), through
selective firing of natural gas, use of selective non-catalytic
reduction, or SNCR, technology presently installed at the
Norwalk Harbor and Middletown Power Stations, improved
combustion controls, use of emission reduction credits, and
purchase of allowances. In 2002, the Connecticut legislature
passed a law further tightening air emission standards by
eliminating emissions credit purchases after January 1,
2005 as a means of meeting Department of Environmental
Protection, or DEP, regulatory standards for SO2
emissions from older power plants. The Company plans to comply
with the legislation through the use of lower sulfur oil.
Massachusetts air regulations prescribe schedules under which
six existing coal-fired power plants in-state are required to
meet stringent emission limits for NOX,
SO2, mercury, and CO2. The state has
reserved the issue of control of carbon monoxide and particulate
matter emissions for future consideration. Consistent
22
with a permit to install natural gas reburn technology to meet
the NOX and SO2 limits received in early
2003 from the Massachusetts Department of Environmental
Protection, or MADEP, the Company has implemented that
technology at Somerset station. On June 4, 2004, MADEP
issued its regulation on the control of mercury emissions. The
effect of this regulation is that starting October 1, 2006,
Somerset will be capped at 13.1 lbs/year of mercury and as
of January 1, 2008, Somerset must achieve a reduction in
its mercury inlet-to-outlet concentration of 85%. The Company
plans to meet the requirements through the management of its
fuels, and the use of early and off-site reduction credits.
Additionally, the Company has entered into an agreement with
MADEP to retire or repower the Somerset station by the end of
2009. The Company is currently considering its options with
respect to how it will address MADEPs CO2
emission standards; part of this analysis depends upon the
outcome of the model rule process currently underway for the
Regional Greenhouse Gas Initiative, or RGGI, discussed below.
New York State Department of Environmental Conservation, or
NYSDEC, rules reducing allowable SO2 and
NOX emissions from large, fossil-fuel-fired
combustion units in New York State became effective October
2004. The reductions are achieved through an allowance-based
cap-and-trade program that affects only New York sources.
Specifically, New York electric generators have to reduce
SO2 emissions to 25% below the levels allowed in the
federal Acid Rain Program starting January 2005 and 50% below
the levels allowed by federal Acid Rain Program starting in
January 2008. Under this Acid Rain Deposition Program, or ADRP,
electric generators also have to meet the ozone season
NOX emissions limit of 0.15 lbs/MMBtu
year-round, starting October 2004. The Companys strategy
for complying with the ADRP is to generate early reductions of
SO2 and NOX emissions associated with fuel
switching and use such reductions to extend the timeframe for
implementing technological controls, which could ultimately
include the addition of flue gas desulfurization, or FGD, and
selective catalytic reduction, or SCR, equipment. On
January 11, 2005, the Company reached an agreement with the
State of New York and the NYSDEC in connection with voluntary
emissions reductions at the Huntley and Dunkirk facilities, as
discussed in Item 3 Legal Proceedings. The
Company does not anticipate that any material capital
expenditures, beyond those already planned, will be required for
our Huntley and Dunkirk plants to meet the current compliance
standards in New York (including under the recent settlement)
through the end of the decade.
While no rules affecting the Companys existing facilities
have been formally proposed, Delaware has foreshadowed the
development of MACT-comparable standards for SO2,
NOX and mercury. Delaware is considering such
rule-making based on recent determinations that portions of the
state are in non-attainment for NAAQS for fine particulates, or
PM2.5, and all of the state is in non-attainment for the NAAQS
for 8-Hour Ozone. The Company is evaluating voluntary emissions
reductions opportunities which may include blending low sulfur
western coals. While Delaware has not yet issued a proposed
rule, the Company is currently participating as a stakeholder in
such policy-making efforts along with the Governors Energy
Task Force, legislators, the PSC and the Delaware Department of
Natural Resources and Environmental Control, or DNREC. Further,
Delaware has begun rule-making in regard to developing emissions
standards for small combustion turbines and distributive
generation sources and implementing USEPAs New Source
Review, or NSR, revisions. In addition to air emission
initiatives, Delaware has also established Total Maximum Daily
Loading, or TMDL, standards for temperature in its watersheds
and intends to establish one for mercury as well. The Company
continues to participate in these developments and has filed
comments with the relevant agencies.
In July 2003, nine northeastern states announced a regional
initiative to establish a cap-and-trade GHG program for electric
generators, referred to as the Regional Greenhouse Gas
Initiative, or RGGI. The model RGGI rule is to be announced in
2005, with an estimate of two to three years for participating
states to finalize implementing regulations. A proposed level of
the RGGI cap has not been determined at this time. If
implemented, our plants in New York, Delaware, Massachusetts,
and Connecticut may be affected and our compliance costs with
any mandated GHG reductions in the future could be material.
The Ozone Transport Commission, or OTC, was established by
Congress and governs ozone and the NOX budget program
in certain eastern states, including Massachusetts, Connecticut,
New York and Delaware. In January 2005, the OTC stepped up its
efforts to develop a multi-pollutant regime (SO2,
NOX, mercury and CO2) that is expected to
be completed by mid-2006 (with individual state implementation to
23
follow), particularly if Clear Skies does not eventuate in 2005
or CAIR is perceived to be lenient. The Company continues to be
engaged in the OTC stakeholder process. While it is not possible
to predict the outcome of this regional legislative effort, to
the extent that the OTC seeks to effect emissions requirements
that are more stringent than currently proposed or existing
regimes (including the recently reached New York settlement),
the Company could be materially impacted.
South Central Region. The Louisiana Department of
Environmental Quality, or LADEQ, has promulgated State
Implementation Plan revisions to bring the Baton Rouge ozone
non-attainment area into compliance with applicable NAAQS. The
Company participated in development of the revisions, which
require the reduction of NOX emissions at the
gas-fired Big Cajun I Power Station and coal-fired Big
Cajun II Power Station to 0.1 lbs/ MMBtu and 0.21 lbs/
MMBtu NOX, respectively (both based on heat input).
This revision of the Louisiana air rules would constitute a
change-in-law covered by agreement between Louisiana Generating
LLC and the electric cooperatives (power offtakers) allowing the
costs of added combustion controls to be passed through to the
cooperatives. The capital cost of combustion controls required
at the Big Cajun II Generating Station to meet the
states NOX regulations will total about
$10.0 million for Unit 1 and will be undertaken in
2005. Units 2 and 3 have already made such changes.
In the 1990s, the USEPA commenced an industry-wide investigation
of coal-fired electric generators to determine compliance with
environmental requirements under the CAA associated with
repairs, maintenance, modifications and operational changes made
to the facilities over the years. USEPA focused on whether the
changes were subject to NSR regulations which require companies
to obtain permits before making major modifications to their
facilities and if deemed necessary, install control equipment to
reduce air emissions. As a result of this ongoing investigation
USEPA and several states have filed suits against a number of
coal-fired power plants in mid-western and southern states
alleging violations of the CAA NSR requirements. The
U.S. District Court for the Southern District of Ohio
issued a decision in August 2003 finding Ohio Edison Company in
violation of the NSR provisions of the CAA. In United
States v. Duke Energy Company, however, the
U.S. District Court for the Middle District of North
Carolina rejected the USEPAs interpretation, concluding
that the exclusion for routine maintenance should be defined
relative to what is routine for the particular industry, not
what is routine for the particular unit at issue. On
October 27, 2003, the USEPAs NSR rule on routine
maintenance was published in the Federal Register. The new
regulations, which are not retroactive, would establish an
equipment replacement cost threshold of 20% for determining when
major NSR requirements are triggered. An appeal opposing the
rule was filed with the U.S. Court of Appeals. The
effective date of the rule has been delayed pending review. In
June 2004, the USEPA filed an appeal with the U.S. Court of
Appeals for the Fourth Circuit from the decision in the Duke
Energy case which is currently being heard with a ruling
expected by summer 2005.
On January 27, 2004, Louisiana Generating, LLC and Big
Cajun II received a request for information under
Section 114 of the CAA from USEPA seeking information
primarily related to physical changes made at Big Cajun II.
Throughout 2004 Louisiana Generating, LLC and Big Cajun II
submitted several responses to the USEPAs follow-up
requests. On February 15, 2005, we received a Notice of
Violation, or NOV, alleging violations of the NSR provisions of
the CAA at Big Cajun 2 Units 1 and 2 from 1998 through the NOV
date. Given the preliminary stage of this NOV process, the
Company cannot predict the outcome of this matter at this time,
but it is actively engaged with USEPA to address these issues.
West Coast Region. The El Segundo Generating Station is
regulated by the South Coast Air Quality Management District, or
SCAQMD. Before its retirement as of January 1, 2005, the
Long Beach Generating Station was also regulated by SCAQMD.
SCAQMD approved amendments to its Regional Clean Air Incentives
Market, or RECLAIM, NOX regulations on
January 7, 2005. RECLAIM is a regional emission-trading
program targeting NOX reductions to achieve state and
federal ambient air quality standards for ozone. Among other
changes, the amendments reduce the NOX RECLAIM
Trading Credit, or RTC, holdings of El Segundo Power, LLC
and Long Beach Generation LLC facilities by certain amounts.
Notwithstanding these amendments, retained RTCs are expected to
be sufficient to operate El Segundo Units 3 and 4 as
high as 100% capacity factor.
24
|
|
|
Domestic Site Remediation Matters |
Under certain federal, state and local environmental laws and
regulations, a current or previous owner or operator of any
facility, including an electric generating facility, may be
required to investigate and remediate releases or threatened
releases of hazardous or toxic substances or petroleum products
at the facility. We may also be held liable to a governmental
entity or to third parties for property damage; personal injury
and investigation and remediation costs incurred by the party in
connection with hazardous material releases or threatened
releases. These laws, including the Comprehensive Environmental
Response, Compensation and Liability Act of 1980, or CERCLA, as
amended by the Superfund Amendments and Reauthorization Act of
1986, or SARA, impose liability without regard to whether the
owner knew of or caused the presence of the hazardous
substances, and courts have interpreted liability under such
laws to be strict (without fault), and joint and several. The
cost of investigation, remediation or removal of any hazardous
or toxic substances or petroleum products could be substantial.
Although we have been involved in on-site contamination matters,
to date, we have not been named as a potentially responsible
party with respect to any off-site waste disposal matter.
Northeast Region. Ash is produced as a by-product of coal
combustion at the Dunkirk, Huntley, Indian River and Somerset
Generating Stations. The Company attempts to direct its coal ash
to beneficial uses. Even so, significant amounts of ash are
landfilled. At Dunkirk and Huntley ash is disposed of at
landfills owned and operated by the Company and it maintains
financial assurance to cover costs associated with landfill
closure, post-closure care and monitoring activities. On
April 30, 2003, the Company funded a trust in the amount of
approximately $5.9 million to provide such financial
assurance. The Company is also responsible for the costs
associated with closure, post-closure care and monitoring of the
ash landfill owned and operated by the Company at the Indian
River facility. Financial assurance to provide for closure and
post-closure costs at that location is currently maintained by a
trust fund collateralized in the amount of approximately
$6.7 million. The Company seeks to commence a project to
utilize a quarter of its ash production in 2005 for beneficial
local use. Additionally, the Company is working with DNREC to
modify current landfill slope design to gain significant
additional capacity at the existing landfill, thus delaying
pending closure and expansion of the landfill. The Company must
also maintain financial assurance for closing interim status
Resource Conservation and Recovery Act, or RCRA, facilities at
the Devon, Middletown, Montville and Norwalk Harbor Generating
Stations. On April 30, 2003, the Company funded a trust in
the amount of $1.5 million to provide RCRA financial
assurance.
The Company inherited historical clean-up liabilities when it
acquired the Somerset, Devon, Middletown, Montville, Norwalk
Harbor, Arthur Kill and Astoria Generating Stations. During
installation of a sound wall at Somerset Station in 2003, oil
contaminated soil was encountered. The Company has delineated
the general extent of contamination, determined it to be
minimal, and has placed an activity use limitation on that
section of the property. Site contamination liabilities arising
under the Connecticut Transfer Act at the Devon, Middletown,
Montville and Norwalk Harbor Stations have been identified. The
Company has proposed a remedial action plan to be implemented
over the next two to eight years (depending on the station) to
address historical coal ash contamination at the facilities. The
total estimated cost of this remedial action plan is not
expected to exceed $1.5 million. Remedial obligations at
the Arthur Kill generating station have been established in
discussions between the Company and the NYSDEC and are estimated
to cost between $1 million and $2 million. Remedial
investigations continue at the Astoria generating station with
long-term clean-up liability expected to be within the range of
$2.5 million to $4.3 million. While installing
groundwater-monitoring wells on the Astoria site to track
remediation of a historical fuel oil spill, the drilling
contractor encountered deposits of coal tar in two borings. The
Company reported the coal tar discovery to the NYSDEC in 2003
and delineated the extent of this contamination. The Company may
also be required to remediate the coal tar contamination and/or
record a deed restriction on the property if significant
contamination is to remain in place.
The Company has been put on notice that the prior owner of the
Huntley, Dunkirk and Oswego plants is seeking indemnification
and defense in connection with several lawsuits alleging
liability for damages to persons allegedly exposed to
asbestos-containing materials at the plants. The prior owner
alleges that the Company is liable by the terms of the Asset
Sales Agreements pursuant to which the Company acquired the
25
plants, which allegations are disputed. To date, the prior owner
has not filed suit against the Company with respect to its claim
for indemnification with respect to these cases.
South Central Region. Liabilities associated with
closure, post-closure care and monitoring of the ash ponds owned
and operated at the Big Cajun II Generating Station are
addressed through the use of a trust fund maintained by the
Company. The value of the trust fund is approximately
$5.0 million and the Company is making annual payments to
the fund in the amount of approximately $116,000.
West Coast Region. The Asset Purchase Agreements for the
Long Beach, El Segundo, Encina, and San Diego gas
turbine generating facilities provide that Southern California
Edison, or SCE, and San Diego Gas & Electric, or
SDG&E, retain liability, and indemnify the Company, for
existing soil and groundwater contamination that exceeds
remedial thresholds in place at the time of closing. The Company
and its business partner conducted Phase I and
Phase II Environmental Site Assessments at each of these
sites for purposes of identifying such existing contamination
and provided the results to the sellers. SCE and SDG&E have
agreed to address contamination identified by these studies and
are undertaking corrective action at the Encina and
San Diego gas turbine generating sites. Spills and releases
of various substances have occurred at these sites since the
Company established the historical baseline, all of which have
been, or will be, completely remediated. An oil leak in 2002
from underground piping at the El Segundo Generating
Station contaminated soils adjacent to and underneath the
Unit 1 and 2 powerhouse. The Company excavated and disposed
of contaminated soils that could be removed in accordance with
existing laws. Following the Companys formal request, the
Los Angeles Regional Water Quality Control Board, or LARWQCB,
will allow contaminated soils to remain underneath the building
foundation until the building is demolished.
A diesel fuel spill to on-site surface containment occurred at
the Cabrillo Power II LLC Kearny Combustion Turbine
facility (San Diego) in February 2003. Emergency response
and subsequent remediation activities were completed.
Confirmation sampling for the site was completed in 2004 and
submitted to the San Diego County Department of
Environmental Health. Three San Diego Combustion Turbine
facilities, formerly operating pursuant to land leases with the
U.S. Navy, are currently being decommissioned with
equipment being removed from the sites and remediation
activities occurring where necessary. All remedial activities
are being completed pursuant to the requirements of the
U.S. Navy and the San Diego County Department of
Environmental Health. Remediation activities were completed in
2004 at the Naval Training Center and North Island facilities.
At the 32nd Street Naval Station facility, additional
contamination delineation is necessary and additional
unquantified remediation in inaccessible areas may be required
in the future.
|
|
|
International Environmental Matters |
Most of the foreign countries in which we own or may acquire or
develop independent power projects have environmental and safety
laws or regulations relating to the ownership or operation of
electric power generation facilities. These laws and
regulations, like in the U.S., are constantly evolving, and have
a significant impact on international wholesale power producers.
In particular, our international power generation facilities
will likely be affected by emissions limitations and operational
requirements imposed by the Kyoto Protocol, which is an
international treaty related to greenhouse gas emissions which
entered into force on February 16, 2005, and country-based
restrictions pertaining to global climate change concerns.
We retain appropriate advisors in foreign countries and seek to
design our international asset management strategy to comply
with each countrys environmental and safety laws and
regulations. There can be no assurance that changes in such laws
or regulations will not adversely effect our international
operations.
Australia. With respect to Australia, climate change is
considered a long-term issue (e.g. 2010 and beyond) and the
Australian governments response to date has included a
number of initiatives, all of which have had no impact or
minimal impact on the Companys operations. The Australian
government has stated that Australia will achieve its Kyoto
Protocol target of 8% below 1990 greenhouse gas emission levels
for the 2008 to 2012 reporting period but that Australia will
not ratify the Kyoto Protocol. Each Australian state government
is considering implementing a number of climate change
initiatives that will vary considerably state to state.
26
The asset purchase documentation for the NRG Flinders assets in
South Australia provides protections to buyer with respect to
historical soil and ground water contamination. Although NRG
Flinders has some ongoing obligations with respect to historic
site contamination management at Augusta Power Station,
Clause 5 of the Environment Compliance Agreement between
the South Australian Minister for Environment and Heritage and
NRG Flinders dated September 20, 2000, referred to as the
EC Agreement, removed any obligation for clean-up or
remediation of existing contamination.
While new legislation on contamination is being introduced in
South Australia, with particular emphasis on groundwater
contamination (regardless of the existing quality of the
groundwater), the Company considers it unlikely that any of the
proposed amendments will materially negatively impact NRG
Flinders operations. Specifically, despite the proposed
Soil Contamination Amendments to the Environment
Protection Act 1993, Flinders will not be obligated to
take any action to clean up or remediate any historical
groundwater contamination caused by disposal of ash as a
seawater slurry to the ash ponds by virtue of the
EC Agreement (referenced above).
NRG Flinders disposes of ash to slurry ponds at Port Augusta in
South Australia. At the end of life of the power station, NRG
Flinders has an obligation to remediate these ponds in
accordance with a plan accepted by the South Australian EPA and
confirmed in the EC Agreement. The estimated cost of
remediation according to the Plan is AUD 1.7 million. There
is no timeline associated with the obligation but the
EC Agreement extends to 2025. Under these arrangements,
required remediation relates to surface remediation and does not
entail any groundwater remediation.
A number of other changes in South Australian legislation are
proposed; for example a new Water Quality Policy, which may have
some minor implications for the Companys operations (e.g.,
especially mine operations). The Company continues to be
involved in the legislative stakeholder process and does not
expect the proposed amendments to have a materially adverse
effect on its assets or operations.
MIBRAG/ Schkopau, Germany. The Companys facilities
in Germany are likely to be impacted by evolving emissions
limitations imposed as a result of the ratification of the Kyoto
Protocol. The Company expects that CO2 emissions
trading will begin in Germany in 2005. Allocations of allowances
have now been made by the government, but are being challenged
by most recipients. Irrespective of the final allocation
amounts, the Company does not expect the CO2 trading
program to be a material constraint on its business in Germany.
In addition, changes to the German Emission Control Directive
will result in lower NOX emission limits for plants
firing conventional fuels (Section 13 of the Directive) and
co-firing waste products (Section 17 of the Directive). The
new regulations will require the Mumsdorf and Deuben Power
stations to install additional controls to reduce NOX
emissions in 2006.
The European Unions Groundwater Directive and Mine
Wastewater Management Directive are in the rule-making stage
with the final outcome still under debate. Given the uncertainty
regarding the possible outcome of the debate on these
directives, we cannot quantify at this time the possible effect
such requirements would have on our future coal mining
operations in Germany.
A new law specifically dealing with the relocation of residents
of Heuersdorf in the path of the mining plan was enacted by the
legislature of Saxony in 2004 and there are numerous potential
court challenges still outstanding in this process. We cannot
predict the outcome of these actions at this time. MIBRAG
continues its political and legal work in an effort to obtain a
favorable resolution.
The supply contracts under which MIBRAG mines lignite from the
Profen mine expire on December 31, 2021. The contracts
under which MIBRAG mines lignite from the Schleenhain mine
expire in 2041. At the end of each mines productive
lifetime, MIBRAG will be required to reclaim certain areas.
MIBRAG accrues for these eventual expenses and estimates the
cost of the final reclamation to approach
175 million
in the instance of the Schleenhain mine and
132 million
for Profen.
Enfield Energy Centre Limited, United Kingdom. The first
phase of Europes CO2 emissions trading scheme,
or EU ETS, beginning in 2005, also affects our assets in the
U.K. Participants will be required to surrender emissions
allowances equal to the amount of CO2 they have
emitted in each year of the scheme. Allowances will be tradable
and a market has already developed in this product. For the U.K.
it is not yet
27
possible to quantify the possible effect of this scheme on our
operations because final installation level details for the
scheme have yet to be released. The second phase of the program
will run between 2008 and 2012 and may be extended to cover
other GHGs. Additionally, the integrated pollution prevention
and control directive, or IPPC, which sets out a framework for
the environmental regulation of industrial activities, will be
implemented in March 2006. As Enfield Energy Centre is a latest
design combined cycle gas turbine, implementing this directive
is not expected to require any major changes or expenditures.
Risks Related to NRG Energy, Inc.
|
|
|
Future decreases in gas prices may adversely impact our
financial performance. |
Certain of our facilities, particularly our coal generation
assets, are currently benefiting from higher electricity prices
in their respective markets as a result of high gas prices
compared to historical levels. Gas-fired facilities set the
marginal cost of energy in most of our domestic markets. A
decrease in gas prices may lead to a corresponding decrease in
electricity prices in these markets, which could materially and
adversely impact our financial performance.
|
|
|
Our revenues are unpredictable because most of our power
generation facilities operate, wholly or partially, without
long-term power purchase agreements. Further, because wholesale
power prices are subject to significant volatility, the revenues
that we generate are subject to significant fluctuations. |
Most of our facilities operate as merchant
facilities without long-term agreements. An oversupply of
generating capacity has depressed wholesale power prices in many
regions of the country and increased the difficulty of obtaining
long-term contracts. Without the benefit of long-term power
purchase agreements, we cannot be sure that we will be able to
sell any or all of the power generated by our facilities at
commercially attractive rates or that our facilities will be
able to operate profitably. This could lead to future
impairments of our property, plant and equipment or to the
closing of certain of our facilities resulting in economic
losses and liabilities.
We sell all or a portion of the energy, capacity and other
products from many of our facilities to wholesale power markets,
including energy markets operated by independent system
operators, or ISOs, or regional transmission organizations, or
RTOs. 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 ISOs or RTOs and state and federal regulators. In
addition, unlike most other commodities, electric power can only
be stored on a very limited basis and generally must be produced
concurrently with its use. As a result, the wholesale power
markets are subject to significant and unpredictable price
fluctuations over relatively short periods.
|
|
|
Competition in wholesale power markets may have a material
adverse effect on our results of operations and cash
flows. |
We have numerous competitors in all aspects of our business, and
additional competitors may enter the industry. Our wholesale
energy operations compete with other providers of electric
energy in the procurement of fuel and transportation services,
and the sale of capacity, energy and related products. In order
to successfully compete, we seek to aggregate fuel supplies at
competitive prices from different sources and locations and to
efficiently utilize transportation services from third-party
pipelines, railways and other fuel transporters and transmission
services from electric utilities.
We also compete against other energy merchants on the basis of
our relative skills, financial position and access to credit
sources. Energy customers, wholesale energy suppliers and
transporters often seek financial guarantees and other
assurances that their energy contracts will be satisfied. As a
result, our business is constrained by our liquidity, our access
to credit and the reduction in market liquidity. Other companies
with which we compete may have greater resources in these areas.
Other factors may contribute to increased competition in
wholesale power markets. The future of the wholesale power
generation industry is unpredictable, but may include
consolidation within the industry, the
28
sale, bankruptcy or liquidation of certain competitors, the
re-regulation of certain markets or a long-term reduction in new
investment into the industry. New capital and competitors have
entered the industry in the last three years, including
financial investors who perceive that asset values may have
bottomed out at levels below their true replacement value. A
number of generation facilities in the United States are now in
the hands of lenders. Under any scenario, we anticipate that we
will continue to face competition from numerous companies in the
industry. We anticipate that FERC will continue its efforts to
facilitate the competitive energy marketplace throughout the
country on several fronts but particularly by encouraging
utilities to voluntarily participate in RTOs or ISOs.
Many companies in the regulated utility industry, with which the
wholesale power industry is closely linked, are also
restructuring or reviewing their strategies. Several of those
companies are discontinuing their unregulated activities,
seeking to divest their unregulated subsidiaries or attempting
to have their regulated subsidiaries acquire assets out of their
or other companies unregulated subsidiaries. This may lead
to increased competition between the regulated utilities and the
unregulated power producers within certain markets.
|
|
|
A substantial portion of our historical cash flow has been
derived from a CDWR contract in California and we do not expect
to be able to enter into comparable agreements beyond
2004. |
In March 2001, certain affiliates of West Coast Power entered
into a contract with the California Department of Water
Resources, or CDWR, pursuant to which the affiliates agreed to
sell up to 2,300 MW from January 1, 2002 through
December 31, 2004, any of which may be resold by the CDWR
to utilities such as Southern California Edison Company,
PG&E Corp. and San Diego Gas and Electric Company. This
contract contributed $108.6 million for the year ended
December 31, 2004 and $102.6 million for the full year
2003 to our reported equity earnings in West Coast Power, which
were decreased by the non-cash impact of fresh start accounting
of $115.8 million for the year ended December 31, 2004
and $8.8 million for the period December 6, 2003
through December 31, 2003. West Coast Power made
distributions to NRG Energy of $114.2 million for the
year ended December 31, 2004 and $122.2 million during
calendar year 2003. The contract and the corresponding earnings
and cash flow terminated on December 31, 2004. The CDWR
contract accounted for a majority of West Coast Powers
revenues during these periods. Beginning January 2005, all of
the West Coast Power assets have been negotiated and will
operate under reliability must-run, or RMR, agreements. In
January 2005, the El Segundo generating facility entered into a
tolling arrangement for its entire gross generating capacity of
670 MW commencing May 1, 2005 and extending through
December 31, 2005. During the term of this agreement, the
purchaser will be entitled to primary energy dispatch rights for
the facilitys generating capacity. The agreement is
subject to the amendment of the El Segundo RMR agreement to
switch to RMR Condition I and to otherwise allow the purchaser
to exercise its primary dispatch rights under this agreement
while preserving Cal ISOs ability to call on the El
Segundo facility as a reliability resource under the RMR
agreement, if necessary.
|
|
|
Construction, expansion, refurbishment and operation of
power generation facilities involve significant risks that
cannot always be covered by insurance or contractual protections
and could have a material adverse effect on our revenues and
results of operations. |
Many of our facilities are old. Newer plants owned by our
competitors are often more efficient than our aging plants,
which may put some of our plants at a competitive disadvantage.
Over time, our plants may be squeezed out of their markets, or
be unable to compete, because of the construction of new, more
efficient plants. Older equipment, even if maintained in
accordance with good engineering practices, may require
significant capital expenditures to keep it operating at optimum
efficiency. This equipment is also likely to require periodic
upgrading and improvement. Any unexpected failure, including
failure associated with breakdowns, forced outages or any
unanticipated capital expenditures could result in reduced
profitability. In addition, if we make any major
modifications to our power generation facilities, as
defined under the new source review provisions of the federal
Clean Air Act, we may be required to install best
available control technology or to achieve the
lowest achievable emissions rate. Any such
modifications would likely result in substantial additional
capital expenditures.
29
In general, environmental laws and regulations, particularly
with respect to air emissions, are becoming more stringent,
which may require us to install expensive plant upgrades and/or
restrict or modify our operations to meet more stringent
standards. An example of this is RGGI, the regional greenhouse
gas initiative in the Northeast, discussed previously in the
Northeast section under Regional U.S. Regulatory
Initiatives. There are many key unknowns with respect to this
initiative, including the applicable baseline, initial
allocations, required emissions reductions, availability of
offsets, the extent to which states will adopt the program, and
the timing for implementation. There can be no assurance at this
time that a carbon dioxide cap-and-trade program, if implemented
by the states in which we operate, would not have a material
adverse effect on our operations in this region.
We cannot predict the level of capital expenditures that will be
required due to frequently changing environmental and safety
laws and regulations, deteriorating facility conditions and
unexpected events (such as natural disasters or terrorist
attacks). The unexpected requirement of large capital
expenditures could have a material adverse effect on our
financial performance and condition. Further, the construction,
expansion, modification and refurbishment of power generation
facilities involve many risks, including:
|
|
|
|
|
interruptions to dispatch at our facilities; |
|
|
|
supply interruptions; |
|
|
|
work stoppages; |
|
|
|
labor disputes; |
|
|
|
weather interferences; |
|
|
|
unforeseen engineering, environmental and geological
problems; and |
|
|
|
unanticipated cost overruns. |
The ongoing operation of our facilities involves all of the
risks described above, as well as risks relating to the
breakdown or failure of equipment or processes, performance
below expected levels of output or efficiency and the inability
to transport our product to our customers in an efficient manner
due to a lack of transmission capacity. 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 our lost revenues, increased expenses or
liquidated damages payments should we experience equipment
breakdown or non-performance by contractors. Any of these risks
could cause us to operate below expected capacity or
availability levels, which in turn could result in lost
revenues, increased expenses, higher maintenance costs and
penalties.
|
|
|
We are exposed to the risk of fuel and fuel transportation
cost increases and volatility and interruption in fuel supply
because some of our facilities do not have long-term natural
gas, coal or liquid fuel supply agreements. |
Most of our domestic natural gas-, coal- and oil-fired power
generation facilities purchase their fuel requirements under
short-term contracts or on the spot market. Although we attempt
to purchase fuel based on our known fuel requirements, we still
face the risks of supply interruptions and fuel price volatility
as fuel deliveries may not exactly match energy sales due in
part to our need to prepurchase fuel inventories for reliability
and dispatch requirements. 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. Moreover, changes in market
prices for natural gas, coal and oil may result from the
following:
|
|
|
|
|
weather conditions; |
|
|
|
seasonality; |
|
|
|
demand for energy commodities and general economic conditions; |
30
|
|
|
|
|
disruption of electricity, gas or coal transmission or
transportation, infrastructure or other constraints or
inefficiencies; |
|
|
|
additional generating capacity; |
|
|
|
availability of competitively priced alternative energy sources; |
|
|
|
availability and levels of storage and inventory for fuel stocks; |
|
|
|
natural gas, crude oil, refined products and coal production
levels; |
|
|
|
the creditworthiness or bankruptcy or other financial distress
of market participants; |
|
|
|
changes in market liquidity; |
|
|
|
natural disasters, wars, embargoes, acts of terrorism and other
catastrophic events; and |
|
|
|
federal, state and foreign governmental regulation and
legislation. |
The volatility of fuel prices could materially and adversely
affect our financial results and operations.
|
|
|
The quality of fuel that we rely on at certain of our coal
plants may not be available at times. |
Our plant operating characteristics and equipment often dictate
the specific fuel quality to be combusted. The availability and
price of specific fuel qualities may vary due to supplier
financial or operational disruptions, transportation disruptions
and force majeure. At times, coal of specific quality may not be
available at any price, or we may not be able to transport such
coal to our facilities on a timely basis. In such case, we may
not be able to run a coal facility even if it would be
profitable. Operating a coal plant with lesser quality coal can
lead to emission problems. If we had contracted the power from
the facility, we could be required to supply or purchase power
from alternate sources, perhaps at a loss. This could have a
material adverse impact on the financial results of specific
plants and on our results of operations.
|
|
|
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 contracted supplier for the provision
of transportation of fuel and other services required for the
operation of our facilities. If these suppliers cannot perform,
we utilize the marketplace to provide these services. At times,
we rely on a single customer or a few customers to purchase all
or a significant portion of a facilitys output, in some
cases under long-term agreements that provide the support for
any project debt used to finance the facility. For the year
ended December 31, 2004, we derived 49.8% of our revenues
from majority-owned operations from four customers: NYISO
accounted for 28.5%, ISO New England accounted for 9.1%,
National Electricity Market Management Co. Ltd (Australia)
accounted for 6.8% and Vattenfall Europe (Germany) accounted for
5.4%. For the period December 6, 2003 through
December 31, 2003, we derived 39.0% of our revenues from
majority-owned operations from two customers: NYISO accounted
for 26.5% and ISO New England accounted for 12.5%. During the
period January 1, 2003 through December 5, 2003, we
derived 33.4% of our revenues from majority-owned operations
from NYISO. During 2002, we derived approximately 26.0% of our
revenues from majority-owned operations from NYISO. The failure
of any supplier or customer to fulfill its contractual
obligations to a facility could have a material adverse effect
on such facilitys financial results. Consequently, the
financial performance of any such facility is dependent on the
credit quality of, and continued performance by, suppliers and
customers.
|
|
|
Our operations are subject to hazards customary to the
power generation industry. We may not have adequate insurance to
cover all of these hazards. |
Our operations are subject to many hazards associated with the
power generation industry, which may expose us to significant
liabilities for which we may not have adequate insurance
coverage. Power generation involves hazardous activities,
including acquiring, transporting and unloading fuel, operating
large pieces of rotating equipment and delivering electricity to
transmission and distribution systems. In addition to natural
risks such as earthquake, flood, lightning, hurricane and wind,
hazards, such as fire, explosion, collapse and
31
machinery failure, are inherent risks in our operations. These
and other hazards can cause significant personal injury or loss
of life, severe damage to and destruction of property, plant and
equipment, contamination of, or damage to, the environment and
suspension of operations. The occurrence of any one of these
events may result in our being named as a defendant in lawsuits
asserting claims for substantial damages, including for
environmental cleanup costs, personal injury and property damage
and fines and/or penalties. We maintain an amount of insurance
protection that we consider adequate, but we cannot assure you
that our insurance will be sufficient or effective under all
circumstances and against all hazards or liabilities to which we
may be subject. A successful claim for which we are not fully
insured could hurt our financial results and materially harm our
financial condition. Further, due to rising insurance costs and
changes in the insurance markets, we cannot assure you that
insurance coverage will continue to be available at all or at
rates or on terms similar to those presently available to us.
|
|
|
We may not have sufficient liquidity to hedge market risks
effectively. |
We are exposed to market risks through our power marketing
business, which involves the sale of energy, capacity and
related products and procurement of fuel, transmission services
and emission allowances. These market risks include, among other
risks, volatility arising from the timing differences associated
with buying fuel, converting fuel into energy and delivering the
energy to a buyer. We seek to manage this volatility by entering
into forward and other contracts that hedge our exposure for our
net transactions. The effectiveness of our hedging strategy may
be dependent on the amount of collateral available to enter into
these hedging contracts, and liquidity requirements may be
greater than we anticipate or are able to meet. Without a
sufficient amount of working capital to post as collateral in
support of performance guarantees or as cash margin, we may not
be able to effectively manage price volatility. Factors which
could lead to an increase in our required collateral include
volatile commodity prices, adverse changes in our industry,
credit rating downgrades and the secured nature of our Amended
Credit Facility. Under certain unfavorable commodity price
scenarios, it is possible that we could experience inadequate
liquidity as a result of the posting of additional collateral.
Further, if our facilities experience unplanned outages, we may
be required to procure replacement power in the open market to
minimize our exposure to liquidated damages. Without adequate
liquidity to post margin and collateral requirements, we may be
exposed to significant losses and may miss significant
opportunities, and we may have increased exposure to the
volatility of spot markets.
|
|
|
The accounting for our hedging activities may increase the
volatility in our quarterly and annual financial results. |
We engage in commodity-related marketing and price-risk
management activities in order to economically hedge our
exposure to market risk with respect to (i) electricity
sales from our generation assets, (ii) fuel utilized by
those assets and (iii) emission allowances. We generally
attempt to balance our fixed-price physical and financial
purchases and sales commitments in terms of contract volumes and
the timing of performance and delivery obligations, through the
use of financial and physical derivative contracts. These
derivatives are accounted for in accordance with
SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by
SFAS No. 137, SFAS No. 138 and
SFAS No. 149. SFAS No. 133 requires us to
record all derivatives on the balance sheet at fair value with
changes in the fair value resulting from fluctuations in the
underlying commodity prices immediately recognized in earnings,
unless the derivative qualifies for hedge accounting treatment.
Whether a derivative qualifies for hedge accounting depends upon
it meeting specific criteria used to determine if hedge
accounting is and will remain appropriate for the term of the
derivative. Economic hedges will not necessarily qualify for
hedge accounting treatment. As a result, we are unable to
predict the impact that our risk management decisions may have
on our quarterly operating results or financial position.
32
|
|
|
The value of our assets is subject to the nature and
extent of decommissioning and remediation obligations applicable
to us. |
Our facilities and related properties may become subject to
decommissioning and/or site remediation obligations that may
require material unplanned expenditures or otherwise materially
affect the value of those assets. While we meet all site
remediation obligations currently applicable to our assets
(largely through the provision of various forms of financial
assurance. See Item 1 Environmental
Matters Domestic Site Remediation Matters), more
onerous obligations apply to sites where a plant is to be
dismantled, which could negatively affect our ability to
economically undertake power redevelopments or alternate uses at
existing power plant sites. Further, laws and regulations may
change to impose material additional decommissioning and
remediation obligations on us in the future, negatively
impacting the value of our assets and/or our ability to
undertake redevelopment projects.
|
|
|
Our results are subject to quarterly and seasonal
fluctuations. |
Our quarterly operating results have fluctuated in the past and
will continue to do so in the future as a result of a number of
factors, including seasonal variations in demand and
corresponding electricity and fuel price volatility and
variations in levels of production.
|
|
|
Because we own less than a majority of some of our project
investments, we cannot exercise complete control over their
operations. |
We have limited control over the operation of some project
investments and joint ventures because our investments are in
projects where we beneficially own less than a majority of the
ownership interests. We seek to exert a degree of influence with
respect to the management and operation of projects in which we
own less than a majority 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 operate
such projects. Our co-venturers may not have the level of
experience, technical expertise, human resources management and
other attributes necessary to operate these projects optimally.
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.
|
|
|
Our access to the capital markets may be limited. |
We may require additional capital from outside sources from time
to time. Our ability to arrange 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; |
|
|
|
covenants in our existing debt and credit agreements; |
|
|
|
credit availability from banks and other financial institutions; |
|
|
|
investor confidence in us, our partners and the regional
wholesale power markets; |
|
|
|
our financial performance and the financial performance of our
subsidiaries; |
|
|
|
our levels of indebtedness; |
|
|
|
maintenance of acceptable credit ratings; |
|
|
|
cash flow; and |
|
|
|
provisions of tax and securities laws that may impact raising
capital. |
We may not be successful in obtaining additional capital for
these or other reasons. The failure to obtain additional capital
from time to time may have a material adverse effect on our
business and operations.
33
|
|
|
Our business is subject to substantial governmental
regulation and permitting requirements and may be adversely
affected by liability under, or any future inability to comply
with, existing or future regulations or requirements. |
Our business is subject to extensive foreign, federal, state and
local energy, environmental and other laws and regulations. We
generally are required to obtain and comply with a wide variety
of licenses, permits and other approvals in order to construct,
operate or modify our facilities. We may incur significant
additional costs because of our need to comply 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. We could also be required to shut
down any facilities that do not comply with these requirements.
In addition, we are at risk for liability for past, current or
future contamination at our former and existing facilities or
with respect to off-site waste disposal sites that we have used
in our operations. Existing regulations may be revised or
reinterpreted and new laws and regulations may be adopted or
become applicable to us or our facilities in a manner that may
have a detrimental effect on our business. With the continuing
trend toward stricter standards, greater regulation and more
extensive permitting requirements, we expect that our
environmental expenditures will be substantial in the future.
Our operations are potentially subject to the provisions of
various energy laws and regulations, including the Public
Utility Holding Company Act of 1935, or PUHCA, the Federal Power
Act or FPA, and state and local utility laws and regulations.
Under the FPA, FERC regulates our wholesale sales of electric
power (other than sales by our qualifying facilities, which are
exempt from FERC rate regulation). The ability to sell energy at
market-based rates is predicated on the absence of market power
in either generation or transmission, the inability to create
barriers to entry and the inability to engage in abusive
affiliate transactions and filing of certain reports with FERC.
The market power analysis includes not only generation and
transmission owned by a particular applicant but also assets
owned by affiliated companies. Holders of market-based rate
authority must comply with obligations imposed by FERC and with
certain FERC filing requirements such as the requirement to file
quarterly reports detailing wholesale sales. Although a number
of our direct and indirect subsidiaries have obtained
market-based rate authority from FERC, these authorizations
could be revoked if we fail in the future to satisfy the
applicable criteria, if FERC modifies the criteria, or if FERC
eliminates or further restricts the ability of wholesale sellers
to make sales at market-based rates.
In addition, under PUHCA, registered holding companies and their
subsidiaries (i.e., companies with 10% or more of their voting
securities held by registered holding companies) are subject to
extensive regulation by the SEC. We will not be considered a
holding company or subject to PUHCA as long as we do not become
a subsidiary of another registered holding company and the
projects in which we have an interest (1) qualify as a
qualifying facility, or QF, under the Public Utility Regulatory
Policies Act, or PURPA, (2) obtain and maintain exempt
wholesale generator, or EWG, status under Section 32 of
PUHCA, (3) obtain and maintain foreign utility company, or
FUCO, status under Section 33 of PUHCA, or (4) are
subject to another exemption or waiver. If our projects were to
cease to be exempt and we were to become subject to SEC and FERC
regulation under PUHCA, it would be difficult for us to comply
with PUHCA absent a substantial corporate restructuring.
|
|
|
Our business faces regulatory risks related to the market
rules and regulations imposed by transmission providers,
independent system operators and regional transmission
organizations. |
We face regulatory risk imposed by the various transmission
providers, ISOs and RTOs and their corresponding market rules.
These market rules are subject to revisions, and such revisions
may not benefit us. Transmission providers, ISOs and RTOs have
FERC-approved tariffs that govern access to their transmission
system. These tariffs may contain provisions that limit access
to the transmission grid or allocate scarce transmission
capacity in a particular manner.
We presently operate in the following ISO or RTO markets:
California (through the West Coast Power joint venture and
individually), New England, New York and PJM (the Pennsylvania,
Jersey, Maryland Interconnection). The chief regulatory risk is
the lack of, or uncertainty regarding, market mechanisms that
effectively compensate generating units for providing
reliability services and installed capacity.
34
|
|
|
Restrictions in transmission access and expansions in the
transmission system could reduce revenues. |
We are dependent on access to transmission systems to sell our
energy. In the northeastern ISO and RTO markets, we have a
significant amount of generation located in load pockets.
Expansion of the transmission system to reduce or eliminate
these load pockets could negatively impact our existing
facilities in these areas.
Our facilities located in the Entergy franchise territory face a
different transmission risk, in that restrictions on
transmission access may limit our ability to sell energy or to
service new customers.
|
|
|
We are subject to claims made after the date that we filed
for bankruptcy and other claims that were not discharged in the
bankruptcy cases, which could have a material adverse effect on
our results of operations and profitability. |
The nature of our business frequently subjects us to litigation.
Many of the largest claims against us prior to the date of the
bankruptcy filing were satisfied and discharged in accordance
with the terms of the NRG plan of reorganization or the plan of
reorganization for certain subsidiaries or in connection with
settlement agreements that were approved by the bankruptcy court
prior to our emergence from bankruptcy. Circumstances in which
pre-bankruptcy filing claims have not been discharged include,
among others, where we have agreed with a given claimant to
preserve their claims, as well as, potentially, instances where
a claimant had no notice of the bankruptcy filing. The ultimate
resolution of certain remaining or future claims may have a
material adverse effect on our results of operations and
profitability. In addition, claims made against subsidiaries
that did not file for chapter 11, and claims arising after
the date of our bankruptcy filing, were not discharged in the
bankruptcy cases. See Item 15 Note 27 to
the Consolidated Financial Statements included in our Annual
Report on Form 10-K for the Year ended December 31,
2004, for a description of the significant legal proceedings and
investigations in which we are presently involved.
Under the NRG plan of reorganization, we have established
disputed claims reserves, which we will utilize to make
distributions to holders of disputed claims in our bankruptcy
cases as and when their claims are resolved. If these reserves
prove inadequate, we will be required to finance any further
cash distributions from other resources, and doing so could have
a material adverse impact on our financial condition, and, in
addition, we could be required to issue new common stock, which
would dilute existing shareholders. In particular, the State of
Californias disputed claims against us are capped at
$1.35 billion. There are also a number of private claims
springing from the California energy crisis for which there is
no cap. We have made no reserves for these claims, because we
believe they are without merit; however, if the State of
California or these private litigants prevail, then payment of
the distributions to which the State of California or these
private litigants would be entitled under the NRG plan of
reorganization could have a material adverse impact on our
financial condition.
|
|
|
Acts of terrorism could have a material adverse effect on
our financial condition, results of operations and cash
flows. |
Our generation facilities and the facilities of third parties on
which they rely may be targets of terrorist activities, as well
as events occurring in response to or in connection with them,
that could cause environmental repercussions and/or result in
full or partial disruption of their ability to generate,
transmit, transport or distribute electricity or natural gas.
Strategic targets, such as energy-related facilities, may be at
greater risk of future terrorist activities than other domestic
targets. Any such environmental repercussions or disruption
could result in a significant decrease in revenues or
significant reconstruction or remediation costs, which could
have a material adverse effect on our financial condition,
results of operations and cash flows.
|
|
|
Our international investments face uncertainties. |
We have investments in power projects in Australia, the United
Kingdom, Germany and Brazil. International investments are
subject to risks and uncertainties relating to the political,
social and economic
35
structures of the countries in which we invest. Risks
specifically related to our investments in international
projects may include:
|
|
|
|
|
fluctuations in currency valuation; |
|
|
|
currency inconvertibility; |
|
|
|
expropriation and confiscatory taxation; |
|
|
|
increased regulation; and |
|
|
|
approval requirements and governmental policies limiting returns
to foreign investors. |
Cautionary Statement Regarding Forward Looking Information
This Annual Report on Form 10-K includes forward-looking
statements within the meaning of Section 27A of the
Securities Act and Section 21E of the Exchange Act. The
words believes, projects,
anticipates, plans, expects,
intends, estimates and similar
expressions are intended to identify forward-looking statements.
These forward-looking statements involve known and unknown
risks, uncertainties and other factors which may cause our
actual results, performance and achievements, or industry
results, to be materially different from any future results,
performance or achievements expressed or implied by such
forward-looking statement. These factors, risks and
uncertainties include, but are not limited to, the factors
described under Risks Related to NRG Energy, Inc. in
this Item 1 and to the following:
|
|
|
|
|
Lack of comparable financial data due to adoption of Fresh Start
reporting; |
|
|
|
Our ability to successfully and timely close transactions to
sell certain of our assets; |
|
|
|
The potential impact of our corporate relocation on workforce
requirements including the loss of institutional knowledge and
the inability to maintain existing processes; |
|
|
|
Hazards customary to the power production industry and power
generation operations such as fuel and electricity price
volatility, unusual weather conditions, catastrophic
weather-related or other damage to facilities, unscheduled
generation outages, maintenance or repairs, unanticipated
changes to fossil fuel supply costs or availability due to
higher demand, shortages, transportation problems or other
developments, environmental incidents, or electric transmission
or gas pipeline system constraints and the possibility that we
may not have adequate insurance to cover losses as a result of
such hazards; |
|
|
|
Our potential inability to enter into contracts to sell power
and procure fuel on terms and prices acceptable to us; |
|
|
|
The liquidity and competitiveness of wholesale markets for
energy commodities; |
|
|
|
Changes in government regulation, including but not limited to
the pending changes of market rules, market structures and
design, rates, tariffs, environmental laws and regulations and
regulatory compliance requirements; |
|
|
|
Price mitigation strategies and other market structures employed
by independent system operators, or ISOs, or regional
transmission organizations, or RTOs, that result in a failure to
adequately compensate our generation units for all of their
costs; |
|
|
|
Our ability to borrow additional funds and access capital
markets, as well as our substantial indebtedness and the
possibility that we may incur additional indebtedness going
forward; and |
|
|
|
Significant operating and financial restrictions placed on us
contained in the indenture governing our 8% second priority
senior secured notes due 2013, our amended and restated credit
facility as well as in debt and other agreements of certain of
our subsidiaries and project affiliates generally. |
Forward-looking statements speak only as of the date they were
made, and we undertake no obligation to publicly update or
revise any forward-looking statements, whether as a result of
new information, future events or otherwise. The foregoing
review of factors that could cause our actual results to differ
materially from those
36
contemplated in any forward-looking statements included in this
Annual Report on Form 10-K should not be construed as
exhaustive.
Item 2 Properties
Listed below are descriptions of our interests in facilities,
operations and/or projects owned as of December 31, 2004.
Independent Power Production and Cogeneration Facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
NRGS |
|
|
|
|
|
|
Owned |
|
Percentage |
|
|
|
|
|
|
Capacity |
|
Ownership |
|
|
Name and Location of Facility |
|
Purchaser/Power Market |
|
(MW) |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
Northeast Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oswego, New York
|
|
|
NYISO |
|
|
|
1,700 |
|
|
|
100% |
|
|
|
Oil/Gas |
|
Huntley, New York
|
|
|
NYISO |
|
|
|
760 |
|
|
|
100% |
|
|
|
Coal |
|
Dunkirk, New York
|
|
|
NYISO |
|
|
|
600 |
|
|
|
100% |
|
|
|
Coal |
|
Arthur Kill, New York
|
|
|
NYISO |
|
|
|
842 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
Astoria Gas Turbines, New York
|
|
|
NYISO |
|
|
|
600 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
Somerset, Massachusetts
|
|
|
ISO-NE |
|
|
|
136 |
|
|
|
100% |
|
|
|
Coal/Oil |
|
Middletown, Connecticut
|
|
|
ISO-NE |
|
|
|
786 |
|
|
|
100% |
|
|
|
Oil/Gas/Jet Fuel |
|
Montville, Connecticut
|
|
|
ISO-NE |
|
|
|
498 |
|
|
|
100% |
|
|
|
Oil/Gas/Diesel |
|
Devon, Connecticut
|
|
|
ISO-NE |
|
|
|
401 |
|
|
|
100% |
|
|
|
Gas/Oil/Jet Fuel |
|
Norwalk Harbor, Connecticut
|
|
|
ISO-NE |
|
|
|
353 |
|
|
|
100% |
|
|
|
Oil |
|
Connecticut Jet Power, Connecticut
|
|
|
ISO-NE |
|
|
|
127 |
|
|
|
100% |
|
|
|
Jet Fuel |
|
Indian River, Delaware
|
|
|
PJM |
|
|
|
784 |
|
|
|
100% |
|
|
|
Coal/Oil |
|
Vienna, Maryland
|
|
|
PJM |
|
|
|
170 |
|
|
|
100% |
|
|
|
Oil |
|
Conemaugh, Pennsylvania
|
|
|
PJM |
|
|
|
64 |
|
|
|
4% |
|
|
|
Coal/Oil |
|
Keystone, Pennsylvania
|
|
|
PJM |
|
|
|
63 |
|
|
|
4% |
|
|
|
Coal/Oil |
|
South Central Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Cajun II, Louisiana*
|
|
|
SERC-Entergy |
|
|
|
1,489 |
|
|
|
86% |
|
|
|
Coal |
|
Big Cajun I, Louisiana
|
|
|
SERC-Entergy |
|
|
|
458 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
Bayou Cove, Louisiana
|
|
|
SERC-Entergy |
|
|
|
320 |
|
|
|
100% |
|
|
|
Gas |
|
Sterlington, Louisiana
|
|
|
SERC-Entergy |
|
|
|
202 |
|
|
|
100% |
|
|
|
Gas |
|
West Coast Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
El Segundo Power, California
|
|
|
Cal ISO |
|
|
|
335 |
|
|
|
50% |
|
|
|
Gas |
|
Encina, California
|
|
|
Cal ISO |
|
|
|
483 |
|
|
|
50% |
|
|
|
Gas/Oil |
|
Long Beach Generating, California**
|
|
|
Cal ISO |
|
|
|
265 |
|
|
|
50% |
|
|
|
Gas |
|
San Diego Combustion Turbines, CA
|
|
|
Cal ISO |
|
|
|
85 |
|
|
|
50% |
|
|
|
Gas/Oil |
|
Saguaro Power Co., Nevada***
|
|
|
WECC |
|
|
|
53 |
|
|
|
50% |
|
|
|
Gas/Oil |
|
Chowchilla, California
|
|
|
Cal ISO |
|
|
|
49 |
|
|
|
100% |
|
|
|
Gas |
|
Red Bluff, California
|
|
|
Cal ISO |
|
|
|
45 |
|
|
|
100% |
|
|
|
Gas |
|
Other North America:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Audrain***
|
|
|
MAIN |
|
|
|
640 |
|
|
|
100% |
|
|
|
Gas |
|
Rockford I, Illinois
|
|
|
MAIN |
|
|
|
342 |
|
|
|
100% |
|
|
|
Gas |
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net |
|
NRGS |
|
|
|
|
|
|
Owned |
|
Percentage |
|
|
|
|
|
|
Capacity |
|
Ownership |
|
|
Name and Location of Facility |
|
Purchaser/Power Market |
|
(MW) |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
Rockford II, Illinois
|
|
|
MAIN |
|
|
|
171 |
|
|
|
100% |
|
|
|
Gas |
|
Rocky Road Power, Illinois
|
|
|
PJM |
|
|
|
175 |
|
|
|
50% |
|
|
|
Gas |
|
Ilion, New York
|
|
|
NYISO |
|
|
|
60 |
|
|
|
100% |
|
|
|
Gas/Oil |
|
Dover, Delaware
|
|
|
PJM |
|
|
|
106 |
|
|
|
100% |
|
|
|
Gas/Coal/Oil |
|
James River***
|
|
|
SERC TVA |
|
|
|
55 |
|
|
|
50% |
|
|
|
Coal |
|
Paxton Creek Cogeneration
|
|
|
PJM |
|
|
|
12 |
|
|
|
100% |
|
|
|
Gas |
|
Other 3 projects***
|
|
|
Various |
|
|
|
30 |
|
|
|
Various |
|
|
|
Various |
|
Australia:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Flinders, South Australia
|
|
|
South Australian Pool |
|
|
|
760 |
|
|
|
100% |
|
|
|
Coal |
|
Gladstone Power Station, Queensland
|
|
|
Enertrade/Boyne Smelters |
|
|
|
630 |
|
|
|
38% |
|
|
|
Coal |
|
Other International:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Europe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Enfield Energy Centre, UK***
|
|
|
UK Electricity Grid |
|
|
|
95 |
|
|
|
25% |
|
|
|
Gas |
|
Schkopau Power Station, Germany
|
|
|
Vattenfall Europe |
|
|
|
400 |
|
|
|
42% |
|
|
|
Coal |
|
MIBRAG mbH, Germany****
|
|
|
ENVIA/MIBRAG Mines |
|
|
|
119 |
|
|
|
50% |
|
|
|
Coal |
|
Brazil:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Itiquira Energetica, Brazil***
|
|
|
COPEL |
|
|
|
154 |
|
|
|
99% |
|
|
|
Hydro |
|
NEO Corporation, Various
|
|
|
Various |
|
|
|
41 |
|
|
|
Various |
|
|
|
Various |
|
|
|
* |
Units 1 and 2 owned 100%, Unit 3 owned 58% |
|
** |
Retired effective January 1, 2005 |
|
*** |
May sell or dispose of in 2005 |
|
**** |
Primarily a coal mining facility |
38
Thermal Energy Production and Transmission Facilities and
Resource Recovery Facilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs |
|
|
|
|
|
|
|
|
Percentage |
|
|
Name and Location of |
|
|
|
|
|
Ownership |
|
|
Facility |
|
Customers |
|
Net Owned Capacity* |
|
Interest |
|
Fuel Type |
|
|
|
|
|
|
|
|
|
Non-Generation Facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy Center Minneapolis, Minnesota
|
|
Approx. 100 steam customers and 45 chilled water customers |
|
Steam: 1,203 mm Btu/hr. (353 MWt)
Chilled water: 41,630 tons (146 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center San Francisco, California
|
|
Approx. 170 steam customers |
|
Steam: 482 mm Btu/hr. (141 MWt) |
|
|
100% |
|
|
|
Gas |
|
NRG Energy Center Harrisburg, Pennsylvania
|
|
Approx. 270 steam customers and 3 chilled water customers |
|
Steam: 440 mm Btu/hr. (129 MWt)
Chilled water: 2,400 tons (8 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center Pittsburgh, Pennsylvania
|
|
Approx. 25 steam and 25 chilled water customers |
|
Steam: 266 mm Btu/hr. (78 MWt)
Chilled water: 12,580 tons (44 MWt) |
|
|
100% |
|
|
|
Gas/Oil |
|
NRG Energy Center San Diego, California
|
|
Approx. 20 chilled water customers |
|
Chilled water: 7,425 tons (26 MWt) |
|
|
100% |
|
|
|
Gas |
|
NRG Energy Center St. Paul, Minnesota
|
|
Rock-Tenn Company |
|
Steam: 430 mm Btu/hr. (126 MWt) |
|
|
100% |
|
|
|
Coal/Gas/Oil |
|
Camas Power Boiler Washington
|
|
Georgia-Pacific Corp. |
|
Steam: 200 mm Btu/hr. (59 MWt) |
|
|
100% |
|
|
|
Biomass |
|
NRG Energy Center Dover, Delaware
|
|
Kraft Foods, Inc. |
|
Steam: 190 mm Btu/hr. (56 MWt) |
|
|
100% |
|
|
|
Coal |
|
NRG Energy Center Bayport, Minnesota
|
|
Andersen Corporation and Minnesota Correctional Facility |
|
Steam: 200 mm Btu/hr. (59 MWt) |
|
|
100% |
|
|
|
Coal/Gas/Propane |
|
|
|
* |
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. |
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGS |
|
|
|
|
|
|
Percentage |
|
|
|
|
|
|
Ownership |
Name and Location of Facility |
|
Customers |
|
Net Owned Capacity |
|
Interest |
|
|
|
|
|
|
|
Alternative Energy:
|
|
|
|
|
|
|
|
|
Resource Recovery Facilities
|
|
|
|
|
|
|
|
|
Newport, Minnesota
|
|
Ramsey and Washington Counties |
|
MSW: 1,500 tons/day |
|
|
100% |
|
Elk River, Minnesota
|
|
Anoka, Hennepin, and Sherburne Counties; Tri- County Solid Waste
Management Commission |
|
MSW: 1,275 tons/day |
|
|
85% |
|
Other Properties
In addition to the above, we lease our corporate offices at 211
Carnegie Center, Princeton, New Jersey 08540 and various other
office spaces. We also own interests in other construction
projects in various states of completion, as well as other
properties not used for operational purposes.
|
|
Item 3 |
Legal Proceedings |
California Wholesale Electricity Litigation and Related
Investigations
People of the State of California ex. rel. Bill Lockyer,
Attorney General, v. Dynegy, Inc. et al.,
U.S. District Court, Northern District of California,
Case No. C-02-O1854 VRW; U.S. Court of Appeals for the
Ninth Circuit, Case No. 02-16619. This action was filed in
state court on March 11, 2002, against us, Dynegy, Dynegy
Power Marketing, Inc., Xcel Energy, West Coast Power, or WCP,
and WCPs four operating subsidiaries. Through our
subsidiary, NRG West Coast LLC, we are a 50 percent
beneficial owner with Dynegy of West Coast Power, which owns,
operates, and markets the power of four California plants.
Dynegy and its affiliates and subsidiaries are responsible for
gas procurement and marketing and trading activities on behalf
of West Coast Power. The complaint alleges that the defendants
violated state unfair competition law by selling ancillary
services to the state independent system operator, and
subsequently selling the same capacity into the spot market. It
seeks injunctive relief as well as restitution, disgorgement and
unspecified civil penalties. On April 17, 2002, the
defendants removed the case to the U.S. District Court for
the Northern District of California in San Francisco. In a
March 25, 2003, opinion, the court dismissed the Attorney
Generals action against Dynegy and us with prejudice,
finding it was barred by the filed-rate doctrine and preempted
by federal law. On July 6, 2004, the U.S. Court of
Appeals for the Ninth Circuit rejected the Attorney
Generals appeal. Rehearing was sought and rejected on
October 29, 2004. On January 27, 2005, the Attorney
General filed a petition for writ of certiorari to the
U.S. Supreme Court.
Public Utility District of Snohomish County v. Dynegy
Power Marketing, Inc et al., Case No. 02-CV-1993
RHW, U.S. District Court, Southern District of California
(part of MDL 1405). This action was filed against us,
Dynegy, Xcel Energy and several other market participants on
July 15, 2002. The complaint alleges violations of state
anti-trust and unfair competition laws by means of price fixing,
restriction of supply, and other market gaming
activities. After the action was transferred to the
U.S. District Court for the Southern District of California
in San Diego and made a part of the Multi-District
Litigation, or MDL, proceeding described below, it was dismissed
on the grounds of federal preemption and filed-rate doctrine.
The plaintiffs filed a notice of appeal and on
September 10, 2004, the U.S. Court of Appeals for the
Ninth Circuit affirmed the District Courts dismissal on
the same legal grounds. On November 5, 2004, the plaintiff
filed a petition for writ of certiorari to the U.S. Supreme
Court and on February 22, 2005, the Supreme Court issued an
order requesting the views of the U.S. Solicitor General on
the petition.
40
In re: Wholesale Electricity Antitrust Litigation, MDL
1405, U.S. District Court, Southern District of
California. The cases included in this proceeding are as
follows:
|
|
|
Pamela R Gordon, on Behalf of Herself and All Others
Similarly Situated v Reliant Energy, Inc. et al., Case
No. 758487, Superior Court of the State of California,
County of San Diego (filed on November 27, 2000).
Ruth Hendricks, On Behalf of Herself and All Others
Similarly Situated and On Behalf of the General Public v.
Dynegy Power Marketing, Inc. et al., Case
No. 758565, Superior Court of the State of California,
County of San Diego (filed November 29, 2000).
The People of the State of California, by and through
San Francisco City Attorney Louise H. Renne v. Dynegy
Power Marketing, Inc. et al., Case No. 318189,
Superior Court of California, San Francisco County
(filed January 18, 2001). Pier 23 Restaurant, A
California Partnership, On Behalf of Itself and All Others
Similarly Situated v PG&E Energy Trading et al.,
Case No. 318343, Superior Court of California,
San Francisco County (filed January 24, 2001).
Sweetwater Authority, et al. v. Dynegy, Inc.
et al., Case No. 760743, Superior Court of
California, County of San Diego (filed January 16,
2001). Cruz M Bustamante, individually, and Barbara
Matthews, individually, and on behalf of the general public and
as a representative taxpayer suit, v. Dynegy Inc.
et al., inclusive. Case No. BC249705, Superior
Court of California, Los Angeles County (filed May 2,
2001). |
NRG Energy is a defendant in all of the above referenced
cases. Several of WCPs operating subsidiaries are also
defendants in the Bustamante case. The cases
allege unfair competition, market manipulation and price fixing
and all seek treble damages, restitution and injunctive relief.
In December 2002, the U.S. District Court for the Southern
District of California issued an opinion finding that federal
jurisdiction was absent in the district court, and remanding the
cases back to state court. A notice of appeal was filed and on
December 8, 2004, the U.S. Court of Appeals for the
Ninth Circuit issued its published, unanimous decision affirming
the District Court in most respects. On March 5, 2005, the
Ninth Circuit denied a petition for rehearing. We anticipate
that the cases will be remanded to state court in 2005 at which
time the defendants will again raise filed-rate and federal
preemption challenges.
Northern California cases against
various market participants. T&E Pastorino v. Duke
Energy, et al., Case No. 02-CV-2176; RDJ Farms v.
Allegheny Energy, et al., Case No. 02-2059; Century
Theatres v. Allegheny Energy, et al., Case No.
02-CV-2177; Bronco Don v. Duke Energy, Case
No. 02-CV-2178; El Super Burrito v. Allegheny
Energy, et al., Case No. 02-CV-2180; Leos
Day & Night Pharmacy, Case No. 02-CV-2181; J&M
Karsant V. Duke Energy, Case No. 02-CV-2182. (Part of MDL
1405). We were not named in any of these cases, but in all
of them, either WCP or one or more of its operating subsidiaries
as well as Dynegy are named as defendants. These cases all
allege violations of state unfair competition law. Dynegys
counsel is representing both Dynegy and the WCP subsidiaries in
these cases with each side responsible for half of the defense
costs. These cases all were removed to federal court and denied
remand to state court. In late August 2003, the defendants
motions to dismiss were granted in these various cases. On
February 25, 2005, the U.S. Court of Appeals for the
Ninth Circuit approved the district court decision to dismiss
the case.
Bustamante v. McGraw-Hill Companies, Inc.,
et al., No. BC 235598, California Superior Court,
Los Angeles County (filed November 20, 2002, and
amended in 2003). This putative class action alleges that the
defendants attempted to manipulate gas indexes by reporting
false and fraudulent trades. Named defendants in the suit
include several of WCPs operating subsidiaries. Dynegy is
defending the WCP subsidiaries pursuant to a limited
indemnification agreement. The complaint seeks restitution and
disgorgement, civil fines, compensatory and punitive damages,
attorneys fees and declaratory and injunctive relief.
Defendants motion for summary judgment is pending.
Jerry Egger, et al. v. Dynegy, Inc., et al.,
Case No. 809822, Superior Court of California,
San Diego County (filed May 1, 2003). This
putative class action alleges violations of Californias
antitrust law, as well as unlawful and unfair business practices
and seeks treble damages, restitution and injunctive relief. The
named defendants include WCP and several of its operating
subsidiaries. NRG Energy is not named. This case was
removed to the U.S. District Court for the Northern
District of California, and the defendants have moved to have
this case included as Multi-District Litigation along with the
above referenced cases. Plaintiffs argued a motion to remand to
state court on February 19, 2004, at which time the court
stayed the case pending a
41
decision from the U.S. Court of Appeals for the Ninth
Circuit in the Pastorino appeal, referenced above.
Dynegys counsel is representing Dynegy and WCP and its
subsidiaries in this case with each side responsible for half of
the defense costs. With the Ninth Circuits
February 25, 2005, decision in the Northern California
cases referenced above, a decision on the stay in this case is
expected this year.
Texas-Ohio Energy, Inc., on behalf of Itself and all
others similarly situated v. Dynegy, Inc. Holding Co., West
Coast Power, LLC, et al., Case No. CIV.S-03-2346 DFL
GGH, U.S. District Court, Eastern District of
California (filed November 10, 2003). This putative
class action alleges violations of the federal Sherman and
Clayton Acts and state antitrust law. In addition to naming WCP
and Dynegy, Inc. Holding Co., the complaint names numerous
industry participants, as well as unnamed
co-conspirators. The complaint alleges that defendants
conspired to manipulate the spot price and basis differential of
natural gas with respect to the California market. The complaint
seeks unspecified amounts of damages, including a trebling of
plaintiffs and the putative classs actual damages.
Dynegy is defending WCP pursuant to a limited indemnification
agreement.
City of Tacoma, Department of Public Utilities, Light
Division, v. American Electric Power Service Corporation,
et al., U.S. District Court, Western District of
Washington, Case No. C04-5325 RBL (filed June 16,
2004). The complaint names over 50 defendants, including
WCPs four operating subsidiaries and various Dynegy
entities. The complaint also names both us and WCP as
Non-Defendant Co-Conspirators. Plaintiff alleges a
conspiracy to violate the federal Sherman Act by withholding
power generation from, and/or inflating the apparent demand for
power in markets in California and elsewhere. Plaintiff claims
damages in excess of $175 million. Dynegy is defending WCP
and its subsidiaries pursuant to a limited indemnification
agreement.
Fairhaven Power Company v. Encana Corporation,
et al., Case No. CIV-F-04-6256 (OWW/ LJO),
U.S. District Court, Eastern District of California
(filed September 22, 2004), Abelman v. Encana,
U.S. District Court, Eastern District of California, Case
No. 04-CV-6684 (filed December 13, 2004);
Utility Savings v. Reliant, et al.,
U.S. District Court, Eastern District of California,
(filed November 29, 2004). These putative class actions
name WCP and Dynegy Holding Co., Inc. among the numerous
defendants. The Complaints allege violations of the federal
Sherman Act, and Californias antitrust and unfair
competition law as well as unjust enrichment. The Complaints
seek a determination of class action status, a trebling of
unspecified damages, statutory, punitive or exemplary damages,
restitution, disgorgement, injunctive relief, a constructive
trust, and costs and attorneys fees. Dynegy is defending
WCP pursuant to a limited indemnification agreement.
In Re: Natural Gas Commodity Litigation, Master
File No. 03 CV 6186(VM)(AJP), U.S. District Court,
Southern District of New York. West Coast Power, or WCP, and
Dynegy Marketing and Trade are among numerous defendants accused
of manipulating gas index publications and prices in violation
of the federal Commodity Exchange Act, or CEA, in the following
consolidated cases: Cornerstone Propane Partners,
LP v. Reliant Energy Services, Inc., et al., Case
No. 03 CV 6186 (S.D.N.Y. filed August 18, 2003);
Calle Gracey v. American Electric Power Co., Inc.,
et al., Case No. 03 CV 7750 (S.D.N.Y. filed
Oct. 1, 2003); Cornerstone Propane Partners,
LP v. Coral Energy Resources, LP, et al., Case
No. 03 CV 8320 (S.D.N.Y. filed Oct. 21, 2003); and
Viola v. Reliant Energy Servs., et al., Case
No. 03 CV 9039 (S.D.N.Y. filed Nov. 14, 2003).
Plaintiffs, in their Amended Consolidated Class Action
Complaint dated October 14, 2004, allege that the
defendants engaged in a scheme to manipulate and inflate natural
gas prices. The plaintiffs seek class action status for their
lawsuit, unspecified actual damages for violations of the CEA
and costs and attorneys fees. Dynegy Marketing and Trade
is defending WCP in these proceedings pursuant to a limited
indemnification agreement.
ABAG Publicly Owned Energy Resources v. Sempra Energy,
et al., Alameda County Superior Court, Case
No. RG04186098, filed November 10, 2004; Cruz
Bustamante v. Williams Energy Services, et al.,
Los Angeles Superior Court, Case No. BC285598, filed
June 28, 2004; City & County of
San Francisco, et al. v. Sempra Energy,
et al., San Diego County Superior Court, Case
No. GIC832539, filed June 8, 2004; City of
San Diego v. Sempra Energy, et al.,
San Diego County Superior Court, Case No. GIC839407,
filed December 1, 2004; County of Alameda v.
Sempra Energy, Alameda County Superior Court, Case
42
No. RG041282878, filed October 29, 2004;
County of San Diego v. Sempra Energy, et al.,
San Diego County Superior Court, Case No. GIC833371,
filed July 28, 2004; County of
San Mateo v. Sempra Energy, et al.,
San Mateo County Superior Court, Case No. CIV443882,
filed December 23, 2004; County of
Santa Clara v. Sempra Energy, et al.,
San Diego County Superior Court, Case No. GIC832538,
filed July 8, 2004; Nurserymens Exchange,
Inc. v. Sempra Energy, et al., San Mateo County
Superior Court, Case No. CIV442605, filed
October 21, 2004; Older v. Sempra Energy,
et al., San Diego Superior Court, Case
No. GIC835457, filed December 8, 2004;
Owens-Brockway Glass Container, Inc. v. Sempra
Energy, et al., Alameda County Superior Court, Case
No. RG0412046, filed December 30, 2004;
Sacramento Municipal Utility District v. Reliant Energy
Services, Inc., Sacramento County Superior Court, Case
No. 04AS04689, filed November 19, 2004; School
Project for Utility Rate Reduction v. Sempra Energy,
et al., Alameda County Superior Court, Case
No. RG04180958, filed October 19, 2004; Tamco,
et al. v. Dynegy, Inc., et al.,
San Diego County Superior Court, Case
No. GIC840587, filed December 29, 2004; Utility
Savings & Refund Services, LLP v. Reliant Energy
Services, Inc., et al., U.S. District Court, Eastern
District of California, Case No. 04-6626, filed
November 30, 2004.
The defendants in all of the above referenced cases include WCP
and various Dynegy entities. NRG Energy is not a defendant.
The Complaints allege that defendants attempted to manipulate
natural gas prices in California, and allege violations of
Californias antitrust law, conspiracy, and unjust
enrichment. The relief sought in all of these cases includes
treble damages, restitution and injunctive relief. The
Complaints assert that WCP is a joint venture between Dynegy and
NRG Energy, but that Dynegy Marketing and Trade handled all
of the administrative services and commodity related concerns of
WCP. The cases are presently being consolidated for coordinated
pretrial proceedings in San Diego County Superior Court.
Dynegy is defending WCP pursuant to a limited indemnification
agreement.
|
|
|
NRG Bankruptcy Cap on California Claims |
On November 21, 2003, in conjunction with confirmation of
the NRG plan of reorganization, we reached an agreement with the
Attorney General and the State of California, generally, whereby
for purposes of distributions, if any, to be made to the State
of California under the NRG plan of reorganization, the
liquidated amount of any and all allowed claims shall not exceed
$1.35 billion in the aggregate. The agreement neither
affects our right to object to these claims on any and all
grounds nor admits any liability whatsoever. We further agreed
to waive any objection to the liquidation of these claims in a
non-bankruptcy forum having proper jurisdiction.
|
|
|
FERC California Market Manipulation |
The FERC conducted an Investigation of Potential
Manipulation of Electric and Natural Gas Prices, which
involved hundreds of parties, including our affiliate, West
Coast Power, or WCP, and substantial discovery. In June 2001,
FERC initiated proceedings related to Californias demand
for $8.9 billion in refunds from power sellers who
allegedly inflated wholesale prices during the energy crisis.
After two administrative law judge opinions and a March 26,
2003, FERC Order adopting in part and modifying in part the last
of the two opinions, Dynegy, we and the WCP entities engaged in
extensive settlement negotiations with FERC Staff; the People of
the State of California ex rel. Bill Lockyer, Attorney
General; the California Public Utility Commission, or CPUC
staff; the California Department of Water Resources acting
through its Electric Power Fund, the California Electricity
Oversight Board; PG&E; Southern California Edison Company;
and San Diego Gas and Electric Company. The parties entered
into a definitive, comprehensive settlement, which FERC approved
on October 25, 2004, (the FERC Settlement).
As part of the FERC Settlement, WCP placed into escrow for
distribution to California energy consumers a total of
$22.5 million, which includes the $3 million
settlement with FERC respecting trading techniques, announced on
January 20, 2004. In addition, WCP agreed to forego:
(1) past due receivables from the California Independent
System Operator and the California Power Exchange related to the
settlement period; and (2) natural gas cost recovery claims
against the settling parties related to the settlement period. In
43
exchange, the various California settling parties agreed to
forego: (1) all claims relating to refunds or other
monetary damages for sales of electricity during the settlement
period; (2) claims alleging that WCP received unjust or
unreasonable rates for the sale of electricity during the
settlement period; and (3) FERC dismissed numerous
investigations respecting market transactions. For a two year
period following FERCs acceptance of the settlement
agreement, WCP will retain an independent engineering company to
perform semi-annual audits of the technical and economic basis,
justification and rationale for outages that occurred at its
California generating plants during the previous six month
period, and to have the results of such audits provided to the
FERC Office of Market Oversight and Investigation without any
prior review by WCP.
WCP previously established significant reserves on its balance
sheet and will not incur any further loss associated with the
FERC Settlement. We will pay no cash from corporate funds, nor
will the FERC Settlement have any direct impact on our profit
and loss statement.
There are a number of additional, related proceedings in which
WCP subsidiaries are parties, which are either pending before
FERC or on appeal from FERC to various U.S. Courts of
Appeal. These cases involve, among other things, allegations of
physical withholding, a FERC-established price mitigation plan
determining maximum rates for wholesale power transactions in
certain spot markets, and the enforceability of, and obligations
under, various contracts with, among others, the California
Independent System Operator and the State of California and
certain of its agencies and departments.
|
|
|
California Attorney General |
The California Attorney General has undertaken an investigation
entitled In the Matter of the Investigation of Possibly
Unlawful, Unfair, or Anti-Competitive Behavior Affecting
Electricity Prices in California. In this connection, the
Attorney General has issued subpoenas to Dynegy, served
interrogatories on Dynegy and us, and informally requested
documents and conducted interviews with Dynegy and Dynegy
employees as well as us and our employees. We responded to the
interrogatories in the summer of 2002, and again on
September 3, 2002. We have also produced a large volume of
documentation relating to the West Coast Power subsidiaries.
Electricity Consumers Resource Council v. Federal
Energy Regulatory Commission, Docket No. 03-1449.
On December 19, 2003, the Electricity Consumers Resource
Council, or ECRC, appealed to the U.S. Court of Appeals for
the District of Columbia Circuit a 2003 FERC decision approving
the implementation of a demand curve for the New York installed
capacity, or ICAP, market. ECRC claims that the implementation
of the ICAP demand curve violates section 205 of the
Federal Power Act because it constitutes unreasonable
ratemaking. On December 3, 2004, the Company filed a brief
opposing the ECRC request.
Consolidated Edison Co. of New York v. Federal Energy
Regulatory Commission, Docket No. 01-1503.
Consolidated Edison and others petitioned the U.S. Court of
Appeals for the District of Columbia Circuit for review of
certain FERC orders in which FERC refused to order a
re-determination of prices in the New York Independent System
Operator, or NYISO, operating reserve markets for the period
January 29, 2000, to March 27, 2000. On
November 7, 2003, the Court issued a decision which found
that the NYISOs method of pricing spinning reserves
violated the NYISO tariff. The Court also required FERC to
determine whether the exclusion from the non-spinning market of
a generating facility known as Blenheim-Gilboa and resources
located in western New York also constituted a tariff violation
and/or whether these exclusions enabled NYISO to use its
Temporary Extraordinary Procedure, or TEP, authority to require
refunds. On March 4, 2005, FERC issued an order stating
that no refunds would be required for the tariff violation
associated with the pricing of spinning reserves. In the order,
FERC also stated that the exclusion of the Blenheim-Gilboa
facility and western reserves from the non-spinning market was
not a market flaw and NYISO was correct not to use its TEP
authority to revise the prices in this market. Motions for
rehearing of the Order must be filed by April 3, 2005. If
the March 4, 2005 order is reversed and refunds are
required, NRG entities which may be affected include NRG Power
Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill
Power LLC.
44
Although non-NRG-related entities would share responsibility for
payment of any such refunds under the petitioners theory
the cumulative exposure to our above-listed entities could
exceed $23 million.
Connecticut Light & Power Company v. NRG
Power Marketing, Inc., Docket No. 3:01-CV-2373 (AWT),
U.S. District Court, District of Connecticut (filed on
November 28, 2001). Connecticut Light & Power
Company, or CL&P, sought recovery of amounts it claimed it
was owed for congestion charges under the terms of an
October 29, 1999, contract between the parties. CL&P
withheld approximately $30 million from amounts owed to NRG
Power Marketing, Inc., or PMI, and PMI counterclaimed. CL&P
filed its motion for summary judgment to which PMI filed a
response on March 21, 2003. By reason of the stay issued by
the bankruptcy court, the court has not ruled on the pending
motion. On November 6, 2003, the parties filed a joint
stipulation for relief from the stay in order to allow the
proceeding to go forward that was promptly granted. PMI cannot
estimate at this time the overall exposure for congestion
charges for the full term of the contract.
Connecticut Light & Power Company v.
NRG Energy, Inc., Federal Energy Regulatory Commission
Docket No. EL03-10-000-Station Service Dispute (filed
October 9, 2002); Binding Arbitration. On
July 1, 1999, Connecticut Light & Power Company,
or CL&P, and the Company agreed that we would purchase
certain CL&P generating facilities. The transaction closed
on December 14, 1999, whereupon NRG Energy took
ownership of the facilities. CL&P began billing NRG Energy
for station service power and delivery services provided to the
facilities and NRG Energy refused to pay asserting that the
facilities self-supplied their station service needs. On
October 9, 2002, Northeast Utilities Services Company, on
behalf of itself and CL&P, filed a complaint at FERC seeking
an order requiring NRG Energy to pay for station service
and delivery services. On December 20, 2002, FERC issued an
Order finding that at times when NRG Energy is not able to
self-supply its station power needs, there is a sale of station
power from a third-party and retail charges apply. CL&P
renewed its demand for payment which was again refused by
NRG Energy. In August 2003, the parties agreed to submit
the dispute to binding arbitration. The parties each selected
one respective arbitrator. A neutral arbitrator cannot be
selected until the party-appointed arbitrators have been given a
mutually agreed upon description of the dispute, which has yet
to occur. Once the neutral arbitrator is selected, a decision is
required within 90 days unless otherwise agreed by the
parties. The potential loss inclusive of amounts paid to
CL&P and accrued could exceed $6 million.
The State of New York and Erin M. Crotty, as Commissioner
of the New York State Department of Environmental
Conservation v. Niagara Mohawk Power Corporation
et al., U.S. District Court for the Western
District of New York, Civil Action No. 02-CV-002S. In
January 2002, the New York State Department of Environmental
Conservation, or NYSDEC, sued Niagara Mohawk Power Corporation,
or NiMo, and us in federal court in New York. The complaint
asserted that projects undertaken at our Huntley and Dunkirk
plants by NiMo, the former owner of the facilities, required
preconstruction permits pursuant to the Clean Air Act and that
the failure to obtain these permits violated federal and state
laws. On January 11, 2005, we reached agreement with the
State of New York and the NYSDEC to settle this matter. The
settlement requires the reduction of sulfur dioxide
(SO2) by over 86 percent and nitrogen oxide by
over 80 percent in aggregate at the Huntley and Dunkirk
plants. To do so, units 63 and 64 at Huntley will be retired
after receiving the appropriate regulatory approvals. Units 65
and 66 will be retired eighteen months later. We also agreed to
limits on the transfer of certain federal SO2
allowances. We are not subject to any penalty as a result of the
settlement. Through the end of the decade, we expect that our
ongoing compliance with the emissions limits set out in the
settlement will be achieved through capital expenditures already
planned. This includes conversion to low sulfur western coal at
the Huntley and Dunkirk plants that will be completed by spring
2006.
Niagara Mohawk Power Corporation v. NRG Energy,
Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme
Court, State of New York, County of Onondaga, Case
No. 2001-4372 (filed on July 13, 2001). NiMo filed
suit in state court in New York seeking a declaratory judgment
with respect to its obligations to indemnify us under the asset
sales agreement. We asserted that NiMo is obligated to indemnify
us for any related compliance costs associated with resolution
of the above referenced NYSDEC enforcement action. On
October 18, 2004, the parties reached a confidential
settlement.
45
Niagara Mohawk Power Corporation v. Dunkirk Power
LLC, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG
Huntley Operations, Inc., Oswego Power LLC and NRG Oswego
Operations, Inc., Supreme Court, Erie County, Index
No. 1-2000-8681 Station Service Dispute
(filed October 2, 2000). NiMo seeks to recover damages
less payments received through the date of judgment, as well as
any additional amounts due and owing, for electric service
provided to the Dunkirk Plant after September 18, 2000.
NiMo claims that we failed to pay retail tariff amounts for
utility services commencing on or about June 11, 1999, and
continuing to September 18, 2000, and thereafter. NiMo
alleged breach of contract, suit on account, violation of
statutory duty and unjust enrichment claims. Prior to trial, the
parties entered into a Stipulation and Order filed
August 9, 2002, consolidating this action with two other
actions against the Huntley and Oswego subsidiaries, both of
which cases assert the same claims and legal theories. On
October 8, 2002, a Stipulation and Order was filed staying
this action pending submission to FERC of some or all of the
disputes in the action. The potential loss inclusive of amounts
paid to NiMo and accrued is approximately $23.2 million.
Niagara Mohawk Power Corporation v. Huntley Power
LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc.,
Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego
Operations, Inc., Case Filed November 26, 2002 in
Federal Energy Regulatory Commission Docket No. EL
03-27-000. This is the companion action to the above
referenced action filed by NiMo at FERC asserting the same
claims and legal theories. On November 19, 2004, FERC
denied NiMos petition and ruled that the Huntley, Dunkirk
and Oswego plants could net their service station obligations
over a 30 calendar day period from the day NRG Energy
acquired the facilities. In addition, FERC ruled that neither
NiMo nor the New York Public Service Commission could impose a
retail delivery charge on the NRG facilities because they are
interconnected to transmission and not to distribution. NiMo
filed a motion for rehearing, on which FERC has not ruled.
U.S. Environmental Protection Agency Request for
Information under Section 114 of the Clean Air Act.
On January 27, 2004, Louisiana Generating, LLC and Big
Cajun II received a request under Section 114 of the
federal Clean Air Act from U.S. EPA Region 6 seeking
information primarily relating to physical changes made at Big
Cajun II. Louisiana Generating, LLC and Big Cajun II
submitted several responses to the EPA. On February 15,
2005, Louisiana Generating, LLC received a Notice of Violation
alleging violations of the New Source Review provisions of the
Clean Air Act from 1998 through the Notice of Violation date. We
cannot predict the outcome of this matter at this time.
Itiquira Energetica, S.A. Our Brazilian project
company, Itiquira Energetica S.A., the owner of a 156 MW
hydro project in Brazil, is in arbitration with the former EPC
contractor for the project, Inepar Industria e Construcoes, or
Inepar. The dispute was commenced by Itiquira in
September of 2002 and pertains to certain matters arising under
the former EPC contract. Itiquira seeks
U.S. $40 million and asserts that Inepar breached the
contract and caused damages to Itiquira by (i) failing to
meet milestones for substantial completion; (ii) failing to
provide adequate resources to meet such milestones;
(iii) failing to pay subcontractors amounts due; and
(iv) being insolvent. Inepar seeks
U.S. $10 million and alleges that Itiquira breached
the contract and caused damages to Inepar by failing to
recognize events of force majeure as grounds for excused delay
and extensions of scope of services and material under the
contract. An expert investigation was ordered by an arbitration
panel to cover technical and accounting issues and expert
testimony was presented at two subsequent hearings. Final
written arguments from the parties were submitted on
January 28, 2005. The court of arbitration is expected to
issue a decision by the close of the second quarter of 2005.
CFTC Trading Inquiry. On July 1, 2004, the
CFTC filed a civil complaint against us in Minnesota federal
district court, alleging false reporting of natural gas trades
from August 2001 to May 2002, and seeking an injunction against
future violations of the Commodity Exchange Act. On
July 23, 2004, we filed a motion with the bankruptcy court
to enforce the injunction provisions of the NRG plan of
reorganization against the CFTC. Thereafter, we filed with the
Minnesota federal district court a motion to dismiss. On
November 17, 2004, a Bankruptcy Court hearing was held on
the CFTCs motion to reinstate its expunged bankruptcy
claim, and on our motion to enforce the injunction contained in
our plan of reorganization in order to preclude the CFTC from
continuing its Minnesota federal court action. On
December 6, 2004, a federal magistrate judge in Minnesota
issued a report and recommendation that our motion to dismiss be
granted by the district court. On March 16, 2005, the
federal district court in Minnesota adopted the magistrate
judges report and
46
recommendations and dismissed the case. The Bankruptcy Court has
yet to schedule for a hearing or rule on the CFTCs pending
motion to reinstate its expunged claim.
In addition to the foregoing, we are parties to other litigation
or legal proceedings. See Market Developments in the
various regions in Item 1 Business
Power Generation for additional discussion on regulatory legal
proceedings.
The Company believes that it has valid defenses to the legal
proceedings and investigations described above and intends to
defend them vigorously. However, litigation is inherently
subject to many uncertainties. There can be no assurance that
additional litigation will not be filed against the Company or
its subsidiaries in the future asserting similar or different
legal theories and seeking similar or different types of damages
and relief. Unless specified above, the Company is unable to
predict the outcome these legal proceedings and investigations
may have or reasonably estimate the scope or amount of any
associated costs and potential liabilities. An unfavorable
outcome in one or more of these proceedings could have a
material impact on the Companys consolidated financial
position, results of operations or cash flows. The Company also
has indemnity rights for some of these proceedings to reimburse
the Company for certain legal expenses and to offset certain
amounts deemed to be owed in the event of an unfavorable
litigation outcome.
Disputed Claims Reserve
As part of the NRG plan of reorganization, we have funded a
disputed claims reserve for the satisfaction of certain general
unsecured claims that were disputed claims as of the effective
date of the plan. Under the terms of the plan, to the extent
such claims are resolved now that we have emerged from
bankruptcy, the claimants will be paid from the reserve on the
same basis as if they had been paid out in the bankruptcy. That
means that their allowed claims will be reduced to the same
recovery percentage as other creditors would have received and
will be paid in pro rata distributions of cash and common stock.
We believe we have funded the disputed claims reserve at a
sufficient level to settle the remaining unresolved proofs of
claim we received during the bankruptcy proceedings. However, to
the extent the aggregate amount of these payouts of disputed
claims ultimately exceeds the amount of the funded claims
reserve, we are obligated to provide additional cash, notes and
common stock to the claimants. We will continue to monitor our
obligation as the disputed claims are settled. If excess funds
remain in the disputed claims reserve after payment of all
obligations, such amounts will be reallocated to the creditor
pool. We have contributed common stock and cash to an escrow
agent to complete the distribution and settlement process. Since
we have surrendered control over the common stock and cash
provided to the disputed claims reserve, we recognized the
issuance of the common stock as of December 6, 2003 and
removed the cash amounts from our balance sheet. Similarly, we
removed the obligations relevant to the claims from our balance
sheet when the common stock was issued and cash contributed.
|
|
Item 4 |
Submission of Matters to a Vote of Security Holders |
No matters were considered during the fourth quarter of 2004.
PART II
|
|
Item 5 |
Market for Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities |
Market Information and Holders
In connection with the consummation of our reorganization, on
December 5, 2003, all shares of our old common stock were
canceled and 100,000,000 shares of new common stock of
NRG Energy were distributed pursuant to such plan in
accordance with Section 1145 of the bankruptcy code to the
holders of certain classes of claims. We received no proceeds
from such issuance. A certain number of shares of common stock
were
47
issued and placed in the Disputed Claims Reserve for
distribution to holders of disputed claims as such claims are
resolved or settled. See Item 3 Legal
Proceedings Disputed Claims Reserve. In the event
our disputed claims reserve is inadequate, it is possible we
will have to issue additional shares of our common stock to
satisfy such pre-petition claims or contribute additional cash
proceeds. Our authorized capital stock consists of
500,000,000 shares of NRG Energy common stock and
10,000,000 shares of preferred stock. A total of
4,000,000 shares of our common stock are available for
issuance under our long-term incentive plan. We have also filed
with the Secretary of State of Delaware a Certificate of
Designation of our 4% Convertible Perpetual Preferred
Stock, or Preferred Stock.
Our common stock is listed on the New York Stock Exchange and
has been assigned the symbol: NRG. We have submitted to the New
York Stock Exchange our annual certificate from our Chief
Executive Officer certifying that he is not aware of any
violation by us of New York Stock Exchange corporate governance
listing standards. The high and low sales prices, as well as the
closing price for our common stock on a per share basis for 2004
and the period December 6, 2003 to December 31, 2003
are set forth below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
Fourth |
|
Third |
|
Second |
|
First |
|
December 6 - |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
December 31, |
Common Stock Price |
|
2004 |
|
2004 |
|
2004 |
|
2004 |
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
High
|
|
$ |
36.18 |
|
|
$ |
28.43 |
|
|
$ |
24.80 |
|
|
$ |
22.50 |
|
|
$ |
23.05 |
|
Low
|
|
$ |
26.00 |
|
|
$ |
24.10 |
|
|
$ |
19.17 |
|
|
$ |
18.10 |
|
|
$ |
18.10 |
|
Closing
|
|
$ |
36.05 |
|
|
$ |
26.94 |
|
|
$ |
24.80 |
|
|
$ |
22.20 |
|
|
$ |
21.90 |
|
NRG Energy had 87,041,935 shares outstanding as of
December 31, 2004. As of March 10, 2005, there were
11,182 common shareholders of record.
Dividends
We have not declared or paid dividends on our common stock and
the amount of dividends is currently limited by our credit
agreements.
Recent Sale of Unregistered Securities; Repurchase of Common
Stock
Upon emergence from chapter 11, investment partnerships
managed by MatlinPatterson LLC, or MatlinPatterson, owned
approximately 21.5 million (21.5%) of our common shares. On
December 21, 2004, using existing cash we purchased
13 million shares of common stock from MatlinPatterson at a
purchase price of $31.16 per share. In addition to a
reduction in total shares of common stock outstanding by
13 million, the share repurchase resulted in (i) the
reduction of MatlinPattersons share ownership to less than
10% from the prior 21.5%, (ii) termination of
MatlinPattersons registration rights, and
(iii) resignation from our Board of Directors of three
directors affiliated with MatlinPatterson. Our Boards
Governance and Nominating Committee is in the process of
identifying appropriate independent directors to fill the
vacancies.
The following table summarizes the stock repurchased by
NRG Energy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number of Shares |
|
|
|
|
|
|
|
|
Purchased as Part of |
|
Maximum Number of |
|
|
Total Number of |
|
Average Price |
|
Publicly Announced |
|
Shares that May Yet Be |
Period |
|
Shares Purchased |
|
Paid Per Share |
|
Plans |
|
Purchased Under the Plans |
|
|
|
|
|
|
|
|
|
December 27, 2004
|
|
|
13,000,000* |
|
|
$ |
31.16 |
|
|
|
none |
|
|
|
N/A |
|
|
|
* |
13,000,000 shares were purchased other than through a
publicly announced plan. The purchase was made in a negotiated
transaction. |
Redemption and Repurchase of Second Priority Notes
Proceeds from the sale of the Preferred Stock were used to
redeem $375.0 million of our Second Priority Notes on
February 4, 2005. In January 2005 and in March 2005, we
used existing cash to purchase, at market prices,
$25 million and $15.8 million, respectively, in face
value of our Second Priority Notes. These notes were assumed by
NRG Energy and therefore remain outstanding.
48
Securities Authorized for Issuance Under Equity Compensation
Plans
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
(b) |
|
(c) |
|
|
|
|
|
|
Number of Securities |
|
|
|
|
|
|
Remaining Available |
|
|
Number of Securities |
|
|
|
for Future Issuance |
|
|
to be Issued Upon |
|
Weighted-Average Exercise |
|
Under Compensation |
|
|
Exercise of |
|
Price of Outstanding |
|
Plans (Excluding |
|
|
Outstanding Options, |
|
Options, Warrants and |
|
Securities Reflected |
Plan Category |
|
Warrants and Rights |
|
Rights |
|
in Column (a)) |
|
|
|
|
|
|
|
Equity compensation plans approved by security holders
|
|
|
1,904,026 |
|
|
$ |
22.34 |
|
|
|
2,053,294* |
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
n/a |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
1,904,026 |
|
|
$ |
22.34 |
|
|
|
2,053,294* |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
The NRG Energy, Inc. Long-Term Incentive Plan became
effective upon our emergence from bankruptcy. The Long-Term
Incentive Plan, which was adopted in connection with the NRG
plan of reorganization, was approved by our stockholders on
August 4, 2004. The Long-Term Incentive Plan provides for
grants of stock options, stock appreciation rights, restricted
stock, performance awards, deferred stock units and dividend
equivalent rights. Our directors, officers and employees, as
well as other individuals performing services for, or to whom an
offer of employment has been extended by us, are eligible to
receive grants under the Long-Term Incentive Plan. A total of
4,000,000 shares of our common stock are available for
issuance under the Long-Term Incentive Plan. The purpose of the
Long-Term Incentive Plan is to promote our long-term growth and
profitability by providing these individuals with incentives to
maximize stockholder value and otherwise contribute to our
success and to enable us to attract, retain and reward the best
available persons for positions of responsibility. The
Compensation Committee of our Board of Directors administers the
Long-Term Incentive Plan. There were 2,053,294 and
3,367,249 shares of common stock remaining available for
grants of stock options under our Long-Term Incentive Plan as of
December 31, 2004 and 2003, respectively. |
49
|
|
Item 6 |
Selected Financial Data |
The following table presents our selected financial data. The
data included in the following table has been restated to
reflect the assets, liabilities and results of operations of
certain projects that have met the criteria for treatment as
discontinued operations. For additional information refer to
Item 15 Note 6 to the Consolidated
Financial Statements. This historical data should be read in
conjunction with the Consolidated Financial Statements and the
related notes thereto in Item 15 and
Managements Discussion and Analysis of Financial
Condition and Results of Operations in Item 7. Due to
the adoption of Fresh Start reporting as of December 5,
2003, the Successor Companys post Fresh Start balance
sheet and statement of operations have not been prepared on a
consistent basis with the Predecessor Companys financial
statements and are not comparable in certain respects to the
financial statements prior to the application of Fresh Start
reporting.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
Predecessor Company |
|
|
|
|
|
|
|
Year Ended |
|
|
December 6 - |
|
January 1 - |
|
Year Ended December 31, |
|
|
December 31, |
|
|
December 31, |
|
December 5, |
|
|
|
|
2004 |
|
|
2003 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands, except per share amounts) |
Revenues from majority-owned operations
|
|
$ |
2,361,424 |
|
|
|
$ |
138,490 |
|
|
$ |
1,798,387 |
|
|
$ |
1,938,293 |
|
|
$ |
2,085,350 |
|
|
$ |
1,664,980 |
|
Corporate relocation charges
|
|
|
16,167 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganization, restructuring and impairment charges
|
|
|
31,271 |
|
|
|
|
2,461 |
|
|
|
435,400 |
|
|
|
2,563,060 |
|
|
|
|
|
|
|
|
|
Fresh start reporting adjustments
|
|
|
|
|
|
|
|
|
|
|
|
(4,118,636 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Legal settlement
|
|
|
|
|
|
|
|
|
|
|
|
462,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,962,309 |
|
|
|
|
122,328 |
|
|
|
(1,475,523 |
) |
|
|
4,321,385 |
|
|
|
1,703,531 |
|
|
|
1,308,589 |
|
Write downs and losses on equity method investments
|
|
|
(16,270 |
) |
|
|
|
|
|
|
|
(147,124 |
) |
|
|
(200,472 |
) |
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
162,145 |
|
|
|
|
11,405 |
|
|
|
2,949,078 |
|
|
|
(2,788,452 |
) |
|
|
210,502 |
|
|
|
149,729 |
|
Income/(loss) from discontinued operations, net
|
|
|
23,472 |
|
|
|
|
(380 |
) |
|
|
(182,633 |
) |
|
|
(675,830 |
) |
|
|
54,702 |
|
|
|
33,206 |
|
Net income/(loss)
|
|
|
185,617 |
|
|
|
|
11,025 |
|
|
|
2,766,445 |
|
|
|
(3,464,282 |
) |
|
|
265,204 |
|
|
|
182,935 |
|
Income/(loss) from continuing operations per weighted average
share basic and diluted
|
|
$ |
1.62 |
|
|
|
$ |
.11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
7,830,028 |
|
|
|
|
9,244,987 |
|
|
|
N/A |
|
|
|
10,896,851 |
|
|
|
12,915,222 |
|
|
|
5,986,289 |
|
Long-term debt, including current maturities
|
|
$ |
3,766,118 |
|
|
|
$ |
4,129,011 |
|
|
|
N/A |
|
|
$ |
7,782,648 |
|
|
$ |
6,857,055 |
|
|
$ |
3,194,340 |
|
The following table provides the detail of our revenues from
majority-owned operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
Predecessor Company |
|
|
|
|
|
|
|
Year Ended |
|
|
December 6 - |
|
January 1 - |
|
Year Ended December 31, |
|
|
December 31, |
|
|
December 31, |
|
December 5, |
|
|
|
|
2004 |
|
|
2003 |
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Energy and energy-related
|
|
$ |
1,378,490 |
|
|
|
$ |
78,018 |
|
|
$ |
992,626 |
|
|
$ |
1,183,514 |
|
|
$ |
1,376,044 |
|
|
$ |
1,091,115 |
|
Capacity
|
|
|
612,294 |
|
|
|
|
39,955 |
|
|
|
565,965 |
|
|
|
553,321 |
|
|
|
490,315 |
|
|
|
405,697 |
|
Alternative energy
|
|
|
175,715 |
|
|
|
|
12,064 |
|
|
|
115,911 |
|
|
|
97,712 |
|
|
|
161,845 |
|
|
|
92,671 |
|
O & M fees
|
|
|
20,852 |
|
|
|
|
1,135 |
|
|
|
12,942 |
|
|
|
14,413 |
|
|
|
15,789 |
|
|
|
10,073 |
|
Other
|
|
|
174,073 |
|
|
|
|
7,318 |
|
|
|
110,943 |
|
|
|
89,333 |
|
|
|
41,357 |
|
|
|
65,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues from majority-owned operations
|
|
$ |
2,361,424 |
|
|
|
$ |
138,490 |
|
|
$ |
1,798,387 |
|
|
$ |
1,938,293 |
|
|
$ |
2,085,350 |
|
|
$ |
1,664,980 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
Energy and energy-related revenue consists of revenues received
from third parties for sales in the day-ahead and real-time
markets, as well as bilateral sales. In addition, this category
includes day-ahead and real-time operating revenues.
Capacity revenue consists of revenues received from a third
party at either the market or negotiated contract rates for
making installed generation capacity available in order to
satisfy system integrity and reliability requirements. In
addition, capacity revenues includes revenues received under
tolling arrangements which entitle third parties to dispatch our
facilities and assume title to the electrical generation
produced from that facility.
Alternative energy revenue consists of revenues received from
the sale of steam, hot and chilled water generally produced at a
central district energy plant and sold to commercial,
governmental and residential buildings for space heating,
domestic hot water heating and air conditioning. Alternative
energy revenue includes the sale of high-pressure steam produced
and delivered to industrial customers that is used as part of an
industrial process. In addition, alternative revenue includes
revenues received from the processing of municipal solid waste
into refuse derived fuel that is sold to a third party to be
used as fuel in the generation of electricity.
Operations and management, or O&M, fees consist primarily of
revenues received from providing certain unconsolidated
affiliates with management and operational services generally
under long-term operating agreements.
Other revenues consist of miscellaneous other revenues derived
from the sale of natural gas, recovery of incurred costs under
reliability agreements and revenues received under leasing
arrangements. In addition, we also generate revenues from
maintenance, the sale of ancillary services excluding day-ahead
and real-time operating revenues and by entering into certain
financial transactions. Ancillary revenues are derived from the
sale of energy related products associated with the generation
of electrical energy such as spinning reserves, reactive power
and other similar products. Also included in other revenues are
revenues derived from financial transactions
(derivatives) relating to the sale of energy or fuel which
do not require the physical delivery of the underlying commodity.
|
|
Item 7 |
Managements Discussion and Analysis of Financial
Condition and Results of Operations |
Overview
NRG Energy, Inc., or NRG Energy, the
Company, we, our, or
us is a wholesale power generation company,
primarily engaged in the ownership and operation of power
generation facilities, the transacting in and trading of fuel
and transportation services and the marketing and trading of
energy, capacity and related products in the United States and
internationally. We have a diverse portfolio of electric
generation facilities in terms of geography, fuel type and
dispatch levels. Our principal domestic generation assets
consist of a diversified mix of natural gas-, coal- and
oil-fired facilities, representing approximately 40%, 31% and
29% of our total domestic generation capacity, respectively. In
addition, 23% of our domestic generating facilities have dual or
multiple fuel capacity, which allows plants to dispatch with the
lowest cost fuel option.
Our two principal objectives are to maximize the operating
performance of our entire portfolio, and to protect and enhance
the market value of our physical and contractual assets through
the execution of asset-based risk management, marketing and
trading strategies within well-defined risk and liquidity
guidelines. We aggregate the assets in our core regions into
integrated businesses to serve the requirements of the
load-serving entities in our core markets. Our business involves
the reinvestment of capital in our existing assets for reasons
of repowering, expansion, environmental remediation, operating
efficiency, reliability programs, greater fuel optionality,
greater merit order diversity, enhanced portfolio effect or for
alternative use, among other reasons. Our business also may
involve acquisitions intended to complement the asset portfolios
in our core regions, and from time to time we may also consider
and undertake other merger and acquisition transactions that are
consistent with our strategy.
51
The wholesale energy industry entered a prolonged slump in 2001,
from which it is only beginning to emerge. We expect that
generally weak market conditions will continue for the
foreseeable future in many U.S. markets. We further expect
that the merchant power industry will continue to see corporate
restructuring, debt restructuring, and consolidation over the
coming years.
Asset Sales. We have substantially completed our
divestment of major non-core assets; however, as part of our
strategy, we plan to continue the selective divestment of
certain non-core assets. We have no current plans to market
actively any of our core assets, although our intention to
maximize over time the value of all of our assets could lead to
additional assets sales.
Discontinued Operations. We have classified certain
business operations, and gains/losses recognized on sale, as
discontinued operations for projects that were sold or have met
the required criteria for such classification pending final
disposition. Accounting regulations require that continuing
operations be reported separately in the income statement from
discontinued operations, and that any gain or loss on the
disposition of any such business be reported along with the
operating results of such business. Assets classified as
discontinued operations on our balance sheet as of
December 31, 2004 consist of the McClain project. All other
projects have been sold as of December 31, 2004.
Independent Registered Public Accounting Firm; Audit
Committee. PricewaterhouseCoopers LLP served as our
independent auditors from 1995 through 2003. On May 3,
2004, we announced that PricewaterhouseCoopers LLP had decided
not to stand for re-election as our independent auditor for the
year ended December 31, 2004. On May 24, 2004 the
Audit Committee of our Board of Directors appointed KPMG LLP as
our independent registered public accounting firm going forward,
and on August 4, 2004 our stockholders ratified the
appointment. PricewaterhouseCoopers LLP has consented to the
inclusion of their reports for the periods January 1, 2003
to December 5, 2003 and December 6, 2003 to
December 31, 2003 and for the year ended December 31,
2002. The Company intends to continue to request the consent of
PricewaterhouseCoopers LLP in future filings with the SEC when
deemed necessary.
Fresh Start Reporting. In connection with our emergence
from bankruptcy, we adopted Fresh Start Reporting on
December 5, 2003, in accordance with the requirements of
Statement of Position 90-7, Financial Reporting by
Entities in Reorganization Under the Bankruptcy Code,
or SOP 90-7. The application of SOP 90-7 resulted in
the creation of a new reporting entity. Under Fresh Start, our
reorganization value was allocated to our assets and liabilities
on a basis substantially consistent with purchase accounting in
accordance with SFAS No. 141. Accordingly, our
assets recorded values were adjusted to reflect their
estimated fair values upon adoption of Fresh Start. Any portion
of the reorganization value not attributable to specific assets
is an indefinite-lived intangible asset referred to as
reorganization value in excess of value of identifiable
assets and reported as goodwill. We did not record any
such amounts. As a result of adopting Fresh Start and emerging
from bankruptcy, our historical financial information is not
comparable to financial information for periods after our
emergence from bankruptcy.
Results of Operations
Upon our emergence from bankruptcy, we adopted the Fresh Start
provisions of SOP 90-7. Accordingly, the Reorganized NRG
statement of operations and statement of cash flows have not
been prepared on a consistent basis with the Predecessor
Companys financial statements and are not comparable in
certain respects to the financial statements prior to the
application of Fresh Start, therefore, the Predecessor
Companys and the Reorganized NRGs amounts are
discussed separately for comparison and analysis purposes,
herein.
52
The following table shows the percent of total revenue each
segment contributes to our total revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
|
Predecessor Company |
|
|
|
|
|
|
|
|
For the Year |
|
|
|
For the Period |
|
|
|
|
For the Period |
|
|
|
For the Year |
|
|
|
|
Ended |
|
Percent of |
|
December 6- |
|
Percent of |
|
|
January 1- |
|
Percent of |
|
Ended |
|
Percent of |
|
|
December 31, |
|
Total |
|
December 31, |
|
Total |
|
|
December 5, |
|
Total |
|
December 31, |
|
Total |
Segments |
|
2004 |
|
Revenue |
|
2003 |
|
Revenue |
|
|
2003 |
|
Revenue |
|
2002 |
|
Revenue |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
(In thousands) |
|
|
|
|
(In thousands) |
|
|
|
(In thousands) |
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
$ |
1,251,153 |
|
|
|
53.0 |
% |
|
$ |
69,191 |
|
|
|
50.0 |
% |
|
|
$ |
861,452 |
|
|
|
47.9 |
% |
|
$ |
964,196 |
|
|
|
49.7 |
% |
|
South Central
|
|
|
418,145 |
|
|
|
17.6 |
% |
|
|
26,609 |
|
|
|
19.2 |
% |
|
|
|
356,534 |
|
|
|
19.8 |
% |
|
|
388,023 |
|
|
|
20.0 |
% |
|
West Coast
|
|
|
2,469 |
|
|
|
0.1 |
% |
|
|
(268 |
) |
|
|
(0.2 |
)% |
|
|
|
23,956 |
|
|
|
1.3 |
% |
|
|
30,796 |
|
|
|
1.6 |
% |
|
Other North America
|
|
|
105,644 |
|
|
|
4.5 |
% |
|
|
5,377 |
|
|
|
3.9 |
% |
|
|
|
85,388 |
|
|
|
4.8 |
% |
|
|
81,521 |
|
|
|
4.2 |
% |
|
Australia
|
|
|
181,065 |
|
|
|
7.7 |
% |
|
|
11,947 |
|
|
|
8.6 |
% |
|
|
|
151,494 |
|
|
|
8.4 |
% |
|
|
170,761 |
|
|
|
8.8 |
% |
All Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other International
|
|
|
157,220 |
|
|
|
6.7 |
% |
|
|
13,082 |
|
|
|
9.4 |
% |
|
|
|
137,384 |
|
|
|
7.6 |
% |
|
|
108,379 |
|
|
|
5.6 |
% |
|
Alternative Energy
|
|
|
65,872 |
|
|
|
2.8 |
% |
|
|
3,852 |
|
|
|
2.8 |
% |
|
|
|
60,871 |
|
|
|
3.4 |
% |
|
|
69,030 |
|
|
|
3.6 |
% |
|
Non-Generation
|
|
|
186,425 |
|
|
|
7.9 |
% |
|
|
9,860 |
|
|
|
7.1 |
% |
|
|
|
129,063 |
|
|
|
7.2 |
% |
|
|
135,403 |
|
|
|
7.0 |
% |
|
Other
|
|
|
(6,569 |
) |
|
|
(0.3 |
)% |
|
|
(1,160 |
) |
|
|
(0.8 |
)% |
|
|
|
(7,755 |
) |
|
|
(0.4 |
)% |
|
|
(9,816 |
) |
|
|
(0.5 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Revenue
|
|
$ |
2,361,424 |
|
|
|
100.0 |
% |
|
$ |
138,490 |
|
|
|
100.0 |
% |
|
|
$ |
1,798,387 |
|
|
|
100.0 |
% |
|
$ |
1,938,293 |
|
|
|
100.0 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides operating income by segment for the
year ended December 31, 2004.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
West |
|
Other North |
|
|
|
|
|
|
|
|
Northeast |
|
Central |
|
Coast |
|
America |
|
Australia |
|
All Other |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Energy revenue
|
|
$ |
853,454 |
|
|
$ |
219,112 |
|
|
$ |
9,276 |
|
|
$ |
27,816 |
|
|
$ |
159,381 |
|
|
$ |
109,451 |
|
|
$ |
1,378,490 |
|
Capacity revenue
|
|
|
264,624 |
|
|
|
183,483 |
|
|
|
(3,709 |
) |
|
|
84,097 |
|
|
|
|
|
|
|
83,799 |
|
|
|
612,294 |
|
Alternative revenue
|
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
1,748 |
|
|
|
|
|
|
|
173,918 |
|
|
|
175,715 |
|
O & M fees
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
186 |
|
|
|
|
|
|
|
20,668 |
|
|
|
20,852 |
|
Other revenue
|
|
|
133,026 |
|
|
|
15,550 |
|
|
|
(3,096 |
) |
|
|
(8,203 |
) |
|
|
21,684 |
|
|
|
15,112 |
|
|
|
174,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
1,251,153 |
|
|
|
418,145 |
|
|
|
2,469 |
|
|
|
105,644 |
|
|
|
181,065 |
|
|
|
402,948 |
|
|
|
2,361,424 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
859,769 |
|
|
|
294,215 |
|
|
|
10,842 |
|
|
|
57,686 |
|
|
|
161,960 |
|
|
|
321,104 |
|
|
|
1,705,576 |
|
Depreciation and amortization
|
|
|
72,665 |
|
|
|
62,458 |
|
|
|
800 |
|
|
|
21,842 |
|
|
|
24,027 |
|
|
|
27,503 |
|
|
|
209,295 |
|
Corporate relocation charges
|
|
|
11 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,155 |
|
|
|
16,167 |
|
Reorganization items
|
|
|
180 |
|
|
|
976 |
|
|
|
|
|
|
|
142 |
|
|
|
|
|
|
|
(14,688 |
) |
|
|
(13,390 |
) |
Restructuring and impairment charges
|
|
|
247 |
|
|
|
2,909 |
|
|
|
|
|
|
|
26,505 |
|
|
|
|
|
|
|
15,000 |
|
|
|
44,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
$ |
318,281 |
|
|
$ |
57,586 |
|
|
$ |
(9,173 |
) |
|
$ |
(531 |
) |
|
$ |
(4,922 |
) |
|
$ |
37,874 |
|
|
$ |
399,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, 2004 Compared to the
Year Ended December 31, 2003 |
For the year ended December 31, 2004, we recorded net
income of $185.6 million, or $1.85 per weighted
average share of diluted common stock. These favorable results
occurred despite a challenging market environment in 2004.
Unseasonably mild weather, high volatility on forward markets
and disappointing spot power prices summarize 2004s
events. The year started with colder than normal weather
arriving in January but unseasonably mild weather characterized
the period from March thru December which dampened energy prices
in North America. The National Oceanic Atmospheric Agency, or
NOAA, has ranked the mean average temperatures over the past
110 years by season for each of the lower 48 states.
The year 2004 started
53
with the winter being colder than normal in the east coast
followed by a spring, summer and fall which were among the
mildest in the last 110 years throughout most of the United
States. Although mild weather in the North America market kept
spot market on-peak power prices low throughout most of the
year, relatively high gas and oil prices kept spark spreads on
coal-based assets positive.
The overall perception that there would be significant
production losses due to Hurricane Ivan ignited a strong
pre-heating season rally in natural gas futures during the early
fourth quarter. While power prices tracked changes in natural
gas prices, this movement was not one for one. As a result, our
spark spreads on coal-based generation increased dramatically
with the fall 2004 changes in gas prices. During this period we
sold forward 2005 power locking in these spark spreads. Forward
power prices have fallen considerably from the highs set in
October, and many of those forward sales, which were
marked-to-market through earnings, significantly contributed to
the $57.3 million unrealized gain recorded in revenue for
the year ended December 31, 2004 and as more fully
described in Note 16 to the financial statements.
As indicated above, our 2004 results were favorably impacted by
the cold weather in January. Additionally, the Northeasts
income results for the year were positively impacted by the
$57.3 million of unrealized gains associated with forward
sale transactions supporting our Northeast assets. The majority
of the unrealized gains relate to forward sales of electricity
which will be realized in 2005. These gains were offset by our
South Central regions results, which were negatively
impacted by an unplanned outage in the fourth quarter forcing us
to purchase power to meet our contract supply obligations.
Impairment charges of $44.7 million negatively impacted net
income; of which $26.5 million relates to the Kendall
asset. Our results were also favorably impacted by the
FERC-approved settlement agreement between NRG Energy and
Connecticut Light & Power, or CL&P, and others
concerning the congestion and losses obligation associated with
a prior standard offer service contract, whereby we received
$38.4 million in settlement proceeds in July 2004. The 2004
results were also positively impacted by $159.8 million in
equity earnings of unconsolidated affiliates including
$68.9 million from our interest in West Coast Power which
benefited from warmer than normal temperatures during the year.
During the period December 6, 2003 through
December 31, 2003, we recognized net income of
$11.0 million or $0.11 per share of common stock. Net
income was directly attributable to a number of factors some of
which are discussed below. From an overall operational
perspective our facilities were profitable during this period.
Our results were adversely impacted by our having to continue to
satisfy the standard offer service contract that we entered into
with CL&P in 2000. As a result of our inability to terminate
this contract during our bankruptcy proceeding, we continued to
be exposed to losses under this contract. These losses were
incurred, as we were unable to satisfy the requirements of this
contract at a price/cost below the contracted sales price. Upon
our adoption of Fresh Start, we recorded at fair value, all
assets and liabilities on our opening balance sheet and
accordingly we recorded as an obligation the fair value of the
CL&P contract. During the period December 6, 2003
through December 31, 2003, we recognized as revenues the
entire fair value of this contract effectively offsetting the
actual losses incurred under this contract. The CL&P
contract terminated on December 31, 2003.
During the period January 1, 2003 through December 5,
2003, we recorded net income of $2.8 billion. Net income
for the period is directly attributable to our emerging from
bankruptcy and adopting the Fresh Start provisions of
SOP 90-7. Upon the confirmation of our Plan of
Reorganization and our emergence from bankruptcy, we were able
to remove significant amounts of long-term debt and other
pre-petition obligations from our balance sheet. Accordingly, as
part of net income, we recorded a net gain of $3.9 billion
(comprised of a $4.1 billion gain from continuing
operations and a $0.2 billion loss from discontinued
operations) as the impact of our adopting Fresh Start in our
statement of operations. $6.0 billion of this amount is
directly related to the forgiveness of debt and settlement of
substantial amounts of our pre-petition obligations upon our
emergence from bankruptcy. In addition to the removal of
substantial amounts of pre-petition debt and other obligations
from our balance sheet, we also revalued our assets and
liabilities to fair value. Accordingly, we substantially wrote
down the value of our fixed assets. We recorded a net
$1.6 billion charge related to the revaluation of our
assets and liabilities within the Fresh Start Reporting
adjustment line of our consolidated
54
statement of operations. In addition to our adjustments related
to our emergence from bankruptcy, we also recorded substantial
charges related to other items such as the settlement of certain
outstanding litigation in the amount of $462.6 million,
write downs and losses on the sale of equity investments of
$147.1 million, advisor costs and legal fees directly
attributable to our being in bankruptcy of $197.8 million
and $237.6 million of other asset impairment and
restructuring costs incurred prior to our filing for bankruptcy.
Net income for the period January 1, 2003 through
December 5, 2003 was favorably impacted by our not
recording interest expense on substantial amounts of corporate
level debt while we were in bankruptcy and by the continued
favorable results experienced by our equity investments.
|
|
|
Revenues from Majority-Owned Operations |
Our revenues from majority-owned operations were
$2.4 billion for the year ended December 31, 2004
which included $1.4 billion of energy revenues,
$612.3 million of capacity revenues, $175.7 million of
alternative energy revenues, $20.8 million of O&M fees
and $174.1 million of other revenues, which include
$57.3 million of unrealized gains associated with financial
sales transactions of electricity, which are marked to market,
$22.4 million from ancillary service revenues and the
remainder related to financial and physical gas sales and
non-cash contract amortization resulting from fresh start
accounting and other miscellaneous revenue items.
Revenues from majority-owned operations for the year ended
December 31, 2004, were driven primarily by our North
American operations, primarily our Northeast facilities. Our
wholly-owned domestic Northeast power generation operations
significantly contributed to our energy revenues. Our
wholly-owned North America assets generated approximately
29.0 million megawatt hours during the year 2004 with the
Northeast region representing 45.6% of these megawatt hours. Of
the total $1.4 billion in energy revenues, the Northeast
region represented 62%. Our energy revenues were favorably
impacted by the FERC-approved settlement agreement between us
and CL&P and others, whereby we received $38.4 million
in settlement proceeds in July 2004. These settlement proceeds
are included in the All Other segment in the energy revenue
category. South Centrals energy revenues are driven by our
ability to sell merchant energy, which is dependent upon
available generation from our coal-based Louisiana Generating
company after serving our co-op customer and long-term customer
load obligations. Since our load obligation is primarily
residential load, our merchant opportunities are largely
available in the off-peak hours of the day. Our Australian
operations were favorably impacted by strong market prices
driven by gas restrictions in January, record high temperatures
in February and March, and favorable foreign exchange movements.
Our capacity revenues are largely driven by our Northeast and
South Central facilities. Our South Central and New York City
assets earned 30% and 26% of our total capacity revenues,
respectively. In the Northeast, our Connecticut facilities
continue to benefit from the cost-based reliability must-run, or
RMR agreements, which were authorized by FERC as of
January 17, 2004 and approved by FERC on January 27,
2005. The agreements entitle us to approximately
$7.1 million of capacity revenues per month until
January 1, 2006, the LICAP implementation date. In the
South Central region, our long-term contracts provide for
capacity payments. Other North American capacity revenues were
generated by our Kendall operation, which had a long-term
tolling agreement. During this period we also experienced a
favorable impact on our revenues due to the mark-to-market on
certain of our derivative contracts wherein we have recognized
$57.3 million in unrealized gains. This gain is related to
our Northeast assets and is included in Other Revenue. Also
included in Other Revenue in the Northeast are the cost
reimbursement funds under the RMR agreement for our Connecticut
assets. Our revenues during this period include net charges of
$35.3 million of non-cash amortization of the fair values
of various executory contracts recorded on our balance sheet
upon our adoption of the Fresh Start provisions of SOP 90-7
in December 2003.
Our revenues from majority-owned operations were
$138.5 million for the period December 6, 2003 through
December 31, 2003.
55
Revenues from majority-owned operations were $1.8 billion
for the period January 1, 2003 through December 5,
2003 and include $992.6 million of energy revenues,
$566.0 million of capacity revenues, $115.9 million of
alternative energy, $12.9 million of O&M fees and
$110.9 million of other revenues which include financial
and physical gas sales, sales from our Schkopau facility and
NEPOOL expense reimbursements. Revenues from majority-owned
operations during the period ended December 5, 2003, were
driven primarily by our North American operations and to a
lesser degree by our international operations, primarily
Australia. Our domestic Northeast and South Central power
generation operations significantly contributed to our revenues
due primarily to favorable market prices resulting from strong
fuel and electricity prices. Our Australian operations were
favorably impacted by foreign exchange rates. During this period
we also experienced an unfavorable impact on our revenues due to
continued losses on our CL&P standard offer contract and the
mark-to-market on certain of our derivatives.
|
|
|
Cost of Majority-Owned Operations |
Our cost of majority-owned operations for the year ended
December 31, 2004 was $1.5 billion or 63.3% of
revenues from majority-owned operations. Cost of majority-owned
operations consist of $1.008 billion of cost of energy
(primarily fuel and purchased energy costs), or 42.7% of
revenues from majority-owned operations and $486.1 million
of operating expenses, or 20.6% of revenues from majority-owned
operations. Operating expenses consist of $208.5 million of
labor related costs, $236.7 million of operating and
maintenance costs, $38.2 million of non-income based taxes
and $2.9 million of asset retirement obligation accretion.
Fuel related costs include $478.3 million in coal costs,
$233.0 million in natural gas costs, $104.7 million in
fuel oil costs, $38.8 million in transmission and
transportation expenses, $100.4 million of purchased energy
costs, $35.0 million in other costs and $17.8 million
in non-cash SO2 emission credit amortization
resulting from Fresh Start accounting. The Northeast region
consumed 50%, 64% and 92% of total coal, natural gas and oil
expenditures, respectively. The South Central region, which is
comprised mainly of our Louisiana base-loaded coal plant,
consumed 32% of our total coal expenditures.
Operating expenses related to continuing operations for the year
ended December 31, 2004 were $486.1 million or 20.6%
of revenues from majority-owned operations. Operating expenses
include labor, normal and major maintenance costs, environmental
and safety costs, utilities costs, and non-income based taxes.
Labor costs include regular, overtime and contract costs at our
plants and totaled $208.5 million. The Northeast region,
where the majority of our assets reside, represents 52% of total
labor costs; Australia represents 18%, while our South Central
region represents 11%. Of the total O&M costs, normal and
major maintenance at our plants accounted for
$176.7 million, or 36.3% of total operating costs.
Maintenance costs were largely driven by planned outages across
our fleet, and the low-sulfur coal conversion in western New
York. The Northeast region represented over half of the normal
and major maintenance, with a total of $98.6 million in
costs in 2004 while Australia had $38.8 million in normal
and major maintenance, or 22%. Operating expenses were
positively impacted by a $7 million favorable settlement
with a vendor regarding auxiliary power charges. Non-income
based taxes totaled $38.2 million net of $34.6 million
in property tax credits, primarily associated with an enterprise
zone program.
Cost of majority-owned operations was $95.5 million, or
69.0% of revenues from majority-owned operations for the period
December 6, 2003 through December 31, 2003. Cost of
energy for this period was $62.3 million or 45.0% of
revenues from majority-owned operations and operating expenses
were $33.2 million, or 24.0% of revenues from
majority-owned operations. Labor during this period totaled
$11.1 million. Normal and major maintenance was
$12 million with 70% of the total normal and major
maintenance for this time period coming from our Northeast
region.
56
Cost of majority-owned operations was $1.4 billion, or
75.4% of revenues from majority-owned operations for the period
January 1, 2003 through December 5, 2003. Cost of
majority-owned operations was unfavorably impacted by increased
generation in the Northeast region, partially offset by a
reduction in trading and hedging activity resulting from a
reduction in our power marketing activities. Our international
operations were impacted by an unfavorable movement in foreign
exchange rates and continued mark-to-market of the Osborne
contract at Flinders resulting from lower pool prices.
|
|
|
Depreciation and Amortization |
Our depreciation and amortization expense related to continuing
operations for the year ended December 31, 2004 was
$209.3 million. Depreciation and amortization consists
primarily of the allocation of our historical depreciable fixed
asset costs over the remaining lives of such property. Upon
adoption of Fresh Start, we were required to revalue our fixed
assets to fair value and determine new remaining lives for such
assets. Our fixed assets were written down substantially upon
our emergence from bankruptcy. We also determined new remaining
depreciable lives, which are, on average, shorter than what we
had previously used primarily due to the age and condition of
our fixed assets.
Depreciation and amortization expense for the period
December 6, 2003 through December 31, 2003 was
$11.8 million. Depreciation and amortization expense
consists of the allocation of our newly valued basis in our
fixed assets over newly determined remaining fixed asset lives.
Our depreciation and amortization expense related to continuing
operations for the period January 1, 2003 through
December 5, 2003 was $218.8 million. During this
period, depreciation expense was unfavorably impacted by the
shortening of the depreciable lives of certain of our domestic
power generation facilities located in the Northeast region and
the impact of recently completed construction projects. The
depreciable lives of certain of our Northeast facilities,
primarily our Connecticut facilities, were shortened to reflect
economic developments in that region. Certain capitalized
development costs were written-off in connection with the Loy
Yang project resulting in increased expense. Amortization
expense increased due to reducing the life of certain software
costs.
|
|
|
General, Administrative and Development |
Our general, administrative and development costs related to
continuing operations for the year ended December 31, 2004
were $211.2 million. Of this total, $111.1 million or
4.7% of revenues from majority-owned operations represents our
corporate costs, with the remaining $100.1 million
representing costs at our plant operations. Corporate costs are
primarily comprised of corporate labor, external professional
support, such as legal, accounting and audit fees, and office
expenses. Corporate general, administrative and development
expenses were negatively impacted this year by increased legal
fees, increased audit costs and increased consulting costs due
to our Sarbanes Oxley testing and implementation. Plant general,
administrative and development costs primarily include insurance
and external consulting costs. Plant insurance costs were
$40.6 million. Additionally, we recorded $11.7 million
in bad debt expense related to notes receivable.
General, administrative and development costs were
$12.5 million, or 9.0% of revenues from continuing
operations for the period December 6, 2003 to
December 31, 2003. These costs are primarily comprised of
corporate labor, insurance and external professional support,
such as legal, accounting and audit fees.
57
Our general, administrative and development costs related to
continuing operations for the period January 1, 2003 to
December 5, 2003 were $170.3 million or 9.5% of
revenues from majority-owned operations. These costs are
primarily comprised of corporate labor, insurance and external
professional support, such as legal, accounting and audit fees.
For the year ended December 31, 2004, we recorded other
charges of $47.4 million, which consisted of
$16.2 million of corporate relocation charges,
$13.4 million of reorganization credits and
$44.6 million of restructuring and impairment charges.
For the period December 6, 2003 through December 31,
2003 we recorded $2.5 million of reorganization charges.
During the period January 1, 2003 to December 5, 2003,
we recorded other credits of $3.2 billion, which consisted
primarily of $228.9 million related to asset impairments,
$462.6 million related to legal settlements,
$197.8 million related to reorganization charges and
$8.7 million related to restructuring charges. We also
incurred a $4.1 billion credit related to Fresh Start
adjustments.
Other charges (credits) consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
|
Predecessor Company |
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
For the Period |
|
|
Year Ended |
|
December 6 - |
|
|
January 1 - |
|
|
December 31, |
|
December 31, |
|
|
December 5, |
|
|
2004 |
|
2003 |
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Corporate relocation charges
|
|
$ |
16,167 |
|
|
$ |
|
|
|
|
$ |
|
|
Reorganization items
|
|
|
(13,390 |
) |
|
|
2,461 |
|
|
|
|
197,825 |
|
Impairment charges
|
|
|
44,661 |
|
|
|
|
|
|
|
|
228,896 |
|
Restructuring charges
|
|
|
|
|
|
|
|
|
|
|
|
8,679 |
|
Fresh Start adjustments
|
|
|
|
|
|
|
|
|
|
|
|
(4,118,636 |
) |
Legal settlement
|
|
|
|
|
|
|
|
|
|
|
|
462,631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
47,438 |
|
|
$ |
2,461 |
|
|
|
$ |
(3,220,605 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate Relocation Charges |
On March 16, 2004, we announced plans to implement a new
regional business strategy and structure. The new structure
called for a reorganized leadership team and a corporate
headquarters relocation to Princeton, New Jersey. The corporate
headquarters staff were streamlined as part of the relocation,
as functions were either reduced or shifted to the regions. The
transition of the corporate headquarters is substantially
complete. During the year ended December 31, 2004, we
recorded $16.2 million for charges related to our corporate
relocation activities, primarily for employee severance and
termination benefits and employee related transition costs.
These charges are classified separately in our statement of
operations, in accordance with SFAS No. 146,
Accounting for Costs Associated with Exit or Disposal
Activities. We expect to incur an additional
$7.7 million of SFAS No. 146-classified expenses
in connection with corporate relocation charges for a total of
$23.9 million. Of this total, relocating, recruiting and
other employee-related transition costs are expected to be
approximately $11.9 million and have been and will continue
to be expensed as incurred. These costs and cash payments are
expected to be incurred through the second quarter of 2005.
Severance and termination benefits of $7.2 million are
expected to be incurred through the second quarter of
58
2005 with cash payments being made through the fourth quarter of
2005. Building lease termination costs are expected to be
$4.8 million. These costs are expected to be incurred
through the first quarter of 2005 with cash payments being made
through the fourth quarter of 2006. Costs not classified
separately as relocation charges include rent expense of our
temporary office in Princeton, construction costs of our new
office and certain labor costs. All costs relating to the
corporate relocation that are not classified separately as
relocation charges, except for approximately $5.7 million
of related capital expenditures will be expensed as incurred and
included in general, administrative and development expenses.
Cash expenditures for 2004, including capital expenditures, were
$22.4 million. We currently estimate total costs associated
with the corporate relocation to be approximately
$40.0 million.
We recognized a curtailment gain of $750,000 on our defined
benefit pension plan in the fourth quarter of 2004, as a
substantial number of our current headquarters staff left the
Company in this period.
For the year ended December 31, 2004, we recorded a net
credit of $13.4 million related primarily to the settlement
of obligations recorded under Fresh Start. We incurred
$7.4 million of professional fees associated with the
bankruptcy which offset $20.8 million of credits associated
with creditor settlements. For the periods December 6, 2003
to December 31, 2003 and January 1, 2003 to
December 5, 2003, we incurred $2.5 million and
$197.8 million, respectively, in reorganization costs. All
reorganization costs have been incurred since we filed for
bankruptcy in May 2003. The following table provides the detail
of the types of costs incurred.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor |
|
|
Reorganized NRG |
|
|
Company |
|
|
|
|
|
|
|
|
|
|
For the period |
|
|
For the period |
|
|
Year Ended |
|
December 6 - |
|
|
January 1 - |
|
|
December 31, |
|
December 31, |
|
|
December 5, |
|
|
2004 |
|
2003 |
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Reorganization items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Professional fees
|
|
$ |
7,383 |
|
|
$ |
2,461 |
|
|
|
$ |
82,186 |
|
|
Deferred financing costs
|
|
|
|
|
|
|
|
|
|
|
|
55,374 |
|
|
Pre-payment settlement
|
|
|
|
|
|
|
|
|
|
|
|
19,609 |
|
|
Interest earned on accumulated cash
|
|
|
|
|
|
|
|
|
|
|
|
(1,059 |
) |
|
Contingent equity obligation
|
|
|
|
|
|
|
|
|
|
|
|
41,715 |
|
|
Settlement of obligations
|
|
|
(20,773 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total reorganization items
|
|
$ |
(13,390 |
) |
|
$ |
2,461 |
|
|
|
$ |
197,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We review the recoverability of our long-lived assets in
accordance with the guidelines of SFAS No. 144. As a
result of this review, we recorded impairment charges of
$44.7 million and $228.9 million for the year ended
December 31, 2004 and the period January 1, 2003
through December 5, 2003, respectively, as shown in the
table below. Of the $44.7 million total in 2004, Kendall
and the Meriden turbine accounted for $26.5 million and
$15.0 million, respectively. Both of these charges were
based on indicative market valuations. We successfully completed
the sale of Kendall in November 2004 and expect to complete the
sale of the Meriden turbine in the first quarter of 2005. There
were no impairment charges for the period December 6, 2003
through December 31, 2003.
To determine whether an asset was impaired, we compared asset
carrying values to total future estimated undiscounted cash
flows. Separate analyses were completed for assets or groups of
assets at the lowest level for which identifiable cash flows
were largely independent of the cash flows of other assets and
liabilities. The estimates of future cash flows included only
future cash flows, net of associated cash outflows, directly
associated with and expected to arise as a result of our assumed
use and eventual disposition of the asset. Cash flow estimates
associated with assets in service were based on the assets
existing service potential. The cash
59
flow estimates may include probability weightings to consider
possible alternative courses of action and outcomes, given the
uncertainty of available information and prospective market
conditions.
If an asset was determined to be impaired based on the cash flow
testing performed, an impairment loss was recorded to write down
the asset to its fair value. Estimates of fair value were based
on prices for similar assets and present value techniques. Fair
values determined by similar asset prices reflect our current
estimate of recoverability from expected marketing of project
assets. For fair values determined by projected cash flows, the
fair value represents a discounted cash flow amount over the
remaining life of each project that reflects project-specific
assumptions for long-term power pool prices, escalated future
project operating costs, and expected plant operation given
assumed market conditions.
Impairment charges (credits) included the following asset
impairments (realized gains) for the year ended
December 31, 2004 and the period January 1, 2003 to
December 5, 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor |
|
|
|
|
|
|
Reorganized |
|
|
Company |
|
|
|
|
|
|
NRG |
|
|
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
|
|
|
|
Year Ended |
|
|
January 1 - |
|
|
|
|
|
|
December 31, |
|
|
December 5, |
|
Basis of Impairment |
Project Name |
|
Project Status |
|
2004 |
|
|
2003 |
|
Charge |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
Louisiana Generating LLC
|
|
Office building and land being marketed |
|
$ |
493 |
|
|
|
$ |
|
|
|
Estimated market price |
New Roads Holding LLC (turbine)
|
|
Non-operating asset abandoned |
|
|
2,416 |
|
|
|
|
|
|
|
Projected cash flows |
Devon Power LLC
|
|
Operating at a loss in 2003 |
|
|
247 |
|
|
|
|
64,198 |
|
|
Projected cash flows |
Middletown Power LLC
|
|
Operating at a loss |
|
|
|
|
|
|
|
157,323 |
|
|
Projected cash flows |
Arthur Kill Power, LLC
|
|
Terminated construction project |
|
|
|
|
|
|
|
9,049 |
|
|
Projected cash flows |
Langage (UK)
|
|
Terminated |
|
|
|
|
|
|
|
(3,091 |
) |
|
Estimated market price |
Turbines
|
|
Sold |
|
|
|
|
|
|
|
(21,910 |
) |
|
Realized gain |
Berrians Project
|
|
Terminated |
|
|
|
|
|
|
|
14,310 |
|
|
Realized loss |
TermoRio
|
|
Terminated |
|
|
|
|
|
|
|
6,400 |
|
|
Realized loss |
Meriden
|
|
Sold |
|
|
15,000 |
|
|
|
|
|
|
|
Similar asset prices |
Kendall and other expansion projects
|
|
Sold |
|
|
26,505 |
|
|
|
|
|
|
|
Projected cash flows, sales contracts |
Other
|
|
|
|
|
|
|
|
|
|
2,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impairment charges
|
|
|
|
$ |
44,661 |
|
|
|
$ |
228,896 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We incurred $8.7 million of employee separation costs and
advisor fees during the period January 1, 2003 until we
filed for bankruptcy in May 2003. Subsequent to that date we
recorded all advisor fees as reorganization costs.
60
During the fourth quarter of 2003, we recorded a net credit of
$3.9 billion (comprised of a $4.1 billion gain from
continuing operations and a $0.2 billion loss from
discontinued operations) in connection with fresh start
adjustments. Following is a summary of the significant effects
of the reorganization and Fresh Start:
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
Discharge of corporate level debt
|
|
$ |
5,162 |
|
Discharge of other liabilities
|
|
|
811 |
|
Establishment of creditor pool
|
|
|
(1,040 |
) |
Receivable from Xcel
|
|
|
640 |
|
Revaluation of fixed assets
|
|
|
(1,392 |
) |
Revaluation of equity investments
|
|
|
(207 |
) |
Valuation of SO 2 emission credits
|
|
|
374 |
|
Valuation of out of market contracts, net
|
|
|
(400 |
) |
Fair market valuation of debt
|
|
|
108 |
|
Valuation of pension liabilities
|
|
|
(61 |
) |
Other valuation adjustments
|
|
|
(100 |
) |
|
|
|
|
|
Total Fresh Start adjustments
|
|
|
3,895 |
|
|
Less discontinued operations
|
|
|
(224 |
) |
|
|
|
|
|
Total Fresh Start adjustments continuing operations
|
|
$ |
4,119 |
|
|
|
|
|
|
During the period January 1, 2003 to December 5, 2003,
we recorded $462.6 million of legal settlement charges
which consisted of the following. We recorded
$396.0 million in connection with the resolution of an
arbitration claim asserted by FirstEnergy Corp. As a result of
this resolution, FirstEnergy retained ownership of the Lake
Plant Assets and received an allowed general unsecured claim of
$396.0 million under NRG Energys Plan of
Reorganization. In November 2003, we settled litigation with
Fortistar Capital in which Fortistar Capital released us from
all litigation claims in exchange for a $60.0 million
pre-petition bankruptcy claim and an $8.0 million
post-petition bankruptcy claim. We had previously recorded
$10.8 million in connection with various legal disputes
with Fortistar Capital; accordingly, we recorded an additional
$57.2 million during November 2003. In November 2003, we
settled our dispute with Dick Corporation in connection with
Meriden Gas Turbines LLC through the payment of a general
unsecured claim and a post-petition pre-confirmation payment.
This settlement resulted in our recording an additional
liability of $8.0 million in November 2003.
In August 1995, we entered into a Marketing, Development and
Joint Proposing Agreement, or the Marketing Agreement, with
Cambrian Energy Development LLC, or Cambrian. Various claims
arose in connection with the Marketing Agreement. In November
2003, we entered into a settlement agreement with Cambrian where
we agreed to transfer our 100% interest in three gasco projects
(NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50%
interest in two genco projects (MM Phoenix and MM Woodville) to
Cambrian. In addition, we paid approximately $1.8 million
in settlement of royalties incurred in connection with the
Marketing Agreement. We had previously recorded a liability for
royalties owed to Cambrian, therefore, we recorded an additional
$1.4 million during November 2003.
During the year ended December 31, 2004, we recorded other
expense of $171.9 million. Other expense consisted
primarily of $269.4 million of interest expense,
$71.6 million of refinancing-related expenses,
$1.0 million of minority interest in earnings of
consolidated subsidiaries and $16.3 million of write downs
and losses on sales of equity method investments, offset by
$159.8 million of equity in earnings of unconsolidated
affiliates (including $68.9 million from our investment in
West Coast Power LLC) and $26.6 million of other income,
net.
61
Other income (expense) for the period December 6, 2003
through December 31, 2003, was an expense of
$5.4 million and consisted primarily of $18.9 million
of interest expense, partially offset by $13.5 million of
equity in earnings of unconsolidated affiliates.
During the period January 1, 2003 through December 5,
2003, we recorded other expense of $286.9 million. Other
expense consisted primarily of $329.9 million of interest
expense and $147.1 million of write downs and losses on
sales of equity method investments, partially offset by equity
in earnings of unconsolidated affiliates of $170.9 million
and $19.2 million of other income, net.
|
|
|
Minority Interest in Earnings of Consolidated Subsidiaries |
For the year ended December 31, 2004, minority interest in
earnings of consolidated subsidiaries was $1.0 million
which relates primarily to our ownership interests in Northbrook
Energy, LLC and Northbrook New York, LLC, partnerships which
hold a portfolio of small hydro projects. For the period
December 6, 2003 through December 31, 2003, minority
interest in earnings of consolidated subsidiaries was $134,000
and relates primarily to Northbrook New York and Northbrook
Energy.
|
|
|
Equity in Earnings of Unconsolidated Affiliates |
For the year ended December 31, 2004, we recorded
$159.8 million of equity earnings from our investments in
unconsolidated affiliates. Our equity in earnings of West Coast
Power comprised $68.9 million of this amount with our
equity in earnings of Enfield, Mibrag, and Gladstone comprising
$28.5 million, $20.9 million, and $17.5 million,
respectively. Our investment in West Coast Power generated
favorable results due to the pricing under the California
Department of Water Resources contract. Additionally, revenues
from ancillary services revenue and minimum load cost
compensation power positively contributed to West Coast
Powers operating results. However, our equity earnings in
the project as reported in our results of operations have been
reduced by a net $115.8 million to reflect a non-cash basis
adjustment for in the money contracts resulting from adoption of
Fresh Start.
NRG Energys equity earnings were also favorably
impacted by $23.3 million of unrealized gain related to our
Enfield investment. This gain is associated with changes in the
fair value of energy-related derivative instruments not
accounted for as hedges in accordance with
SFAS No. 133.
Equity in earnings of unconsolidated affiliates of
$13.5 million for the period December 6, 2003 through
December 31, 2003 consists primarily of equity earnings
from our 50% ownership in West Coast Power of $9.4 million.
During the period January 1, 2003 through December 5,
2003, we recorded $170.9 million of equity earnings from
investments in unconsolidated affiliates. Our 50% investment in
West Coast Power comprised $98.7 million of this amount
with our investments in the Mibrag, Loy Yang, Gladstone and
Rocky Road projects comprising $21.8 million,
$17.9 million, $12.4 million and $6.9 million,
respectively, with the remaining amounts attributable to various
domestic and international equity investments.
62
Equity in earnings of unconsolidated affiliates consists of the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
|
Predecessor Company |
|
|
|
|
|
|
|
|
Year Ended |
|
December 6, 2003 |
|
|
January 1, 2003 |
|
Year Ended |
|
|
December 31, |
|
Through |
|
|
Through |
|
December 31, |
|
|
2004 |
|
December 31, 2003 |
|
|
December 5, 2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
West Coast Power
|
|
$ |
68,895 |
|
|
$ |
9,362 |
|
|
|
$ |
98,741 |
|
|
$ |
19,044 |
|
MIBRAG
|
|
|
20,938 |
|
|
|
102 |
|
|
|
|
21,818 |
|
|
|
28,750 |
|
Enfield
|
|
|
28,505 |
|
|
|
481 |
|
|
|
|
5,975 |
|
|
|
(6,017 |
) |
Gladstone
|
|
|
17,528 |
|
|
|
997 |
|
|
|
|
12,440 |
|
|
|
7,237 |
|
Rocky Road
|
|
|
6,904 |
|
|
|
305 |
|
|
|
|
6,864 |
|
|
|
6,868 |
|
James River
|
|
|
7,750 |
|
|
|
543 |
|
|
|
|
(1,893 |
) |
|
|
9,713 |
|
NRG Saguaro
|
|
|
5,480 |
|
|
|
617 |
|
|
|
|
3,940 |
|
|
|
4,968 |
|
Scudder LA Trust
|
|
|
1,521 |
|
|
|
150 |
|
|
|
|
2,653 |
|
|
|
1,043 |
|
NRG National
|
|
|
846 |
|
|
|
190 |
|
|
|
|
2,010 |
|
|
|
1,695 |
|
MWPC RDF
|
|
|
200 |
|
|
|
8 |
|
|
|
|
123 |
|
|
|
259 |
|
NRG Cadillac
|
|
|
(421 |
) |
|
|
(2 |
) |
|
|
|
280 |
|
|
|
195 |
|
Central and Eastern European Energy Power Fund
|
|
|
(47 |
) |
|
|
(22 |
) |
|
|
|
(260 |
) |
|
|
(331 |
) |
Loy Yang
|
|
|
|
|
|
|
|
|
|
|
|
17,924 |
|
|
|
8,443 |
|
Other
|
|
|
1,726 |
|
|
|
790 |
|
|
|
|
286 |
|
|
|
(12,871 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity in Earnings of Unconsolidated Affiliates
|
|
$ |
159,825 |
|
|
$ |
13,521 |
|
|
|
$ |
170,901 |
|
|
$ |
68,996 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Write Downs and Losses on Sales of Equity Method
Investments |
As part of our periodic review of our equity method investments
for impairments, we have taken write downs and losses on sales
of equity method investments during the year ended
December 31, 2004 of $16.3 million and
$147.1 million for the period January 1, 2003 through
December 5, 2003. Our Commonwealth Atlantic Limited
Partnership (CALP) and James River investments were written
down based on indicative market bids. The sale of CALP closed in
the fourth quarter of 2004, while the sale agreement for James
River has been terminated. There were no write downs and losses
on sales of equity method investments for the period
December 6, 2003 through December 31, 2003.
63
Write downs and losses (gains) on sales of equity method
investments recorded in the consolidated statement of operations
include the following:
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized |
|
|
Predecessor |
|
|
NRG |
|
|
Company |
|
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
Year Ended |
|
|
January 1 - |
|
|
December 31, |
|
|
December 5, |
|
|
2004 |
|
|
2003 |
|
|
|
|
|
|
|
|
(In thousands) |
Commonwealth Atlantic Limited Partnership
|
|
$ |
4,614 |
|
|
|
$ |
|
|
James River Power LLC
|
|
|
7,293 |
|
|
|
|
|
|
NEO Corporation
|
|
|
3,830 |
|
|
|
|
|
|
Calpine Cogeneration
|
|
|
(735 |
) |
|
|
|
|
|
NLGI Minnesota Methane
|
|
|
|
|
|
|
|
12,257 |
|
NLGI MM Biogas
|
|
|
|
|
|
|
|
2,613 |
|
Kondapalli
|
|
|
|
|
|
|
|
(519 |
) |
ECKG
|
|
|
|
|
|
|
|
(2,871 |
) |
Loy Yang
|
|
|
1,268 |
|
|
|
|
146,354 |
|
Mustang
|
|
|
|
|
|
|
|
(12,124 |
) |
Other
|
|
|
|
|
|
|
|
1,414 |
|
|
|
|
|
|
|
|
|
|
|
Total write downs and losses of equity method investments
|
|
$ |
16,270 |
|
|
|
$ |
147,124 |
|
|
|
|
|
|
|
|
|
|
|
Commonwealth Atlantic Limited Partnership
(CALP) In June 2004, we executed an agreement to
sell our 50% interest in CALP. During the third quarter of 2004,
we recorded an impairment charge of approximately
$3.7 million to write down the value of our investment in
CALP to its fair value. The sale closed in November 2004,
resulting in net cash proceeds of $14.9 million. Total
impairment charges as a result of the sale were
$4.6 million.
James River Power LLC In September 2004, we
executed an agreement with Colonial Power Company LLC to sell
all of our outstanding shares of stock in Capistrano
Cogeneration Company, a wholly-owned subsidiary of
NRG Energy which owns a 50% interest in James River
Cogeneration Company. During the third quarter of 2004, we
recorded an impairment charge of approximately $6.0 million
to write down the value of our investment in James River to its
fair value. During the fourth quarter of 2004, the sale
agreement was terminated. We continue to impair any additional
equity earnings based on its fair value. Total impairment
charges for 2004 were $7.3 million.
NEO Corporation On September 30, 2004,
we completed the sale of several NEO investments
Four Hills LLC, Minnesota Methane II LLC, NEO Montauk Genco
LLC and NEO Montauk Gasco LLC to Algonquin Power of Canada. The
sale also included four wholly-owned NEO subsidiaries (see
Item 15 Note 6). We received cash proceeds
of $6.1 million. The sale resulted in a loss of
approximately $3.8 million attributable to the equity
investment entities sold.
Calpine Cogeneration In January 2004, we
executed an agreement to sell our 20% interest in Calpine
Cogeneration Corporation to Calpine Power Company. The
transaction closed in March 2004 and resulted in net cash
proceeds of $2.5 million and a net gain of
$0.2 million. During the second quarter of 2004, we
received additional consideration on the sale of
$0.5 million, resulting in an adjusted net gain of
$0.7 million.
NLGI Minnesota Methane We
recorded an impairment charge of $12.3 million during 2002
to write-down our 50% investment in Minnesota Methane. We
recorded an additional impairment charge of $14.5 million
during the first quarter of 2003. These charges were related to
a revised project outlook and managements belief that the
decline in fair value was other than temporary. In May 2003, the
project lenders to the wholly-owned subsidiaries of NEO Landfill
Gas, Inc. and Minnesota Methane LLC foreclosed on our membership
interest in the NEO Landfill Gas, Inc. subsidiaries and our
equity interest in Minnesota Methane LLC. Upon completion of the
foreclosure, we recorded a gain of $2.2 million, resulting
in a net impairment
64
charge of $12.3 million for the period January 1, 2003
to December 5, 2003. This gain resulted from the release of
certain obligations.
NLGI MM Biogas We recorded an
impairment charge of $3.2 million during 2002 to write-down
our 50% investment in MM Biogas. This charge was related to a
revised project outlook and managements belief that the
decline in fair value was other than temporary. In November
2003, we entered into a sales agreement with Cambrian Energy
Development to sell our 50% interest in MM Biogas. We recorded
an additional impairment charge of $2.6 million during the
fourth quarter of 2003 due to developments related to the sale
that indicated an impairment of our book value that was
considered to be other than temporary.
Kondapalli In the fourth quarter of 2002, we
wrote down our investment in Kondapalli by $12.7 million
due to recent estimates of sales value, which indicated an
impairment of our book value that was considered to be other
than temporary. On January 30, 2003, we signed a sale
agreement with the Genting Group of Malaysia, or Genting, to
sell our 30% interest in Lanco Kondapalli Power Pvt Ltd, or
Kondapalli, and a 74% interest in Eastern Generation Services
(India) Pvt Ltd (the O&M company). Kondapalli is based in
Hyderabad, Andhra Pradesh, India, and is the owner of a
368 MW natural gas fired combined cycle gas turbine. In the
first quarter of 2003, we wrote down our investment in
Kondapalli by $1.3 million based on the final sale
agreement. The sale closed on May 30, 2003 resulting in net
cash proceeds of approximately $24 million and a gain of
approximately $1.8 million, resulting in a net gain of
$0.5 million. The gain resulted from incurring lower
selling costs than estimated as part of the first quarter
impairment.
ECKG In September 2002, we announced that we
had reached agreement to sell our 44.5% interest in the ECKG
power station in connection with our Csepel power generating
facilities, and our interest in Entrade, an electricity trading
business, to Atel, an independent energy group headquartered in
Switzerland. The transaction closed in January 2003 and resulted
in cash proceeds of $65.3 million and a net loss of less
than $1.0 million. In accordance with the purchase
agreement, we were to receive additional consideration if Atel
purchased shares held by our partner. During the second quarter
of 2003, we received approximately $3.7 million of
additional consideration, resulting in a net gain of
$2.9 million.
Loy Yang Based on a third party market
valuation and bids received in response to marketing Loy Yang
for possible sale, we recorded a write down of our investment of
approximately $111.4 million during 2002. This write-down
reflected managements belief that the decline in fair
value of the investment was other than temporary. In May 2003,
we entered into negotiations that culminated in the completion
of a Share Purchase Agreement to sell 100% of the Loy Yang
project. Consequently, we recorded an additional impairment
charge of approximately $146.4 million during 2003. In
April 2004, we completed the sale of Loy Yang which resulted in
net cash proceeds of $26.7 million and a loss of
$1.3 million.
Mustang Station On July 7, 2003, we
completed the sale of our 25% interest in Mustang Station, a
gas-fired combined cycle power generating plant located in
Denver City, Texas, to EIF Mustang Holdings I, LLC. The
sale resulted in net cash proceeds of approximately
$13.3 million and a net gain of approximately
$12.1 million.
During the year ended December 31, 2004, we recorded
$26.6 million of other income, net, consisting primarily of
interest income earned on notes receivable and cash balances.
For the period December 6, 2003 through December 31,
2003 we recorded other income of $97,000.
During the period January 1, 2003 through December 5,
2003, we recorded $19.2 million of other income, net.
During this period other income, net consisted primarily of
interest income earned on notes receivable and cash balances,
offset in part by the unfavorable mark-to-market on our
corporate level £160 million note that was cancelled
in connection with our bankruptcy proceedings.
65
Interest expense for the year ended December 31, 2004 was
$269.4 million, consisting of interest expense on both our
project- and corporate-level interest-bearing debt. Significant
amounts of our corporate-level debt were forgiven upon our
emergence from bankruptcy and we refinanced significant amounts
of our project-level debt with corporate level high yield notes
and term loans in December 2003. Also included in interest
expense is the amortization of debt financing costs of
$9.2 million related to our corporate level debt and
$13.3 million of amortization expense related primarily to
debt discounts and premiums recorded as part of Fresh Start.
Interest expense also includes the impact of any interest rate
swaps that we have entered in order to manage our exposure to
changes in interest rates.
Interest expense for the period December 6, 2003 through
December 31, 2003 of $18.9 million consists primarily
of interest expense at the corporate level, primarily related to
the Second Priority Notes, term loan facility and revolving line
of credit used to refinance certain project-level financings. In
addition, interest expense includes the amortization of deferred
financing costs incurred as a result of our refinancing efforts
and the amortization of discounts and premiums recorded upon the
marking of our debt to fair value upon our adoption of the Fresh
Start provision of SOP 90-7.
Interest expense for the period January 1, 2003 through
December 5, 2003 of $329.9 million consisted of
interest expense on both our project and corporate level
interest bearing debt. In addition, interest expense includes
the amortization of debt issuance costs and any interest rate
swap termination costs. Interest expense during this period was
favorably impacted by our ceasing to record interest expense on
debt where it was probable that such interest would not be paid,
such as the NRG Energy corporate level debt (primarily
bonds) and the NRG Finance Company debt (construction revolver)
due to our entering into bankruptcy in May 2003. We did not
however cease to record interest expense on the project-level
debt outstanding at our Northeast Generating and South Central
Generating facilities even though these entities were also in
bankruptcy as these claims were deemed to be most likely not
impaired and not subject to compromise. We also recorded
substantial amounts of fees and costs related to our acquiring a
debtor in possession financing arrangement while we were in
bankruptcy. In addition, upon our emergence from bankruptcy we
wrote off any remaining deferred finance costs related to our
corporate and project-level debt including our Northeast and
South Central project-level debt as it was probable that they
would be refinanced upon our emergence from bankruptcy. Interest
expense was unfavorably impacted by an adverse mark-to-market on
certain interest rate swaps that we have entered in order to
manage our exposure to changes in interest rates. Due to our
deteriorating financial condition during such period, hedge
accounting treatment was ceased for certain of our interest rate
swaps, causing changes in fair value to be recorded as interest
expense.
Refinancing expense was $71.6 million for the year ended
December 31, 2004. This amount includes $15.1 million
of prepayment penalties and a $15.3 million write-off of
deferred financing costs related to refinancing certain amounts
of our term loans with additional corporate level high yield
notes in January 2004 and $13.8 million of prepayment
penalties and a $26.8 million write-off of deferred
financing costs related to refinancing the senior credit
facility in December 2004.
Our income tax provision from continuing operations was
$65.1 million for the year ended December 31, 2004 and
an income tax benefit of ($0.7) million for the period
December 6, 2003 through December 31, 2003. The
overall effective tax rate in 2004 and the short period in 2003
was 28.7% and (6.2%), respectively.
66
The change in our effective tax rate was primarily due to a
state tax refund received from Xcel Energy in 2003 and foreign
income taxed in jurisdictions with tax rates different from the
U.S. statutory rate.
Our net deferred tax assets at December 31, 2004 were
offset by a full valuation allowance in accordance with
SFAS No. 109. Under SOP 90-7, any future benefits
from reducing a valuation allowance from preconfirmation
deferred tax assets are required to be reported first as an
adjustment of identifiable intangible assets and then as a
direct addition to paid in capital versus a benefit on our
statement of operations.
The effective tax rate may vary from year to year depending on,
among other factors, the geographic and business mix of earnings
and losses. These same and other factors, including history of
pre-tax earnings and losses, are taken into account in assessing
the ability to realize deferred tax assets.
Income tax expense for the period January 1, 2003 through
December 5, 2003 was $37.9 million. The overall
effective tax rate for the period ended December 5, 2003
was 1.3%. The rate is lower than the U.S. statutory rate
primarily due to a release in valuation allowance for net
operating loss carryforwards that were utilized following our
emergence from bankruptcy to offset the current tax on
cancellation of debt income.
Income taxes have been recorded on the basis that our
U.S. subsidiaries and we would file separate federal income
tax returns for the period January 1, 2003 through
December 5, 2003. Since our U.S. subsidiaries and we
were not included in the Xcel Energy consolidated tax group,
each of our U.S. subsidiaries that is classified as a
corporation for U.S. income tax purposes filed a separate
federal income tax return. It is uncertain if, on a stand-alone
basis, we would be able to fully realize deferred tax assets
related to net operating losses and other temporary differences,
therefore a full valuation allowance has been established.
|
|
|
Income From Discontinued Operations, net of Income Taxes |
We classified as discontinued operations the operations and
gains/losses recognized on the sale of projects that were sold
or were deemed to have met the required criteria for such
classification pending final disposition. During the year ended
December 31, 2004, we recorded income from discontinued
operations, net of income taxes, of $23.5 million. During
the year ended December 31, 2004 and for the period
December 6, 2003 to December 31, 2003, discontinued
operations consisted of the results of our NRG McClain LLC,
Penobscot Energy Recovery Company, or PERC, Compania Boliviana
De Energia Electrica S.A. Bolivian Power Company Limited, or
Cobee, Hsin Yu, LSP Energy (Batesville) and four NEO Corporation
projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima
Deshecha LLC and NEO Tajiguas LLC). All other discontinued
operations were disposed of in prior periods. The
$23.5 million income from discontinued operations includes
a gain of $22.4 million, net of income taxes of
$7.9 million, related primarily to the dispositions of
Batesville, Cobee and Hsin Yu.
Discontinued operations for the period December 6, 2003
through December 31, 2003 is comprised of a loss of
$0.4 million attributable to the on going operations of our
McClain, PERC, Cobee, LSP Energy, Hsin Yu and four NEO
Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO
Prima Deshecha LLC and NEO Tajiguas LLC).
As of December 5, 2003, we classified as discontinued
operations the operations and gains/losses recognized on the
sales of projects that were sold or were deemed to have met the
required criteria for such classification pending final
disposition. For the period January 1, 2003 through
December 5, 2003, discontinued operations consist of the
historical operations and net gains/losses related to our
Killingholme, McClain, PERC, Cobee, NEO Landfill Gas, Inc., or
NLGI, seven NEO Corporation projects (NEO Nashville LLC, NEO
Hackensack LLC, NEO Prima Deshecha LLC, NEO Tajiguas LLC, NEO
Ft. Smith LLC, NEO
67
Woodville LLC and NEO Phoenix LLC), Timber Energy Resources,
Inc., or TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu
projects.
For the period January 1, 2003 through December 5,
2003, the results of operations related to such discontinued
operations was a net loss of $182.6 million due to a loss
on the sale of our Peru projects, impairment charges of
$100.7 million and $23.6 million, respectively,
recorded at McClain and NLGI and fresh start adjustments at LSP
Energy.
|
|
|
For the Year Ended December 31, 2003 Compared to the
Year Ended December 31, 2002 |
During the period December 6, 2003 through
December 31, 2003, we recognized net income of
$11.0 million or $0.11 per share of common stock. Net
income was directly attributable to a number of factors some of
which are discussed below. From an overall operational
perspective our facilities were profitable during this period.
Our results were adversely impacted by our having to continue to
satisfy the standard offer service contract that we entered into
with Connecticut Light & Power, or CL&P, in 2000.
As a result of our inability to terminate this contract during
our bankruptcy proceeding, we continued to be exposed to losses
under this contract. These losses were incurred, as we were
unable to satisfy the requirements of this contract at a
price/cost below the contracted sales price. Upon our adoption
of Fresh Start, we recorded at fair value all assets and
liabilities on our opening balance sheet and accordingly we
recorded as an obligation the fair value of the CL&P
contract. During the period December 6, 2003 through
December 31, 2003, we recognized as revenues the entire
fair value of this contract effectively offsetting the actual
losses incurred under this contract. The CL&P contract
terminated on December 31, 2003.
During the period January 1, 2003 through December 5,
2003, we recorded net income of $2.8 billion. Net income
for the period is directly attributable to our emerging from
bankruptcy and adopting the Fresh Start provisions of
SOP 90-7. Upon the confirmation of our Plan of
Reorganization and our emergence from bankruptcy we were able to
remove significant amounts of long-term debt and other
pre-petition obligations from our balance sheet. Accordingly, as
part of net income, we recorded a net gain of $3.9 billion
(comprised of a $4.1 billion gain from continuing
operations and a $0.2 billion loss from discontinued
operations) as the impact of our adopting Fresh Start in our
statement of operations. $6.0 billion of this amount is
directly related to the forgiveness of debt and settlement of
substantial amounts of our pre-petition obligations upon our
emergence from bankruptcy. In addition to the removal of
substantial amounts of pre-petition debt and other obligations
from our balance sheet, we have also revalued our assets and
liabilities to fair value. Accordingly, we have substantially
written down the value of our fixed assets. We have recorded a
net $1.6 billion charge related to the revaluation of our
assets and liabilities within the Fresh Start Reporting
adjustment line of our consolidated statement of operations. In
addition to our recording adjustments related to our emergence
from bankruptcy, we also recorded substantial charges related to
other items such as the settlement of certain outstanding
litigation in the amount of $462.6 million, write downs and
losses on the sale of equity investments of $147.1 million,
advisor costs and legal fees directly attributable to our being
in bankruptcy of $197.8 million and $237.6 million of
other asset impairment and restructuring costs incurred prior to
our filing for bankruptcy. Net income for the period
January 1, 2003 through December 5, 2003 was favorably
impacted by our not recording interest expense on substantial
amounts of corporate level debt while we were in bankruptcy and
by the continued favorable results experienced by our equity
investments.
During the year ended December 31, 2002, we recognized a
net loss of $3.5 billion. The loss from continuing
operations incurred during 2002 primarily consisted of
$2.6 billion of other charges consisting primarily of asset
impairments.
68
|
|
|
Revenues from Majority-Owned Operations |
Our operating revenues from majority-owned operations were
$138.5 million for the period December 6, 2003 through
December 31, 2003.
Revenues from majority-owned operations were $1.8 billion
for the period January 1, 2003 through December 5,
2003 and include $992.6 million of energy revenues,
$566.0 million of capacity revenues, $115.9 million of
alternative energy, $12.9 million of O&M fees and
$110.9 million of other revenues which include financial
and physical gas sales, sales from our Schkopau facility and
NEPOOL expense reimbursements. Revenues from majority-owned
operations during the period year ended December 5, 2003,
were driven primarily by our North American operations and to a
lesser degree by our international operations, primarily
Australia. Our domestic Northeast and South Central power
generation operations significantly contributed to our revenues
due primarily to favorable market prices resulting from strong
fuel and electricity prices. Our Australian operations were
favorably impacted by favorable foreign exchange rates. During
this period we also experienced an unfavorable impact on our
revenues due to continued losses on our CL&P standard offer
contract and the mark-to-market on certain of our derivatives.
Revenues from majority-owned operations were $1.9 billion
for the year ended December 31, 2002.
|
|
|
Cost of Majority-Owned Operations |
Our cost of majority-owned operations for the period
December 6, 2003 through December 31, 2003 was
$95.5 million or 69.0% of revenues from majority-owned
operations.
Cost of majority-owned operations was $1.4 billion, or
75.4% of revenues from majority-owned operations for the period
January 1, 2003 through December 5, 2003. Cost of
majority-owned operations was unfavorably impacted by increased
generation in the Northeast region, partially offset by a
reduction in trading and hedging activity resulting from a
reduction in our power marketing activities. Our international
operations were unfavorably impacted due to an unfavorable
movement in foreign exchange rates and continued mark-to-market
of the Osborne contract at Flinders resulting from lower pool
prices.
Our cost of majority-owned operations related to continuing
operations was $1.3 billion for 2002, or 68.7% of revenues
from majority-owned operations. Cost of majority-owned
operations, consists primarily of cost of energy (primarily fuel
costs), labor, operating and maintenance costs and non-income
based taxes related to our majority-owned operations. Cost of
energy for the year ended December 31, 2002 was
$900.9 million or 46.5% of revenue from majority-owned
operations.
|
|
|
Depreciation and Amortization |
Our depreciation and amortization expense related to continuing
operations was $11.8 million for the period
December 6, 2003 through December 31, 2003.
Depreciation and amortization expense consists of the allocation
of our newly valued basis in our fixed assets over newly
determined remaining fixed asset lives. As part of adopting the
Fresh Start concepts of SOP 90-7, our tangible fixed assets
were recorded at fair value as determined by a third party
valuation expert who we also consulted with in determining the
appropriate remaining lives for our tangible depreciable
property. Depreciation expense for this period was based on
preliminary depreciable lives and asset balances.
69
Our depreciation and amortization expense related to continuing
operations was $218.8 million for the period
January 1, 2003 through December 5, 2003 and
$207.0 million for the year ended December 31, 2002.
During the period January 1, 2003 to December 5, 2003,
depreciation expense was unfavorably impacted by the shortening
of the depreciable lives of certain of our domestic power
generation facilities located in the Northeast region and the
impact of completed construction projects. Depreciation and
amortization consists of the allocation of our historical
depreciable fixed asset costs over the remaining lives of such
property as well as the amortization of certain contract based
intangible assets.
|
|
|
General, Administrative and Development |
Our general, administrative and development costs for the period
December 6, 2003 through December 31, 2003 was
$12.5 million or 9.0% of revenues from majority-owned
operations. These costs are primarily comprised of corporate
labor, insurance and external professional support, such as
legal, accounting and audit fees.
Our general, administrative and development costs for the period
January 1, 2003 through December 5, 2003 were
$170.3 million, or 9.5% of revenues from majority-owned
operations. Our general, administrative and development costs
for 2002 were $218.9 million, or 11.3% of revenues from
majority-owned operations. General, administrative and
development costs for the period January 1, 2003 through
December 5, 2003 were favorably impacted by decreased costs
related to work force reduction efforts, cost reductions due to
the closure of certain international offices and reduced legal
costs. Outside services also decreased, due to less
non-restructuring legal activities.
During the period December 6, 2003 through
December 31, 2003 we recorded $2.5 million of other
charges related to reorganization items.
During the period January 1, 2003 to December 5, 2003,
we recorded other credits of $3.2 billion, which consisted
primarily of $228.9 million related to asset impairments,
$462.6 million related to legal settlements,
$197.8 million related to reorganization charges and
$8.7 million related to restructuring charges. We also
incurred a $4.1 billion credit related to Fresh Start
adjustments. During 2002, we recorded other charges of
$2.6 billion, which consisted primarily of
$2.5 billion related to asset impairments and
$111.3 million related to restructuring charges.
We review the recoverability of our long-lived assets on a
periodic basis and if we determined that an asset was impaired,
we compared asset-carrying values to total future estimated
undiscounted cash flows. Separate analyses are completed for
assets or groups of assets at the lowest level for which
identifiable cash flows are largely independent of the cash
flows of other assets and liabilities. The estimates of future
cash flows included only future cash flows, net of associated
cash outflows, directly associated with and expected to arise as
a result of our assumed use and eventual disposition of the
asset. Cash flow estimates associated with assets in service are
based on the assets existing service potential. The cash
flow estimates may include probability weightings to consider
possible alternative courses of action and outcomes, given the
uncertainty of available information and prospective market
conditions.
If an asset was determined to be impaired based on the cash flow
testing performed, an impairment loss was recorded to write down
the asset to its fair value. Estimates of fair value were based
on prices for similar
70
assets and present value techniques. Fair values determined by
similar asset prices reflect our current estimate of
recoverability from expected marketing of project assets. For
fair values determined by projected cash flows, the fair value
represents a discounted cash flow amount over the remaining life
of each project that reflects project-specific assumptions for
long-term power pool prices, escalated future project operating
costs, and expected plant operation given assumed market
conditions.
Impairment charges (credits) included the following for the
period January 1, 2003 to December 5, 2003 and the
year ended December 31, 2002. There were no impairment
charges for the period December 6, 2003 through
December 31, 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Predecessor Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
|
|
|
|
|
|
January 1 - |
|
Year Ended |
|
|
|
|
|
|
December 5, |
|
December 31, |
|
|
Project Name |
|
Project Status |
|
2003 |
|
2002 |
|
Fair Value Basis |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
Devon Power LLC
|
|
Operating at a loss |
|
$ |
64,198 |
|
|
$ |
|
|
|
Projected cash flows |
Middletown Power LLC
|
|
Operating at a loss |
|
|
157,323 |
|
|
|
|
|
|
Projected cash flows |
Arthur Kill Power, LLC
|
|
Terminated construction project |
|
|
9,049 |
|
|
|
|
|
|
Projected cash flows |
Langage (UK)
|
|
Terminated |
|
|
(3,091 |
) |
|
|
42,333 |
|
|
Estimated market price/Realized gain |
Turbine
|
|
Sold |
|
|
(21,910 |
) |
|
|
|
|
|
Realized gain |
Berrians Project
|
|
Terminated |
|
|
14,310 |
|
|
|
|
|
|
Realized loss |
Termo Rio
|
|
Terminated |
|
|
6,400 |
|
|
|
|
|
|
Realized loss |
Nelson
|
|
Terminated |
|
|
|
|
|
|
467,523 |
|
|
Similar asset prices |
Pike
|
|
Terminated |
|
|
|
|
|
|
402,355 |
|
|
Similar asset prices |
Bourbonnais
|
|
Terminated |
|
|
|
|
|
|
264,640 |
|
|
Similar asset prices |
Meriden
|
|
Terminated |
|
|
|
|
|
|
144,431 |
|
|
Similar asset prices |
Brazos Valley
|
|
Foreclosure completed in January 2003 |
|
|
|
|
|
|
102,900 |
|
|
Projected cash flows |
Kendall and other expansion projects
|
|
Terminated |
|
|
|
|
|
|
55,300 |
|
|
Projected cash flows |
Turbines & other costs
|
|
Equipment being marketed |
|
|
|
|
|
|
701,573 |
|
|
Similar asset prices |
Audrain
|
|
Operating at a loss |
|
|
|
|
|
|
66,022 |
|
|
Projected cash flows |
Somerset
|
|
Operating at a loss |
|
|
|
|
|
|
49,289 |
|
|
Projected cash flows |
Bayou Cove
|
|
Operating at a loss |
|
|
|
|
|
|
126,528 |
|
|
Projected cash flows |
Other
|
|
|
|
|
2,617 |
|
|
|
28,851 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impairment charges (credits)
|
|
|
|
$ |
228,896 |
|
|
$ |
2,451,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71
For the period from December 6, 2003 to December 31,
2003 we incurred $2.5 million in reorganization costs. For
the period from January 1, 2003 to December 5, 2003,
we incurred $197.8 million in reorganization costs. All
reorganization costs have been incurred since we filed for
bankruptcy in May 2003. The following table provides the detail
of the types of costs incurred (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized |
|
|
Predecessor |
|
|
NRG |
|
|
Company |
|
|
|
|
|
|
|
|
For the Period |
|
|
For the Period |
|
|
December 6 - |
|
|
January 1 - |
|
|
December 31, |
|
|
December 5, |
|
|
2003 |
|
|
2003 |
|
|
|
|
|
|
|
|
(In thousands) |
Reorganization items
|
|
|
|
|
|
|
|
|
|
|
Professional fees
|
|
$ |
2,461 |
|
|
|
$ |
82,186 |
|
|
Deferred financing costs
|
|
|
|
|
|
|
|
55,374 |
|
|
Pre-payment settlement
|
|
|
|
|
|
|
|
19,609 |
|
|
Interest earned on accumulated cash
|
|
|
|
|
|
|
|
(1,059 |
) |
|
Contingent equity obligation
|
|
|
|
|
|
|
|
41,715 |
|
|
|
|
|
|
|
|
|
|
|
|
Total reorganization items
|
|
$ |
2,461 |
|
|
|
$ |
197,825 |
|
|
|
|
|
|
|
|
|
|
|
We incurred $8.7 million of employee separation costs and
advisor fees during the period January 1, 2003 until we
filed for bankruptcy in May 2003. Subsequent to that date we
recorded all advisor fees as reorganization costs. We incurred
total restructuring charges of approximately $111.3 million
for the year ended December 31, 2002. These costs consisted
of employee separation costs and advisor fees.
During the period January 1, 2003 to December 5, 2003,
we recorded $462.6 million of legal settlement charges
which consisted of the following. We recorded
$396.0 million in connection with the resolution of an
arbitration claim asserted by FirstEnergy Corp. As a result of
this resolution, FirstEnergy retained ownership of the Lake
Plant Assets and received an allowed general unsecured claim of
$396.0 million under NRG Energys plan of
reorganization. In November 2003, we settled litigation with
Fortistar Capital in which Fortistar Capital released us from
all litigation claims in exchange for a $60.0 million
pre-petition bankruptcy claim and an $8.0 million
post-petition bankruptcy claim. We had previously recorded
$10.8 million in connection with various legal disputes
with Fortistar Capital; accordingly, we recorded an additional
$57.2 million during November 2003. In November 2003, we
settled our dispute with Dick Corporation in connection with
Meriden Gas Turbines LLC through the payment of a general
unsecured claim and a post-petition pre-confirmation payment.
This settlement resulted in our recording an additional
liability of $8.0 million in November 2003.
In August 1995, we entered into a Marketing, Development and
Joint Proposing Agreement, or the Marketing Agreement, with
Cambrian Energy Development LLC, or Cambrian. Various claims
arose in connection with the Marketing Agreement. In November
2003, we entered into a settlement agreement with Cambrian where
we agreed to transfer our 100% interest in three gasco projects
(NEO Ft. Smith, NEO Phoenix and NEO Woodville) and our 50%
interest in two genco projects (MM Phoenix and MM Woodville) to
Cambrian. In addition, we paid approximately $1.8 million
in settlement of royalties incurred in connection with the
Marketing Agreement. We had previously recorded a liability for
royalties owed to Cambrian, therefore, we recorded an additional
$1.4 million during November 2003.
72
During the fourth quarter of 2003, we recorded a net credit of
$3.9 billion (comprised of a $4.1 billion gain from
continuing operations and a $0.2 billion loss from
discontinued operations) in connection with fresh start
adjustments. Following is a summary of the significant effects
of the reorganization and Fresh Start:
|
|
|
|
|
|
|
|
(In millions) |
Discharge of corporate level debt
|
|
$ |
5,162 |
|
Discharge of other liabilities
|
|
|
811 |
|
Establishment of creditor pool
|
|
|
(1,040 |
) |
Receivable from Xcel
|
|
|
640 |
|
Revaluation of fixed assets
|
|
|
(1,392 |
) |
Revaluation of equity investments
|
|
|
(207 |
) |
Valuation of SO 2 emission credits
|
|
|
374 |
|
Valuation of out of market contracts, net
|
|
|
(400 |
) |
Fair market valuation of debt
|
|
|
108 |
|
Valuation of pension liabilities
|
|
|
(61 |
) |
Other valuation adjustments
|
|
|
(100 |
) |
|
|
|
|
|
Total Fresh Start adjustments
|
|
|
3,895 |
|
|
Less discontinued operations
|
|
|
(224 |
) |
|
|
|
|
|
Total Fresh Start adjustments continuing operations
|
|
$ |
4,119 |
|
|
|
|
|
|
Other income (expense) for the period December 6, 2003
through December 31, 2003, was an expense of
$5.4 million and consisted primarily of $18.9 million
of interest expense, partially offset by $13.5 million of
equity in earnings of unconsolidated affiliates.
During the period January 1, 2003 through December 5,
2003, we recorded other expense of $286.9 million. Other
expense consisted primarily of $329.9 million of interest
expense and $147.1 million of write downs and losses on
sales of equity method investments, partially offset by equity
in earnings of unconsolidated affiliates of $170.9 million
and $19.2 million of other income.
For the year ended December 31, 2002, other expenses were
$572.2 million, which consisted primarily of
$452.2 million of interest expense and $200.5 million
of write downs and losses on sales of equity method investments,
partially offset by equity in earnings of unconsolidated
affiliates of $69.0 million and other income, net of
$11.5 million.
|
|
|
Minority Interest in Earnings of Consolidated Subsidiaries |
For the period December 6, 2003 through December 31,
2003, minority interest in earnings of consolidated subsidiaries
was $134,000 and relates primarily to Northbrook New York and
Northbrook Energy.
73
|
|
|
Equity in Earnings of Unconsolidated Affiliates |
Equity in earnings of unconsolidated affiliates of
$13.5 million for the period December 6, 2003 through
December 31, 2003 consists primarily of equity earnings
from our 50% ownership in West Coast Power of $9.4 million.
During the period January 1, 2003 through December 5,
2003, we recorded $170.9 million of equity earnings from
investments in unconsolidated affiliates. Our 50% investment in
West Coast Power comprised $98.7 million of this amount
with our investments in the Mibrag, Loy Yang, Gladstone and
Rocky Road projects comprising $21.8 million,
$17.9 million, $12.4 million and $6.9 million,
respectively, with the remaining amounts attributable to various
domestic and international equity investments. Our investment in
West Coast Power continues to generate favorable earnings as
well as our investments in Mibrag, Loy Yang, Gladstone and Rocky
Road. For the year ended December 31, 2002, equity earnings
from investments in unconsolidated affiliates was
$69.0 million.
|
|
|
Write-Downs and Losses on Sales of Equity Method
Investments |
As we periodically review our equity method investments for
impairments, we have taken substantial write-downs and losses on
sales of equity method investments during the period
January 1, 2003 through December 5, 2003 and for the
year 2002. During the period January 1, 2003 to
December 5, 2003, we recorded impairments and losses on the
sales of investments of $147.1 million compared to
$200.5 million in 2002. The $147.1 million recorded in
2003 consists primarily of the write down of our investment in
the Loy Yang project of $146.4 million, our investment in
the NEO Corporation Minnesota Methane project of
$12.3 million and our investment in NEO
Corporation MM Biogas of $2.6 million. These
losses were partially offset by gains on the sale of our
investment in the ECKG and Mustang projects of $2.9 million
and $12.1 million, respectively. During 2002 we recorded
write-downs and losses on sales of equity method investments of
$200.5 million. The $200.5 million recorded in 2002
consists primarily of a write down of our investment in the Loy
Yang project of $111.4 million, a loss of
$48.4 million on the transfer of our interest in the Sabine
River Works project to our partner, a $14.2 million write
down related to our investment in our EDL project, a write down
of our investment in our Kondapalli project of
$12.7 million and a write down of our investment in NEO
Corporation Minnesota Methane and MM Biogas of
$12.3 million and $3.2 million, respectively among
others, offset by a $9.9 million gain on sale of our
Kingston project.
Other income, net consists primarily of interest income earned
on notes receivable and cash balances. We recorded $97,000,
$19.2 million and $11.4 million of other income, net
for the periods December 6, 2003 through December 31,
2003 and January 1, 2003 through December 5, 2003 and
for the year ended December 31, 2002, respectively.
Interest expense for the period December 6, 2003 through
December 31, 2003 of $18.9 million consists primarily
of interest expense at the corporate level, primarily related to
the Second Priority Notes, term loan facility and revolving line
of credit used to refinance certain project-level financings. In
addition, interest expense includes the amortization of deferred
financing costs incurred as a result of our refinancing efforts
and the amortization of discounts and premiums recorded upon the
marking of our debt to fair value upon our adoption of the Fresh
Start provision of SOP 90-7.
74
Interest expense for the period January 1, 2003 through
December 5, 2003 of $329.9 million consisted of
interest expense on both our project and corporate level
interest bearing debt. In addition, interest expense includes
the amortization of debt issuance costs and any interest rate
swap termination costs. Subsequent to our entering into
bankruptcy we ceased the recording of interest expense on our
corporate level debt as these pre-petition claims were deemed to
be impaired and subject to compromise. We did not however cease
to record interest expense on the project-level debt outstanding
at our Northeast Generating and South Central Generating
facilities even though these entities were also in bankruptcy as
these claims were deemed to be most likely not impaired and not
subject to compromise. We also recorded substantial amounts of
fees and costs related to our acquiring a debtor in possession
financing arrangement while we were in bankruptcy. In addition,
upon our emergence from bankruptcy we wrote off any remaining
deferred finance costs related to our corporate and
project-level debt including our Northeast and South Central
project-level debt as it was probable that they would be
refinanced upon our emergence from bankruptcy.
Interest expense was $452.2 million for the year ended
December 31, 2002.
Income tax benefit for the period December 6, 2003 through
December 31, 2003 was ($0.7) million and the overall
effective tax rate was (6.2%). The rate is lower than the
U.S. statutory rate primarily due to a state tax refund
received from Xcel Energy in 2003, foreign income taxed in
jurisdictions with tax rates different from the
U.S. statutory rate and a decrease in unfavorable permanent
differences.
Our deferred tax assets at December 31, 2003 were offset by
a full valuation allowance in accordance with
SFAS No. 109. Under SOP 90-7, any future benefits
from reducing a valuation allowance from preconfirmation
deferred tax assets are required to be reported as a direct
addition to paid in capital versus a benefit on our income
statement. Consequently, our effective tax rate in
post-bankruptcy emergence years will not benefit from the
realization of our deferred tax assets, which were fully valued
as of the date of our emergence from bankruptcy. The adoption of
this Statement of Position will result in a disallowance of a
future income statement benefit of $1.3 billion as a result
of a reduction to the intangible asset for realization of
benefits of fully valued deferred tax assets as of
December 5, 2003 (date of emergence from bankruptcy).
The effective tax rate may vary from year to year depending on,
among other factors, the geographic and business mix of earnings
and losses. These same and other factors, including history of
pre-tax earnings and losses, are taken into account in assessing
the ability to realize deferred tax assets.
Income tax expense (benefit) for the period January 1, 2003
through December 5, 2003 was a tax expense of
$37.9 million and a tax benefit of ($166.9) million
for the year ended December 31, 2002. The overall effective
tax rate for the short period ended December 5, 2003 and
the year ended December 31, 2002 was 1.3% and 5.6%,
respectively. The change in our effective tax rate was primarily
due to a release in valuation allowance for net operating loss
carryforwards that were utilized following our emergence from
bankruptcy to offset the current tax on cancellation of debt
income.
Discontinued operations for the period December 6, 2003
through December 31, 2003 is comprised of a loss of
$0.4 million attributable to the on going operations of our
McClain, PERC, Cobee, LSP Energy, Hsin Yu and four NEO
Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO
Prima Deshecha LLC and NEO Tajiguas LLC).
75
As of December 5, 2003, we classified as discontinued
operations the operations and gains/losses recognized on the
sales of projects that were sold or were deemed to have met the
required criteria for such classification pending final
disposition. For the period January 1, 2003 through
December 5, 2003, discontinued operations consist of the
historical operations and net gains/losses related to our
Killingholme, McClain, PERC, Cobee, NLGI, seven NEO Corporation
projects, TERI, Cahua, Energia Pacasmayo, LSP Energy and Hsin Yu
projects. Discontinued operations for the year ended
December 31, 2002 consisted of our Crockett Cogeneration,
Entrade, Killingholme, Csepel, Bulo Bulo, McClain, PERC, Cobee,
NLGI, seven NEO Corporation projects, TERI, Cahua, Energia
Pacasmayo, LSP Energy and Hsin Yu projects.
For the period January 1, 2003 through December 5,
2003, the results of operations related to such discontinued
operations was a net loss of $182.6 million due to a loss
on the sale of our Peru projects, impairment charges of
$100.7 million and $23.6 million, respectively,
recorded at McClain and NLGI and fresh start adjustments at LSP
Energy.
During 2002, we recognized a loss on discontinued operations of
$675.8 million due primarily to asset impairments recorded
at Killingholme, NLGI, TERI, LSP Energy and Hsin Yu projects.
Reorganization and Emergence from Bankruptcy
On May 14, 2003, we and 25 of our U.S. affiliates,
filed voluntary petitions for reorganization under
Chapter 11 of the United States Bankruptcy Code, or the
Bankruptcy Code, in the United States Bankruptcy Court for the
Southern District of New York, or the bankruptcy court.
On May 15, 2003, NRG Energy, PMI, NRG Finance Company
I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital
LLC, collectively the Plan Debtors, filed the NRG plan of
reorganization and the related Disclosure Statement for
Reorganizing Debtors Joint Plan of Reorganization Pursuant
to Chapter 11 of the United States Bankruptcy Code, as
subsequently amended, or the Disclosure Statement. The
Bankruptcy Court held a hearing on the Disclosure Statement on
June 30, 2003, and instructed the Plan Debtors to include
certain additional disclosures. The Plan Debtors amended the
Disclosure Statement and obtained Bankruptcy Court approval for
the Third Amended Disclosure Statement for Debtors Second
Amended Joint Plan of Reorganization Pursuant to Chapter 11
of the Bankruptcy Code.
On November 24, 2003, the bankruptcy court issued an order
confirming the NRG plan of reorganization, and the plan became
effective on December 5, 2003. On September 17, 2003,
the Northeast/ South Central plan of reorganization was proposed
after we secured the necessary financing commitments. On
November 25, 2003, the bankruptcy court issued an order
confirming the Northeast/ South Central plan of reorganization
and the plan became effective on December 23, 2003.
|
|
|
Financial Reporting by Entities in Reorganization under
the Bankruptcy Code and Fresh Start |
Between May 14, 2003 and December 5, 2003, we operated
as a debtor-in-possession under the supervision of the
bankruptcy court. Our financial statements for reporting periods
within that timeframe were prepared in accordance with the
provisions of Statement of Position 90-7,
Financial Reporting by Entities in Reorganization Under
the Bankruptcy Code, or SOP 90-7.
For financial reporting purposes, the close of business on
December 5, 2003, represents the date of emergence from
bankruptcy. As used herein, the following terms refer to the
Company and its operations:
|
|
|
Predecessor Company
|
|
The Company, pre-emergence from bankruptcy
The Companys operations prior to December 6, 2003 |
Reorganized NRG
|
|
The Company, post-emergence from bankruptcy
The Companys operations from December 6, 2003-
December 31, 2004 |
76
The implementation of the NRG plan of reorganization resulted
in, among other things, a new capital structure, the
satisfaction or disposition of various types of claims against
the Predecessor Company, the assumption or rejection of certain
contracts, and the establishment of a new board of directors.
In connection with the emergence from bankruptcy, we adopted
Fresh Start in accordance with the requirements of
SOP 90-7. The application of SOP 90-7 resulted in the
creation of a new reporting entity. Under Fresh Start, the
enterprise value of our company was allocated among our assets
and liabilities on a basis substantially consistent with
purchase accounting in accordance with SFAS No. 141
Business Combinations, or
SFAS No. 141. Accordingly, we pushed down the effects
of this allocation to all of our subsidiaries.
Under the requirements of Fresh Start, we have adjusted our
assets and liabilities, other than deferred income taxes, to
their estimated fair values as of December 5, 2003. As a
result of marking our assets and liabilities to their estimated
fair values, we determined that there was no excess
reorganization value that was reallocated back to our tangible
and intangible assets. Deferred taxes were determined in
accordance with SFAS No. 109, Accounting for
Income Taxes. The net effect of all Fresh Start
adjustments resulted in a gain of $3.9 billion (comprised
of a $4.1 billion gain from continuing operations and a
$0.2 billion loss from discontinued operations), which is
reflected in the Predecessor Companys results of
operations for the period January 1, 2003 through
December 5, 2003. The application of the Fresh Start
provisions of SOP 90-7 created a new reporting entity
having no retained earnings or accumulated deficit.
As part of the bankruptcy process we engaged an independent
financial advisor to assist in the determination of our
reorganized enterprise value. The fair value calculation was
based on managements forecast of expected cash flows from
our core assets. Managements forecast incorporated forward
commodity market prices obtained from a third party consulting
firm. A discounted cash flow calculation was used to develop the
enterprise value of Reorganized NRG, determined in part by
calculating the weighted average cost of capital of the
Reorganized NRG. The Discounted Cash Flow, or DCF, valuation
methodology equates the value of an asset or business to the
present value of expected future economic benefits to be
generated by that asset or business. The DCF methodology is a
forward looking approach that discounts expected
future economic benefits by a theoretical or observed discount
rate. The independent financial advisors prepared a 30-year cash
flow forecast using a discount rate of approximately 11%. The
resulting reorganization enterprise value as included in the
Disclosure Statement ranged from $5.5 billion to
$5.7 billion. The independent financial advisor then
subtracted our project-level debt and made several other
adjustments to reflect the values of assets held for sale,
excess cash and collateral requirements to estimate a range of
Reorganized NRG equity value of between $2.2 billion and
$2.6 billion.
In constructing our Fresh Start balance sheet upon our emergence
from bankruptcy, we used a reorganization equity value of
approximately $2.4 billion, as we believe this value to be
the best indication of the value of the ownership distributed to
the new equity owners. Our NRG plan of reorganization provided
for the issuance of 100,000,000 shares of NRG common stock
to the various creditors resulting in a calculated price per
share of $24.04. Our reorganization value of approximately
$9.1 billion was determined by adding our reorganized
equity value of $2.4 billion, $3.7 billion of interest
bearing debt and our other liabilities of $3.0 billion. The
reorganization value represents the fair value of an entity
before liabilities and approximates the amount a willing buyer
would pay for the assets of the entity immediately after
restructuring. This value is consistent with the voting
creditors and bankruptcy courts approval of the NRG plan
of reorganization.
We recorded approximately $3.9 billion of net
reorganization income (comprised of a $4.1 billion gain
from continuing operations and a $0.2 billion loss from
discontinued operations) in the Predecessor Companys
statement of operations for 2003, which includes the gain on the
restructuring of equity and the discharge of obligations subject
to compromise for less than recorded amounts, as well as
adjustments to the historical carrying values of our assets and
liabilities to fair market value.
Due to the adoption of Fresh Start as of December 5, 2003,
the Reorganized NRG post-Fresh Start statement of operations and
statement of cash flows have not been prepared on a consistent
basis with the Predecessor Companys financial statements
and are therefore not comparable in certain respects to the
77
financial statements prior to the application of Fresh Start.
The accompanying Consolidated Financial Statements have been
prepared to distinguish between Reorganized NRG and the
Predecessor Company.
APB No. 18, The Equity Method of Accounting for
Investments in Common Stock, requires us to
effectively push down the effects of Fresh Start reporting to
our unconsolidated equity method investments and to recognize an
adjustment to our share of the earnings or losses of an investee
as if the investee were a consolidated subsidiary. As a result
of pushing down the impact of Fresh Start to our West Coast
Power affiliate, we determined that a contract based intangible
asset with a one year remaining life, consisting of the value of
West Coast Powers California Department of Water Resources
energy sales contract, must be established and recognized as a
basis adjustment to our share of the future earnings generated
by West Coast Power. This adjustment reduced our equity earnings
in the amount of $115.8 million for the year ended
December 31, 2004. This contract expired in December 2004.
Liquidity and Capital Resources
|
|
|
Reorganized Capital Structure |
In connection with the consummation of our reorganization, on
December 5, 2003, all shares of our old common stock were
canceled and 100,000,000 shares of new common stock of
NRG Energy were distributed pursuant to such plan in
accordance with Section 1145 of the bankruptcy code to the
holders of certain classes of claims. We received no proceeds
from such issuance. A certain number of shares of common stock
were issued and placed in the Disputed Claims Reserve for
distribution to holders of disputed claims as such claims are
resolved or settled. See Item 3 Legal
Proceedings Disputed Claims Reserve. In the event
our disputed claims reserve is inadequate, it is possible we
will have to issue additional shares of our common stock to
satisfy such pre-petition claims or contribute additional cash
proceeds. Our authorized capital stock consists of
500,000,000 shares of NRG Energy common stock and
10,000,000 shares of preferred stock. A total of
4,000,000 shares of our common stock are available for
issuance under our long-term incentive plan.
In addition to our issuance of new common stock, on
December 23, 2003, we completed a note offering consisting
of $1.25 billion of 8% Second Priority Senior Secured Notes
due 2013, or the Second Priority Notes, and we entered into a
new $1.45 billion credit facility consisting of a
$950.0 million term loan facility, a $250.0 million
funded letter of credit facility and a $250.0 million
revolving credit facility. In connection with the consummation
of the NRG plan of reorganization, we issued to Xcel Energy a
$10.0 million non-amortizing promissory note, which accrues
interest at a rate of 3% per annum and matures
2.5 years after the effective date of the NRG plan of
reorganization. In January 2004, we completed a supplementary
note offering whereby we issued an additional
$475.0 million of the Second Priority Notes at a premium
and used the proceeds to repay a portion of the
$950.0 million term loan. On December 24, 2004, we
amended and restated our existing $1.45 billion credit
facility, recasting it as a $950 million secured credit
facility made up of a $450.0 million seven-year senior
secured term loan, a $350.0 million funded letter of credit
facility and a three-year $150.0 million revolving line of
credit. In December 2004, we also issued $420 million of
convertible preferred stock and used the proceeds from such
issuance to redeem $375 million of the Second Priority
Notes in February 2005. Also in January 2005 and in
March 2005, we used existing cash to purchase, at market
prices, $25 million and $15.8 million, respectively,
in face value of our Second Priority Notes. These notes were
assumed by NRG Energy and therefore remain outstanding. As of
March 21, 2005, we had $1.35 billion in aggregate
principal amount of Second Priority Notes outstanding,
$450.0 million principal amount outstanding under the term
loan and $350 million of the funded letter of credit
facility outstanding. $178.3 million of undrawn letters of
credit remain available under the funded letter of credit
facility. As of March 21, 2005, we had not drawn down on
our revolving credit facility.
78
The following table summarizes the debt transactions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at |
|
|
|
Outstanding at |
|
|
|
Outstanding at |
|
|
Date of |
|
Original |
|
December 31, |
|
|
|
December 31, |
|
|
|
March 21, |
|
|
Transaction |
|
Amount |
|
2003 |
|
Activity |
|
2004 |
|
Activity |
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Xcel Promissory Note
|
|
|
Dec. 6, 2003 |
|
|
$ |
10,000 |
|
|
$ |
10,000 |
|
|
|
|
|
|
$ |
10,000 |
|
|
|
|
|
|
$ |
10,000 |
|
NRG 8% Senior Secured Notes
|
|
|
Dec. 23, 2003 |
|
|
$ |
1,250,000 |
|
|
$ |
1,250,000 |
|
|
|
|
|
|
$ |
1,250,000 |
|
|
|
|
|
|
|
|
|
|
Tack-on offering
|
|
|
Jan. 28, 2004 |
|
|
|
|
|
|
|
|
|
|
$ |
475,000 |
|
|
$ |
475,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,725,000 |
|
|
|
|
|
|
$ |
1,725,000 |
|
|
Repurchase of Notes*
|
|
|
Jan. 21-27, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(25,000 |
) |
|
|
|
|
|
Early Redemption
|
|
|
Feb. 4, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(375,000 |
) |
|
|
(375,000 |
) |
|
Repurchase of Notes*
|
|
|
March 28, 2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(15,838 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,350,000 |
|
NRG Credit Facility Term loan
|
|
|
Dec. 23, 2003 |
|
|
$ |
950,000 |
|
|
$ |
950,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letter of Credit facility
|
|
|
Dec. 23, 2003 |
|
|
|
250,000 |
|
|
$ |
250,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate Revolver
|
|
|
Dec. 23, 2003 |
|
|
|
250,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG New Credit Facility
|
|
|
|
|
|
$ |
1,450,000 |
|
|
$ |
1,200,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinancing of the Credit Facility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amended Credit Facility
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Term loan
|
|
|
Dec. 24, 2004 |
|
|
$ |
450,000 |
|
|
|
|
|
|
|
|
|
|
$ |
450,000 |
|
|
|
|
|
|
$ |
450,000 |
|
|
Letter of Credit facility
|
|
|
Dec. 24, 2004 |
|
|
|
350,000 |
|
|
|
|
|
|
|
|
|
|
|
350,000 |
|
|
|
|
|
|
|
350,000 |
|
|
Corporate Revolver
|
|
|
Dec. 24, 2004 |
|
|
|
150,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Amended Credit Facility
|
|
|
|
|
|
$ |
950,000 |
|
|
|
|
|
|
|
|
|
|
$ |
800,000 |
|
|
|
|
|
|
$ |
800,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Corporate Level Debt
|
|
|
|
|
|
|
|
|
|
$ |
2,460,000 |
|
|
|
|
|
|
$ |
2,535,000 |
|
|
|
|
|
|
$ |
2,160,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
* |
The notes were assumed by NRG Energy and remain outstanding. |
As part of the NRG plan of reorganization, we eliminated
approximately $5.2 billion of corporate level bank and bond
debt and approximately $1.3 billion of additional claims
and disputes through our distribution of new common stock and
$1.04 billion in cash among our unsecured creditors. In
addition to the debt reduction associated with the
restructuring, we used the proceeds of the Second Priority Notes
and borrowings under our credit facility to retire approximately
$1.7 billion of project-level debt.
For additional information on our short-term and long-term
borrowing arrangements, see Item 15
Note 18 to the Consolidated Financial Statements.
We have obtained cash from operations, Xcel Energys
contribution net of distributions to creditors, proceeds from
the sale of certain assets, borrowings under our Second Priority
Notes and credit facilities and the proceeds from the sale of
preferred stock. We have used these funds to finance operations,
service debt obligations, finance capital expenditures,
repurchase common stock and meet other cash and liquidity needs.
Historically, we have obtained cash from operations, issuance of
debt and equity securities, borrowings under credit facilities,
capital contributions from Xcel Energy, reimbursement by Xcel
Energy of tax benefits pursuant to a tax sharing agreement and
proceeds from non-recourse project financings. We used these
funds
79
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
|
Predecessor Company |
|
|
|
|
|
|
|
|
|
|
For the Period |
|
|
For the Period |
|
|
|
|
Year Ended |
|
December 6- |
|
|
January 1- |
|
Year Ended |
|
|
December 31, |
|
December 31, |
|
|
December 5, |
|
December 31, |
|
|
2004 |
|
2003 |
|
|
2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Net cash provided (used) by operating activities
|
|
$ |
643,993 |
|
|
$ |
(588,875 |
) |
|
|
$ |
238,509 |
|
|
$ |
430,042 |
|
Net cash (used) provided by investing activities
|
|
|
184,685 |
|
|
|
363,372 |
|
|
|
|
(185,679 |
) |
|
|
(1,681,467 |
) |
Net cash provided (used) by financing activities
|
|
|
(283,734 |
) |
|
|
393,273 |
|
|
|
|
(29,944 |
) |
|
|
1,449,330 |
|
|
|
|
Net Cash Provided (Used) By Operating Activities |
For the year ended December 31, 2004, net cash provided by
operating activities was $644.0 million. Net income of
$185.6 million and adjustments of $383.3 million
accounted for $568.9 million of the total cash provided by
operating activities. Non-cash adjustments consist primarily of
depreciation, amortization and impairment charges offset by
unrealized gains on derivatives. Cash provided by working
capital of $75.0 million reflects a $100 million net
resolution of a bankruptcy-related receivable and payable offset
by other working capital changes of $25.0 million.
For the period December 6, 2003 through December 31,
2003, net cash used by operating activities was
$588.9 million. This was primarily a result of payments
made to creditors upon our emergence from bankruptcy.
For the period January 1, 2003 through December 5,
2003, net cash provided by operating activities was
$238.5 million. Operating activities consisted of a net
loss before Fresh Start adjustments of $1.1 billion, offset
by non-cash charges of $567.5 million and cash provided by
working capital of $800.1 million. The non-cash charges
consisted primarily of the write-down of our investment in Loy
Yang, asset impairments and legal settlement charges. The
favorable change in working capital was primarily due to reduced
cash expenditures throughout the bankruptcy period resulting in
increased accounts payable.
For the year ended December 31, 2002, net cash provided by
operating activities was $430.0 million. Operating
activities consisted of a net loss before restructuring and
impairment charges of $319.8 million offset by non-cash
charges of $144.5 million and cash provided by working
capital of $605.3 million.
|
|
|
Net Cash Provided (Used) By Investing Activities |
For the year ended December 31, 2004, net cash provided by
investing activities was $184.7 million due primarily to
sales proceeds, net of cash on hand, of $252.7 million on
the sale of discontinued operations and sale proceeds of
$50.7 million from the sale of investments, offset by
capital expenditures of $114.4 million.
For the period December 6, 2003 through December 31,
2003, net cash provided by investing activities was
$363.4 million. In connection with the refinancing
transaction, approximately $375.3 million of restricted
cash was released upon payment of the Northeast Generating and
South Central Generating note. This increase was offset by funds
used for capital expenditures and investments in projects.
80
For the period January 1, 2003 through December 5,
2003, net cash used in investing activities was
$185.7 million. This was primarily a result of capital
expenditures and an increase in restricted cash, offset by cash
proceeds received upon the sale of investments.
For the year ended December 31, 2002, net cash used by
investing activities was $1.7 billion due primarily to
$1.4 billion of capital expenditures.
|
|
|
Net Cash Provided (Used) By Financing Activities |
For the year ended December 31, 2004, net cash used by
financing activities was $283.7 million primarily due to
reduction of long-term debt by $159.3 million, which was
primarily related to the McClain sale. Financing activities were
also driven by an increase in the funded letter of credit asset
balance of $100.0 million. In December 2004, the Company
issued preferred stock for net proceeds of $406.4 million
which enabled us to redeem $375.0 million of senior secured
notes in 2005. Available cash balances were used to
purchase 13 million shares of common stock owned by
MatlinPatterson for a price of $405.3 million.
For the period December 6, 2003 through December 31,
2003, net cash provided by financing activities was
$393.3 million. We entered into refinancing transactions on
December 23, 2003, where we issued $1.25 billion of
Second Priority Notes and entered into the New Credit Facility,
which consisted of a $950.0 million senior secured term
loan facility, a $250.0 million funded letter of credit
facility and a $250.0 million unfunded revolving line of
credit. Upon completion of the refinancing transactions, we
repaid the Northeast Generating and South Central Generating
notes and the Mid-Atlantic Generating obligations.
For the period January 1, 2003 through December 5,
2003, net cash used by financing activities was
$29.9 million, which consisted primarily of principal
payments offset by the issuance of additional debt.
For the year ended December 31, 2002, net cash provided by
financing activities was $1.4 billion which consisted
primarily of increased debt of $945.3 and a capital contribution
from Xcel Energy in the amount of $500.0 million.
The principal sources of liquidity for our future operations and
capital expenditures are expected to be: (i) existing cash
on hand and cash flows from operations and (ii) proceeds
from the sale of certain assets and businesses. Additionally, we
have approximately $192.9 million of undrawn letter of
credit capacity under our senior credit facility as of
December 31, 2004.
On December 24, 2004, we amended our corporate bank
facility, which at December 31, 2004 consists of a
$450.0 million, seven-year senior secured term loan, a
$350.0 million funded letter of credit facility, and a
three-year $150.0 million revolving line of credit, or the
revolving credit facility. With the refinancing, we lowered the
interest rate on the term loan to LIBOR plus 1.875% from LIBOR
plus 4.0%. Portions of the revolving credit facility are
available as a swing-line facility and as a revolving letter of
credit sub-facility. As of December 31, 2004, the corporate
revolver was undrawn.
On December 27, 2004, we completed the sale of
$420 million of convertible perpetual preferred stock with
a dividend coupon rate of 4%. The Preferred Stock has a
liquidation preference of $1,000 per share of Preferred
Stock. Holders of Preferred Stock are entitled to receive, when,
as and if declared by our Board of Directors, out of funds
legally available therefore, cash dividends at the rate of
4% per annum, payable quarterly in arrears on
March 15, June 15, September 15 and December 15 of
each year, commencing on March 15, 2005. The Preferred
Stock is convertible, at the option of the holder, at any time
into shares of our common stock at an initial conversion price
of $40.00 per share, which is equal to an approximate
conversion rate of 25 shares of common stock per share of
Preferred Stock, subject to specified adjustments. On or after
81
December 20, 2009, we may redeem, subject to certain
limitations, some or all of the Preferred Stock with cash at a
redemption price equal to 100% of the liquidation preference,
plus accumulated but unpaid dividends, including liquidated
damages, if any, to the redemption date.
Proceeds of $406.4 million from the sale of the preferred
securities are net of securities issuance costs of approximately
$13.6 million, and on February 4, 2005, these proceeds
along with cash on hand were used to redeem $375.0 million
in Second Priority Notes, pay an early redemption penalty of
$30.0 million and pay accrued interest of $4.1 million
on the redeemed notes.
Cash Flows. Our operating cash flows are expected to be
impacted by, among other things: (i) spark spreads
generally; (ii) commodity prices (including demand for
natural gas, coal, oil and electricity); (iii) the cost of
ordinary course operations and maintenance expenses including
margin and collateral calls for our trading operation;
(iv) planned and unplanned outages; (v) contraction of
terms by trade creditors; (vi) cash requirements for
closure and restructuring of certain facilities;
(vii) restrictions in the declaration or payments of
dividends or similar distributions from our subsidiaries; and
(viii) the timing and nature of asset sales.
A principal component of the NRG plan of reorganization is a
settlement with Xcel Energy in which Xcel Energy agreed to make
a contribution to us consisting of cash (and, under certain
circumstances, its common stock) in an aggregate amount of up to
$640.0 million to be paid in three separate installments.
Xcel Energy contributed $288.0 million on February 20,
2004, $328.5 million on April 30, 2004 and
$23.5 million on May 28, 2004. We distributed
$540.0 million of cash we received from Xcel Energy to our
creditors pursuant to our plan of reorganization. We retained
the remaining $100.0 million, which we used for general
corporate purposes.
Asset Sales. We received $303.4 million,
$196.5 million and $229.3 million in cash proceeds
from the sale of certain assets and businesses in the fiscal
years ended 2004, 2003 and 2002, respectively. The Amended
Credit Facility and the indenture governing the notes place
restrictions on the use of any proceeds we may receive from
certain asset sales in the future.
Letter of Credit Sub-facility and Revolving Credit
Facility. The Amended Credit Facility includes a letter of
credit sub-facility in the amount of $350.0 million. As of
December 31, 2004, we had issued $157.1 million in
letters of credit under this facility, leaving
$192.9 million available for future issuance. The Amended
Credit Facility also includes a revolving credit facility in the
amount of $150.0 million to be used for general corporate
purposes. On December 31, 2004 our revolving credit
facility was undrawn. For additional information regarding our
debt see Item 15 Note 18 to the
Consolidated Financial Statements.
Our requirements for liquidity and capital resources, other than
for operating our facilities, can generally be categorized by
the following: (i) PMI activities; (ii) capital
expenditures; (iii) corporate financial restructuring and
(iv) project finance requirements for cash collateral.
PMI. PMI activities comprise the single largest
requirement for liquidity and capital resources. PMI liquidity
requirements are primarily driven by: (i) margin and
collateral posted with counter-parties; (ii) initial
collateral required to establish trading relationships;
(iii) timing of disbursements and receipts (i.e., buying
fuel before receiving energy revenues); and (iv) initial
collateral for large structured transactions. As of
December 31, 2004, PMI had total collateral outstanding of
$47.8 million in margin, prepayments and cash deposits and
$83.1 million outstanding in letters of credit to third
parties.
Future liquidity requirements may change based on our hedging
activity, fuel purchases, future market conditions, including
forward prices for energy and fuel and market volatility. In
addition, liquidity requirements are dependent on our credit
ratings and general perception of creditworthiness. We do not
assume that we will be given unsecured credit from third parties
in budgeting our working capital requirements.
Capital Expenditures. Capital expenditures were
$114.4 million for the year ended December 31, 2004,
$10.6 million for the period December 6, 2003 through
December 31, 2003, $113.5 million for the period
82
January 1, 2003 through December 5, 2003 and
$1.4 billion for the year ended 2002. Capital expenditures
in 2004 relate primarily to the conversion of our western New
York plants to low-sulfur coal, the Playford 2 refurbishment at
our Flinders operation in Australia and planned outages across
our fleet. Capital expenditures in 2003 relate primarily to
operations and maintenance of our existing generating facilities
whereas capital expenditures in 2002 related primarily to new
plant construction. In 2005, we anticipate we will spend
approximately $133.3 million in capital expenditures and an
additional $109.5 million in major maintenance expense
related primarily to the operation and maintenance of our
existing generating facilities.
Corporate Financial Restructuring. We may elect
periodically to modify our corporate financial structure in
order to increase near-term or long-term cash flows or to reduce
exposure to financial risks. On December 21, 2004, we
purchased 13 million shares of common equity interest in
NRG Energy from investment partnerships managed by
MatlinPatterson. Total costs associated with the repurchase,
including fees and expenses, was $405.3 million. On
February 4, 2005, we used proceeds from our Preferred Stock
issuance to redeem early $375.0 million of our Second
Priority Notes at par value plus 8%. We also paid outstanding
accrued interest and liquidated damage penalties attributable to
the redeemed notes. In January 2005 and March 2005, we
repurchased $25.0 million and $15.8 million,
respectively, of our notes, which remain outstanding. As of
March 21, 2005, $1.35 billion in Second Priority Notes
remain outstanding.
Preferred Dividend Payment. On March 15, 2005, we
made a $3.9 million dividend payment to our preferred
shareholders of record as of March 1, 2005. This represents
the first quarterly dividend payment we anticipate making to our
preferred shareholders.
Project Finance Requirements. We are a holding company
and conduct our operations through subsidiaries. Historically,
we have utilized project-level debt to fund a significant
portion of the capital expenditures and investments required to
construct our power plants and related assets. Consistent with
our strategy, we may seek, where available on commercially
reasonable terms, project-level debt in connection with the
assets or businesses that our affiliates or we may develop,
construct or acquire. Project-level borrowings are substantially
non-recourse to other subsidiaries, affiliates and us, and are
generally secured by the capital stock, physical assets,
contracts and cash flow of the related project subsidiary or
affiliate being financed. Some of these project financings may
require us to post collateral in the form of cash or an
acceptable letter of credit.
In February 2005, Flinders amended its debt facility of AUD
279.4 million (approximately US $218.5 million)
in floating-rate debt. The amendment extended the maturity to
February 2017, reduced borrowing costs and reserve requirements,
minimized debt service coverage ratios, removed mandatory cash
sharing arrangements, and made other minor modifications to
terms and conditions. The facility includes an AUD
20 million (approximately US $15.7 million)
working capital and performance bond facility. NRG Flinders is
required to maintain interest-rate hedging contracts on a
rolling 5-year basis at a minimum level of 60% of principal
outstanding. Upon execution of the amendment, a voluntary
principal prepayment of AUD 50 million (approximately
US $39.1 million) was made, reducing the principal
balance to AUD 229.2 million (approximately
$179.4 million).
83
Principal on short-term debt, long-term debt and capital leases
as of December 31, 2004 are due and payable in the
following periods (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary/Description |
|
Total |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
Thereafter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Xcel Energy Note
|
|
$ |
10,000 |
|
|
$ |
|
|
|
$ |
10,000 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Credit Facility Due Dec. 2011
|
|
|
800,000 |
|
|
|
8,000 |
|
|
|
8,000 |
|
|
|
8,000 |
|
|
|
8,000 |
|
|
|
8,000 |
|
|
|
760,000 |
|
8% Second Priority Notes due Dec. 2013
|
|
|
1,725,000 |
|
|
|
400,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,325,000 |
|
NRG Energy Center Minneapolis, due 2013 and 2017
|
|
|
118,950 |
|
|
|
7,877 |
|
|
|
8,465 |
|
|
|
9,097 |
|
|
|
9,776 |
|
|
|
10,507 |
|
|
|
73,228 |
|
NRG Peaker Finance Co LLC
|
|
|
300,876 |
|
|
|
4,312 |
|
|
|
6,768 |
|
|
|
11,164 |
|
|
|
12,903 |
|
|
|
14,758 |
|
|
|
250,971 |
|
Flinders Power Finance Pty
|
|
|
202,856 |
|
|
|
11,564 |
|
|
|
13,443 |
|
|
|
14,633 |
|
|
|
15,931 |
|
|
|
14,083 |
|
|
|
133,202 |
|
NRG Energy Center San Francisco
|
|
|
129 |
|
|
|
32 |
|
|
|
31 |
|
|
|
37 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
Camas Pwr BLR LP Bank facility
|
|
|
6,275 |
|
|
|
2,442 |
|
|
|
2,533 |
|
|
|
1,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Camas Pwr BLR LP Bonds
|
|
|
4,475 |
|
|
|
1,385 |
|
|
|
1,485 |
|
|
|
1,605 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Itiquira Energetica S.A., due January 2012
|
|
|
20,078 |
|
|
|
2,845 |
|
|
|
2,845 |
|
|
|
2,845 |
|
|
|
2,845 |
|
|
|
2,845 |
|
|
|
5,853 |
|
Itiquira Energetica S.A., due April 2011
|
|
|
31,002 |
|
|
|
|
|
|
|
3,875 |
|
|
|
3,875 |
|
|
|
3,875 |
|
|
|
3,875 |
|
|
|
15,502 |
|
Northbrook New York
|
|
|
16,900 |
|
|
|
500 |
|
|
|
600 |
|
|
|
700 |
|
|
|
800 |
|
|
|
850 |
|
|
|
13,450 |
|
Northbrook Carolina
|
|
|
2,375 |
|
|
|
100 |
|
|
|
100 |
|
|
|
150 |
|
|
|
150 |
|
|
|
150 |
|
|
|
1,725 |
|
Northbrook STS HydroPower
|
|
|
24,329 |
|
|
|
477 |
|
|
|
523 |
|
|
|
572 |
|
|
|
627 |
|
|
|
807 |
|
|
|
21,323 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal Debt, Bonds and
Notes
|
|
|
3,263,245 |
|
|
|
439,534 |
|
|
|
58,668 |
|
|
|
53,978 |
|
|
|
54,936 |
|
|
|
55,875 |
|
|
|
2,600,254 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau (capital lease)
|
|
|
303,803 |
|
|
|
69,904 |
|
|
|
51,785 |
|
|
|
38,612 |
|
|
|
31,693 |
|
|
|
23,786 |
|
|
|
88,023 |
|
Audrain Generating (capital lease)
|
|
|
239,930 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
239,930 |
|
Conemaugh Fuels LLC (capital lease)
|
|
|
218 |
|
|
|
16 |
|
|
|
18 |
|
|
|
19 |
|
|
|
20 |
|
|
|
22 |
|
|
|
123 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal Capital Leases
|
|
|
543,951 |
|
|
|
69,920 |
|
|
|
51,803 |
|
|
|
38,631 |
|
|
|
31,713 |
|
|
|
23,808 |
|
|
|
328,076 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt
|
|
$ |
3,807,196 |
|
|
$ |
509,454 |
|
|
$ |
110,471 |
|
|
$ |
92,609 |
|
|
$ |
86,649 |
|
|
$ |
79,683 |
|
|
$ |
2,928,330 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
These amounts reflect scheduled amortization of principal as of
December 31, 2004, with the exception of the 8% Senior
Secured Notes, for which 2005 amounts reflect early redemption
and repurchases made through March 21, 2005. See
Item 15 Note 18 to the Consolidated
Financial Statements for further discussion on events that may
affect debt payment schedules.
On December 24, 2004, we amended and restated our senior
credit facility, which now consists of a $450.0 million,
seven-year senior secured term loan facility, a
$350.0 million funded letter of credit facility, and a
three-year revolving credit facility in an amount up to
$150.0 million. At that time, we paid $13.8 million in
prepayment breakage costs, $3.2 million in accrued but
unpaid interest and fees, and $16.7 million in other costs
associated with the amendment. The balance outstanding under
this facility was $800.0 million as of December 31,
2004. Other expenses include commitment fees on the undrawn
portion of the revolving credit facility, participation fees for
the credit-linked deposit and other fees.
As of December 31, 2004, the $350.0 million letter of
credit facility was fully funded and reflected as a funded
letter of credit on the December 31, 2004 balance sheet. As
of December 31, 2004, $157.1 million in letters of
credit had been issued under this facility, leaving
$192.9 million available for future issuances.
If we decide not to provide any additional funding or credit
support to our subsidiaries, the inability of any of our
subsidiaries that have near-term debt payment obligations to
obtain non-recourse project financing may result in such
subsidiarys insolvency and the loss of our investment in
such subsidiary. Additionally, the loss of a significant
customer at any of our subsidiaries could result in the need to
restructure the non-recourse project
84
financing at that subsidiary, and the inability to successfully
complete a restructuring of the non-recourse project financing
may result in a loss of our investment in such subsidiary.
Certain of our projects are subject to restrictions regarding
the movement of cash. For additional information see
Item 15 Note 18 to the Consolidated
Financial Statements.
For 2005, we anticipate utilizing $300 million of our
letter of credit facility. In addition, PMI may require
additional capital resources depending upon our hedging
activity, fuel purchases and future market conditions. As part
of our refinancing transactions, we have a $150.0 million
revolving credit facility. The revolving credit facility was
established to satisfy short-term working capital requirements,
which may arise from time to time. It is not our current
intention to draw funds under the revolving credit facility.
On February 4, 2005, utilizing net proceeds of
$406.4 million from the sale of preferred securities in
December 2004, we redeemed $375.0 million in Second
Priority Notes. At the same time, we paid $30.0 million for
the early redemption premium on the redeemed notes,
$4.1 million in accrued but unpaid interest on the redeemed
notes and $0.4 million in accrued but unpaid liquidated
damages on the redeemed notes.
On March 15, 2005, we made a $3.9 million dividend
payment to our preferred shareholders of record as of
March 1, 2005. This represents the first quarterly dividend
payment we anticipate making to our preferred shareholders.
We expect our capital requirements to be met with existing cash
balances, cash flows from operations, borrowings under our
Second Priority Notes and Amended Credit Facility, and asset
sales. We believe that our current level of cash availability
and asset sales, along with our future anticipated cash flows
from operations, will be sufficient to meet the existing
operational and collateral needs of our business for the next
12 months. Subject to restrictions in our Second Priority
Notes and our Amended Credit Facility, if cash generated from
operations is insufficient to satisfy our liquidity
requirements, we may seek to sell assets, obtain additional
credit facilities or other financings and/or issue additional
equity or convertible instruments. We cannot assure you,
however, that our business will generate sufficient cash flow
from operations, such that currently anticipated cost savings
and operating improvements will be realized on schedule or that
future borrowings will be available to us under our credit
facilities in an amount sufficient to enable us to pay our
indebtedness, or to fund our other liquidity needs. We may need
to refinance all or a portion of our indebtedness, on or before
maturity. We cannot assure you that we will be able to refinance
any of our indebtedness, on commercially reasonable terms or at
all. To service our indebtedness, we will require a significant
amount of cash. Our ability to generate cash depends on many
factors beyond our control.
|
|
|
Net Operating Loss Carryforwards |
For the year ended December 31, 2004, we generated a net
operating loss carryforward of $102.1 million which will
expire through 2024. We believe that it is more likely than not
that no benefit will be realized on the deferred tax assets
relating to the net operating loss carryforwards. This
assessment included consideration of positive and negative
factors, including our current financial position and results of
operations, projected future taxable income, including projected
operating and capital gains, and available tax planning
strategies. Therefore, as of December 31, 2004, a valuation
allowance of $707.9 million was recorded against the net
deferred tax assets, including net operating loss carryforwards
in accordance with SFAS No. 109.
Off-Balance Sheet Items
As of December 31, 2004, we have not entered into any
financing structure that is designed to be off-balance sheet
that would create liquidity, financing or incremental market
risk or credit risk to us. However, we have numerous investments
with an ownership interest percentage of 50% or less in energy
and energy related entities that are accounted for under the
equity method of accounting as disclosed in
Item 15
85
Note 13 to the Consolidated Financial Statements. Our
pro-rata share of non-recourse debt held by unconsolidated
affiliates was approximately $251.7 million as of
December 31, 2004. The decline was largely a result of
sales of our interest in Calpine Cogeneration, Loy Yang and
Commonwealth Atlantic. In the normal course of business we may
be asked to loan funds to the unconsolidated affiliates on both
a long and short-term basis. Such transactions are generally
accounted for as accounts payable and receivable to/from
affiliates and notes payable/receivable to/from affiliates and
if appropriate, bear market-based interest rates. See
Item 15 Note 11 to the Consolidated
Financial Statements for additional information regarding
amounts accounted for as notes receivable affiliates.
Contractual Obligations and Commercial Commitments
We have a variety of contractual obligations and other
commercial commitments that represent prospective cash
requirements in addition to our capital expenditure programs.
The following is a summarized table of contractual obligations.
See additional discussion in Item 15
Notes 18, 27 and 29 to the Consolidated Financial
Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period as of December 31, 2004 |
|
|
|
|
|
|
|
After |
Contractual Cash Obligations |
|
Total |
|
Short-term |
|
2-3 Years |
|
4-5 Years |
|
5 Years |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Long-term debt
|
|
$ |
4,783,626 |
|
|
$ |
614,573 |
|
|
$ |
461,833 |
|
|
$ |
460,372 |
|
|
$ |
3,246,848 |
|
Capital lease obligations (including estimated interest)
|
|
|
1,263,658 |
|
|
|
115,558 |
|
|
|
177,436 |
|
|
|
136,940 |
|
|
|
833,724 |
|
Operating leases
|
|
|
140,324 |
|
|
|
16,176 |
|
|
|
32,383 |
|
|
|
28,822 |
|
|
|
62,943 |
|
Coal purchase and transportation obligations
|
|
|
351,182 |
|
|
|
118,679 |
|
|
|
135,176 |
|
|
|
75,628 |
|
|
|
21,699 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$ |
6,538,790 |
|
|
$ |
864,986 |
|
|
$ |
806,828 |
|
|
$ |
701,762 |
|
|
$ |
4,165,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Commitment Expiration per Period as of December 31, |
|
|
2004 |
|
|
|
|
|
Total |
|
|
|
|
Amounts |
|
|
|
After |
Other Commercial Commitments |
|
Committed |
|
Short-term |
|
2-3 Years |
|
4-5 Years |
|
5 Years |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Funded standby letters of credit
|
|
$ |
157,144 |
|
|
$ |
157,144 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
Unfunded standby letters of credit
|
|
|
16,103 |
|
|
|
16,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Surety bonds
|
|
|
4,467 |
|
|
|
4,467 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset sales guarantee obligations
|
|
|
73,515 |
|
|
|
1,000 |
|
|
|
250 |
|
|
|
12,500 |
|
|
|
59,765 |
|
Commodity sales guarantee obligations
|
|
|
57,600 |
|
|
|
24,100 |
|
|
|
|
|
|
|
|
|
|
|
33,500 |
|
Other guarantees
|
|
|
94,126 |
|
|
|
|
|
|
|
778 |
|
|
|
|
|
|
|
93,348 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total commercial commitments
|
|
$ |
402,955 |
|
|
$ |
202,814 |
|
|
$ |
1,028 |
|
|
$ |
12,500 |
|
|
$ |
186,613 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In December 2004, we entered into a long-term coal transport
agreement with the Burlington Northern and Santa Fe Railway
Company and affiliates of American Commercial Lines LLC to
deliver low sulfur coal to our Big Cajun II facility in New
Roads, Louisiana beginning April 1, 2005. In December 2004,
we also entered into coal purchase contracts extending through
2007. In March 2005, we entered into an agreement to purchase
23.75 million tons of coal over a period of four years and
nine months from Buckskin Mining Company or Buckskin. The coal
will be sourced from Buckskins mine in the Powder River
Basin, Wyoming, and will be used primarily in
NRG Energys coal-burning generation plants in the
South Central region.
In August 2004, we entered into a contract to
purchase 1,540 aluminum railcars from Johnston America
Corporation to be used for the transportation of low sulfur coal
from Wyoming to NRG Energys coal burning generating
plants, including the Cajun Facilities. On February 18,
2005, we entered into a ten-year operating lease agreement with
GE Railcar Services Corporation, or GE, for the lease of 1,500
railcars and delivery
86
commenced in February 2005. We have assigned certain of our
rights and obligations for 1,500 railcars under the purchase
agreement with Johnston America to GE. Accordingly, the railcars
which we lease from GE under the arrangement described above
will be purchased by GE from Johnston America in lieu of our
purchase of those railcars.
Interdependent Relationships
We do not have any significant interdependent relationships.
Derivative Instruments
We may enter into long-term power sales contracts, long-term gas
purchase contracts and other energy related commodities
financial instruments to mitigate variability in earnings due to
fluctuations in spot market prices, hedge fuel requirements at
generation facilities and protect fuel inventories. In addition,
in order to mitigate interest rate risk associated with the
issuance of our variable rate and fixed rate debt, we enter into
interest rate swap agreements.
The tables below disclose the trading activities that include
non-exchange traded contracts accounted for at fair value.
Specifically, these tables disaggregate realized and unrealized
changes in fair value; identify changes in fair value
attributable to changes in valuation techniques; disaggregate
estimated fair values at December 31, 2004 based on whether
fair values are determined by quoted market prices or more
subjective means; and indicate the maturities of contracts at
December 31, 2004.
|
|
|
Derivative Activity Gains/(Losses) |
|
|
|
|
|
|
|
Reorganized |
|
|
NRG |
|
|
|
|
|
(In thousands) |
Fair value of contracts at December 31, 2003
|
|
$ |
(93,253 |
) |
Contracts realized or otherwise settled during the period
|
|
|
17,298 |
|
Changes in fair value
|
|
|
32,284 |
|
|
|
|
|
|
Fair value of contracts at December 31, 2004
|
|
$ |
(43,671 |
) |
|
|
|
|
|
|
|
|
Sources of Fair Value Gains/(Losses) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG |
|
|
Fair Value of Contracts at Period End as of December 31, 2004 |
|
|
|
|
|
Maturity |
|
|
|
Maturity |
|
|
|
|
Less than |
|
Maturity |
|
Maturity |
|
in excess |
|
Total Fair |
|
|
1 Year |
|
1-3 Years |
|
4-5 Years |
|
of 5 Years |
|
Value |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
Prices actively quoted
|
|
$ |
47,131 |
|
|
$ |
1,296 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
48,427 |
|
Prices based on models and other valuation methods
|
|
|
1,371 |
|
|
|
(19,451 |
) |
|
|
(16,354 |
) |
|
|
(37,913 |
) |
|
|
(72,347 |
) |
Prices provided by other external sources
|
|
|
13,245 |
|
|
|
(1,643 |
) |
|
|
(6,500 |
) |
|
|
(24,853 |
) |
|
|
(19,751 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
61,747 |
|
|
$ |
(19,798 |
) |
|
$ |
(22,854 |
) |
|
$ |
(62,766 |
) |
|
$ |
(43,671 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
We may use a variety of financial instruments to manage our
exposure to fluctuations in foreign currency exchange rates on
our international project cash flows, interest rates on our cost
of borrowing and energy and energy related commodities prices.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and
results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with
accounting principles
87
generally accepted in the United States. The preparation of
these financial statements and related disclosures in compliance
with generally accepted accounting principles, or GAAP, requires
the application of appropriate technical accounting rules and
guidance as well as the use of estimates and judgments that
affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosures of contingent assets and
liabilities. The application of these policies necessarily
involves judgments regarding future events, including the
likelihood of success of particular projects, legal and
regulatory challenges. These judgments, in and of themselves,
could materially impact the financial statements and disclosures
based on varying assumptions, which may be appropriate to use.
In addition, the financial and operating environment also may
have a significant effect, not only on the operation of the
business, but on the results reported through the application of
accounting measures used in preparing the financial statements
and related disclosures, even if the nature of the accounting
policies have not changed.
On an ongoing basis, we evaluate our estimates, utilizing
historic experience, consultation with experts and other methods
we consider reasonable. In any case, actual results may differ
significantly from our estimates. Any effects on our business,
financial position or results of operations resulting from
revisions to these estimates are recorded in the period in which
the facts that give rise to the revision become known.
Our significant accounting policies are summarized in
Item 15 Note 2 to the Consolidated
Financial Statements. The following table identifies certain of
the significant accounting policies listed in
Item 15 Note 2 to the Consolidated
Financial Statements. The table also identifies the judgments
required, uncertainties involved in the application of each and
estimates that may have a material impact on our results of
operations and statement of financial position. These policies,
along with the underlying assumptions and judgments made by our
management in their application, have a significant impact on
our consolidated financial statements. We identify our most
critical accounting policies as those that are the most
pervasive and important to the portrayal of our financial
position and results of operations, and that require the most
difficult, subjective and/or complex judgments by management
regarding estimates about matters that are inherently uncertain.
|
|
|
Accounting Policy |
|
Judgments/Uncertainties Affecting Application |
|
|
|
Fresh Start Reporting
|
|
The determination of the enterprise value and the
allocation to the underlying assets and liabilities are based on
a number of estimates and assumptions, which are inherently
subject to significant uncertainties and contingencies |
|
|
Determination at Fresh Start date |
|
|
Consolidation of entities remaining in bankruptcy |
|
|
Valuation of emission credit allowances and power
sales contracts |
|
|
Valuation of debt instruments |
|
|
Valuation of equity investments |
Capitalization Practices
|
|
Determination of beginning and ending of
capitalization periods |
|
|
Allocation of purchase prices to identified assets |
Asset Valuation and Impairment
|
|
Recoverability of investment through future
operations |
|
|
Regulatory and political environments and
requirements |
|
|
Estimated useful lives of assets |
|
|
Environmental obligations and operational limitations |
|
|
Estimates of future cash flows |
|
|
Estimates of fair value (fresh start) |
|
|
Judgment about triggering events |
Revenue Recognition
|
|
Customer/counter-party dispute resolution practices |
88
|
|
|
Accounting Policy |
|
Judgments/Uncertainties Affecting Application |
|
|
|
|
|
Market maturity and economic conditions |
|
|
Contract interpretation |
Uncollectible Receivables
|
|
Economic conditions affecting customers,
counter-parties, suppliers and market prices |
|
|
Regulatory environment and impact on customer
financial condition |
|
|
Outcome of litigation and bankruptcy proceedings |
Derivative Financial Instruments
|
|
Market conditions in the energy industry, especially
the effects of price volatility on contractual commitments |
|
|
Assumptions used in valuation models |
|
|
Documentation requirements |
|
|
Counter-party credit risk |
|
|
Market conditions in foreign countries |
|
|
Regulatory and political environments and
requirements |
Litigation Claims and Assessments
|
|
Impacts of court decisions |
|
|
Estimates of ultimate liabilities arising from legal
claims |
Income Taxes and Valuation Allowance for Deferred Tax Assets
|
|
Ability of tax authority decisions to withstand
legal challenges or appeals |
|
|
Anticipated future decisions of tax authorities |
|
|
Application of tax statutes and regulations to
transactions. |
|
|
Ability to utilize tax benefits through carrybacks
to prior periods and carryforwards to future periods. |
Discontinued Operations
|
|
Consistent application |
|
|
Determination of fair value (recoverability) |
|
|
Recognition of expected gain or loss prior to
disposition |
Pension
|
|
Accuracy of management assumptions |
|
|
Accuracy of actuarial consultant assumptions |
Stock-Based Compensation
|
|
Accuracy of management assumptions used to determine
the fair value of the stock options |
Of all of the accounting policies identified in the above table,
we believe that the following policies and the application
thereof to be those having the most direct impact on our
financial position and results of operations.
Fresh Start Reporting
In connection with the emergence from bankruptcy, we adopted
Fresh Start in accordance with the requirements of
SOP 90-7. The application of SOP 90-7 resulted in the
creation of a new reporting entity. Under Fresh Start, the
reorganization value of our company was allocated among our
assets and liabilities on a basis substantially consistent with
purchase accounting in accordance with SFAS No. 141,
Business Combinations.
The bankruptcy court in its confirmation order approved our plan
of reorganization on November 24, 2003. Under the
requirements of SOP 90-7, the Fresh Start date is
determined to be the confirmation date unless significant
uncertainties exist regarding the effectiveness of the
bankruptcy order. Our plan of
89
reorganization required completion of the Xcel Energy settlement
agreement prior to emergence from bankruptcy. We believe this
settlement agreement was a significant contingency and thus
delayed the Fresh Start date until the Xcel Energy settlement
agreement was finalized on December 5, 2003.
Under the requirements of Fresh Start, we adjusted our assets
and liabilities, other than deferred income taxes, to their
estimated fair values as of December 5, 2003. As a result
of marking our assets and liabilities to their estimated fair
values, we determined that there was no excess reorganization
value to recognize as an intangible asset. Deferred taxes were
determined in accordance with SFAS No. 109,
Accounting for Income Taxes. The net effect
of all Fresh Start adjustments resulted in a gain of
$3.9 billion (comprised of a $4.1 billion gain from
continuing operations and a $0.2 billion loss from
discontinued operations), which is reflected in the Predecessor
Companys results for the period January 1, 2003
through December 5, 2003. The application of the Fresh
Start provisions of SOP 90-7 created a new reporting entity
having no retained earnings or accumulated deficit.
As part of the bankruptcy process we engaged an independent
financial advisor to assist in the determination of the fair
value of our reorganized enterprise value. The fair value
calculation was based on managements forecast of expected
cash flows from our core assets. Managements forecast
incorporated forward commodity market prices obtained from a
third party consulting firm. A discounted cash flow calculation
was used to develop the enterprise value of Reorganized NRG,
determined in part by calculating the weighted average cost of
capital of the Reorganized NRG. The Discounted Cash Flow, or
DCF, valuation methodology equates the value of an asset or
business to the present value of expected future economic
benefits to be generated by that asset or business. The DCF
methodology is a forward looking approach that
discounts all expected future economic benefits by a theoretical
or observed discount rate. The independent financial advisor
prepared a 30-year cash flow forecast using a discount rate of
approximately 11%. The resulting reorganization enterprise value
ranged from $5.5 billion to $5.7 billion. The
independent financial advisor then subtracted our project-level
debt and made several other adjustments to reflect the values of
assets held for sale, excess cash and collateral requirements to
estimate a range of Reorganized NRG equity value of between
$2.2 billion and $2.6 billion.
In constructing our Fresh Start balance sheet upon our emergence
from bankruptcy, we used a reorganization equity value of
approximately $2.4 billion, as we believe this value to be
the best indication of the value of the ownership distributed to
the new equity owners. Our reorganization value of approximately
$9.1 billion was determined by adding our reorganized
equity value of $2.4 billion, $3.7 billion of interest
bearing debt and our other liabilities of $3.0 billion. The
reorganization value represents the fair value of an entity
before liabilities and approximates the amount a willing buyer
would pay for the assets of the entity immediately after
restructuring. This value is consistent with the voting
creditors and Courts approval of the Plan of
Reorganization.
A separate plan of reorganization was filed for our Northeast
Generating and South Central Generating entities that was
confirmed by the bankruptcy court on November 25, 2003, and
became effective on December 23, 2003, when the final
conditions of the plan were completed. In connection with Fresh
Start on December 5, 2003, we have accounted for these
entities as if they had emerged from bankruptcy at the same time
that we emerged, as we believe that we continued to maintain
control over the Northeast Generating and South Central
Generating facilities throughout the bankruptcy process.
Due to the adoption of Fresh Start upon our emergence from
bankruptcy, the Reorganized NRGs post-fresh start balance
sheet, statement of operations and statement of cash flows have
not been prepared on a consistent basis with the Predecessor
Companys financial statements and are therefore not
comparable in certain respects to the financial statements prior
to the application of Fresh Start.
In connection with the emergence from bankruptcy, we adopted
Fresh Start in accordance with the requirements of
SOP 90-7. The application of SOP 90-7 resulted in the
creation of a new reporting entity.
90
Under Fresh Start, the reorganization value of our company was
allocated to our assets and liabilities on a basis substantially
consistent with purchase accounting in accordance with
SFAS No. 141. We engaged a valuation specialist to
help us determine the fair value of our fixed assets. The
valuations were based on forecast power prices and operating
costs determined by us. The valuation specialist also determined
the estimated remaining useful lives of our fixed assets.
For those assets that were being constructed by us, the carrying
value reflects the application of our property, plant and
equipment policies which incorporate estimates, assumptions and
judgments by management relative to the capitalized costs and
useful lives of our generating facilities. 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 asset under construction is
ready for our intended use or when construction is terminated.
An insignificant amount of interest was capitalized during 2003.
Development costs and capitalized project costs include third
party professional services, permits and other costs that are
incurred incidental to a particular project. Such costs are
expensed as incurred until an acquisition agreement or letter of
intent is signed, and our board of directors has approved the
project. Additional costs incurred after this point are
capitalized.
|
|
|
Impairment of Long Lived Assets |
We evaluate property, plant and equipment and intangible assets
for impairment whenever indicators of impairment exist.
Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of the assets to the future
net cash flows expected to be generated by the asset, through
considering project specific assumptions for long-term power
pool prices, escalated future project operating costs and
expected plant operations. If such assets are considered to be
impaired, the impairment to be recognized is measured by the
amount by which the carrying amount of the assets exceeds the
fair value of the assets by factoring in the probability
weighting of different courses of action available to us.
Generally, fair value will be determined using valuation
techniques such as the present value of expected future cash
flows. Assets to be disposed of are reported at the lower of the
carrying amount or fair value less the cost to sell. For the
year ended December 31, 2004, the periods December 6,
2003 through December 31, 2003 and January 1, 2003
through December 5, 2003 and for the year ended
December 31, 2002, net income from continuing operations
was reduced by $44.7 million, $0 million,
$228.9 million and $2.5 billion, respectively, due to
asset impairments. Asset impairment evaluations are by nature
highly subjective.
|
|
|
Revenue Recognition and Uncollectible Receivables |
We are primarily an electric generation company, operating a
portfolio of majority-owned electric generating plants and
certain plants in which our ownership is 50% or less which are
accounted for under the equity method of accounting. We also
produce thermal energy for sale to customers. Both physical and
financial transactions are entered into to optimize the
financial performance of our generating facilities. Electric
energy revenue is recognized upon transmission to the customer.
In regions where bilateral markets exist and physical delivery
of electricity is common from our plants, we record revenue on a
gross basis. In certain markets, which are operated/controlled
by an independent system operator and in which we have entered
into a netting agreement with the ISO, which results in our
receiving a netted invoice, we have recorded purchased energy as
an offset against revenues received upon the sale of such
energy. Revenues derived from the buying and selling of
electricity not sourced from our facilities are reported net.
Capacity and ancillary revenue is recognized when contractually
earned. Revenues from operations and maintenance services are
recognized when the services are performed. We continually
assess the collectibility of our receivables, and in the event
we believe a receivable to be uncollectible, an allowance for
doubtful accounts is recorded or, in the event of a contractual
dispute, the receivable and corresponding revenue may be
considered unlikely of recovery and not recorded in the
financial statements until management is satisfied that it will
be collected.
91
|
|
|
Derivative Financial Instruments |
In January 2001, we adopted FAS No. 133,
Accounting for Derivative Instruments and Hedging
Activities, or SFAS No. 133, as amended by
SFAS No. 137, SFAS No. 138 and
SFAS No. 149. SFAS No. 133, as amended,
requires us to record all derivatives on the balance sheet at
fair value. In some cases hedge accounting may apply. The
criteria used to determine if hedge accounting treatment is
appropriate are a) the designation of the hedge to an
underlying exposure, b) whether or not the overall risk is
being reduced and c) if there is correlation between the
value of the derivative instrument and the underlying
obligation. Formal documentation of the hedging relationship,
the nature of the underlying risk, the risk management
objective, and the means by which effectiveness will be assessed
is created at the inception of the hedge. Changes in the fair
value of non-hedge derivatives are immediately recognized in
earnings. Changes in the fair value of derivatives accounted for
as hedges are either recognized in earnings as an offset to the
changes in the fair value of the related hedged assets,
liabilities and firm commitments or for forecasted transactions,
deferred and recorded as a component of accumulated other
comprehensive income, or OCI, until the hedged transactions
occur and are recognized in earnings. We primarily account for
derivatives under SFAS No. 133, as amended, such as
long-term power sales contracts, long-term gas purchase
contracts and other energy related commodities and financial
instruments used to mitigate variability in earnings due to
fluctuations in spot market prices, hedge fuel requirements at
generation facilities and to protect investments in fuel
inventories. SFAS No. 133, as amended, also applies to
interest rate swaps and foreign currency exchange rate
contracts. The application of SFAS No. 133, as
amended, results in increased volatility in earnings due to the
recognition of unrealized gains and losses. In determining the
fair value of these derivative/financial instruments we use
estimates, various assumptions, judgment of management and when
considered appropriate third party experts in determining the
fair value of these derivatives.
We classify our results of operations that either have been
disposed of or are classified as held for sale as discontinued
operations if both of the following conditions are met:
(a) the operations and cash flows have been (or will be)
eliminated from our ongoing operations as a result of the
disposal transaction and (b) we will not have any
significant continuing involvement in the operations of the
component after the disposal transaction. Prior periods are
restated to report the operations as discontinued.
The determination of our obligation and expenses for pension
benefits is dependent on the selection of certain assumptions.
These assumptions determined by management include the discount
rate, the expected rate of return on plan assets and the rate of
future compensation increases. Our actuarial consultants use
assumptions for such items as retirement age. The assumptions
used may differ materially from actual results, which may result
in a significant impact to the amount of pension obligation or
expense recorded by us.
Effective January 1, 2003, we adopted the fair value
recognition provisions of SFAS Statement No. 123,
Accounting for Stock-Based Compensation, or
SFAS No. 123. In accordance with SFAS Statement
No. 148, Accounting for Stock-Based
Compensation Transition and Disclosure, or
SFAS No. 148, we adopted SFAS No. 123 under
the prospective transition method which requires the application
of the recognition provisions to all employee awards granted,
modified, or settled after the beginning of the fiscal year in
which the recognition provisions are first applied. The
Black-Scholes option-pricing model is used for all non-qualified
stock options.
|
|
|
Recent Accounting Developments |
In November 2004, the Emerging Issue Task Force, or EITF, issued
EITF No. 03-13, Applying the Conditions in
Paragraph 42 of FASB Statement No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets, in
Determining Whether to Report Discontinued Operations.
EITF 03-13 clarifies the
92
definition of cash flows of a component in which the seller
engages in activities with the component after disposal, and
significant continuing involvement in the operations of the
component after the disposal transaction, and is effective for
fiscal periods beginning after December 15, 2004. The
adoption of this standard will not have a material effect on our
consolidated financial position and results of operations.
In November 2004, the FASB issued SFAS No. 151,
Inventory Costs an amendment of ARB
No. 43, Chapter 4. This statement amends the
guidance in ARB No. 43, Chapter 4, Inventory
Pricing, and requires that idle facility expense,
excessive spoilage, double freight, and rehandling costs be
recognized as current-period charges regardless of whether they
meet the criterion of so abnormal established by ARB
No. 43. SFAS No. 151 is effective for inventory
costs incurred during fiscal years beginning after June 15,
2005. The adoption of this statement will not have a material
effect on our consolidated financial position and results of
operations.
In December 2004, the FASB issued SFAS No. 123R,
Share-Based Payment, a revision to
SFAS No. 123, Accounting for Stock-Based
Compensation, which supersedes APB Opinion
No. 25, Accounting for Stock Issued to
Employees and its related implementation guidance.
SFAS 123R establishes standards for the accounting for
transactions in which an entity exchanges its equity instruments
for goods or services, including obtaining employee services in
share-based payment transactions. SFAS 123R applies to all
awards granted after the required effective date and to awards
modified, repurchased, or cancelled after that date. Adoption of
the provisions of SFAS 123R is effective as of the
beginning of the first interim or annual reporting period that
begins after June 15, 2005. We have previously adopted
SFAS No. 123, and we are currently in the process of
evaluating the potential impact that the adoption of
SFAS 123R will have on our consolidated financial position
and results of operations.
In December 2004, the FASB issued two FASB Staff Positions, or
FSPs, regarding the accounting implications of the American Jobs
Creation Act of 2004 related to (1) the deduction for
qualified domestic production activities (FSP FAS 109-1)
and (2) the one-time tax benefit for the repatriation of
foreign earnings (FSP FAS 109-2). In FSP FAS 109-1,
Application of FASB Statement No. 109,
Accounting for Income Taxes, to the Tax Deduction on
Qualified Production Activities Provided by the American Jobs
Creation Act of 2004, the Board decided that the
deduction for qualified domestic production activities should be
accounted for as a special deduction under FASB Statement
No. 109, Accounting for Income Taxes and
rejected an alternative view to treat it as a rate reduction.
Accordingly, any benefit from the deduction should be reported
in the period in which the deduction is claimed on the tax
return. FSP FAS 109-2, Accounting and Disclosure
Guidance for the Foreign Earnings Repatriation Provision within
the American Jobs Creation Act of 2004, addresses the
appropriate point at which a company should reflect in its
financial statements the effects of the one-time tax benefit on
the repatriation of foreign earnings. Because of the proximity
of the Acts enactment date to many companies
year-ends, its temporary nature, and the fact that numerous
provisions of the Act are sufficiently complex and ambiguous,
the Board decided that absent additional clarifying regulations,
companies may not be in a position to assess the impact of the
Act on their plans for repatriation or reinvestment of foreign
earnings. Therefore, the Board provided companies with a
practical exception to FAS 109s requirements by
providing them additional time to determine the amount of
earnings, if any, that they intend to repatriate under the
Acts beneficial provisions. The Board confirmed, however,
that upon deciding that some amount of earnings will be
repatriated, a company must record in that period the associated
tax liability, thereby making it clear that a company cannot
avoid recognizing a tax liability when it has decided that some
portion of its foreign earnings will be repatriated. We are
currently in the process of evaluating the potential impact that
the adoption of FSP FAS 109-1 and FSP FAS 109-2 will
have on our consolidated financial position and results of
operations.
|
|
Item 7A |
Quantitative and Qualitative Disclosures About Market
Risk |
We are exposed to several market risks in our normal business
activities. Market risk is the potential loss that may result
from market changes associated with our merchant
power generation or with an existing or forecasted financial or
commodity transaction. The types of market risks we are exposed
to are commodity price risk, interest rate risk and currency
exchange risk. In order to manage these risks we utilize various
fixed-
93
price forward purchase and sales contracts, futures and option
contracts traded on the New York Mercantile Exchange, and swaps
and options traded in the over-the-counter financial markets to:
|
|
|
|
|
Manage and hedge our fixed-price purchase and sales commitments; |
|
|
|
Manage and hedge our exposure to variable rate debt obligations, |
|
|
|
Reduce our exposure to the volatility of cash market
prices; and |
|
|
|
Hedge our fuel requirements for our generating facilities. |
Commodity Price Risk
Commodity price risks result from exposures to changes in spot
prices, forward prices, volatilities in commodities, and
correlations between various commodities, such as natural gas,
electricity, coal and oil. A number of factors influence the
level and volatility of prices for energy commodities and
related derivative products. These factors include:
|
|
|
|
|
Seasonal daily and hourly changes in demand, |
|
|
|
Extreme peak demands due to weather conditions, |
|
|
|
Available supply resources, |
|
|
|
Transportation availability and reliability within and between
regions, |
|
|
|
Changes in the nature and extent of federal and state
regulations. |
As part of our overall