10-K
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year ended
December 31, 2007.
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
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For the Transition period
from to .
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Commission file
No. 001-15891
NRG Energy, Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
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41-1724239
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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211 Carnegie Center
Princeton, New Jersey
(Address of principal
executive offices)
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08540
(Zip Code)
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(609)
524-4500
(Registrants telephone
number, including area code:)
Securities registered pursuant
to Section 12(b) of the Act:
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Title of Each Class
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Name of Exchange on Which Registered
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Common Stock, par value $0.01
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New York Stock Exchange
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5.75% Mandatory Convertible Preferred Stock
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New York Stock Exchange
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Securities registered pursuant to Section 12(g) of the
Act:
Common Stock, par value $0.01 per share
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
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
(§ 229.405 of this chapter) 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 a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in Ruler
12b-2 of the
Exchange Act. (Check one):
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
(Do not check if a smaller reporting company)
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Smaller reporting
company o
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
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
$9,869,468,545 based on the closing sale price of $41.57 as
reported on the New York Stock Exchange.
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.
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Class
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Outstanding at February 25, 2008
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Common Stock, par value $0.01 per share
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236,442,274
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Documents Incorporated by Reference:
Portions of the Proxy Statement for the 2008 Annual Meeting
of Stockholders to be held on May 14, 2008
Glossary
of Terms
When the following terms and abbreviations appear in the text of
this report, they have the meanings indicated below:
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Acquisition |
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February 2, 2006 acquisition of Texas Genco LLC, now
referred to as the Companys Texas region |
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AMA |
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Administrative Management Agreement between NRG Development
Company, Inc. and West Coast Power, LLC |
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APB |
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Accounting Principles Board |
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APB 18 |
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APB Opinion No. 18, The Equity Method of
Accounting for Investments in Common Stock |
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Average gross heat rate |
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The product of dividing (a) fuel consumed in BTUs by
(b) KWh generated |
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BART |
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Best Available Retrofit Technology |
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Baseload capacity |
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Electric power generation capacity normally expected to serve
loads on an around-the-clock basis throughout the calendar year |
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BTA |
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Best Technology Available |
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BTU |
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British Thermal Unit |
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CAA |
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Clean Air Act |
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CAIR |
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Clean Air Interstate Rule |
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CAISO |
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California Independent System Operator |
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CAMR |
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Clean Air Mercury Rule |
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Capacity factor |
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The ratio of the actual net electricity generated to the energy
that could have been generated at continuous full-power
operation during the year |
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Capital Allocation Program |
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Share repurchase program announced in August 2006 |
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CDWR |
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California Department of Water Resources |
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CERCLA |
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Comprehensive Environmental Response, Compensation and Liability
Act |
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CL&P |
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Connecticut Light & Power |
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CO2 |
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Carbon dioxide |
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COLA |
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Combined Construction and Operating License Application |
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CPUC |
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California Public Utilities Commission |
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DNREC |
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Delaware Department of Natural Resources and Environmental
Control |
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DPUC |
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Department of Public Utility Control |
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EAF |
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Measures the percentage of maximum generation available over
time as the fraction of net maximum generation that could be
provided over a defined period of time after all types of
outages and deratings, including seasonal deratings, are taken
into account |
2
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EFOR |
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Equivalent Forced Outage Rates considers the
equivalent impact that forced de-ratings have in addition to
full forced outages |
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EITF |
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Emerging Issues Task Force |
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EITF 02-3 |
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EITF Issue
No. 02-3,
Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy
Trading and Risk Management Activities |
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EPAct of 2005 |
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Energy Policy Act of 2005 |
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EPC |
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Engineering, Procurement and Construction |
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ERCOT |
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Electric Reliability Council of Texas, the Independent System
Operator and the regional reliability coordinator of the various
electricity systems within Texas |
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ERO |
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Energy Reliability Organization |
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EWG |
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Exempt Wholesale Generator |
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Expected annual baseload generation |
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The net baseload capacity limited by economic factors
(relationship between cost of generation and market price) and
reliability factors (scheduled and unplanned outages) |
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FASB |
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Financial Accounting Standards Board, the designated
organization for establishing standards for financial accounting
and reporting |
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FCM |
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Forward Capacity Market |
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FERC |
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Federal Energy Regulatory Commission |
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FIN |
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FASB Interpretation |
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FIN 45 |
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FIN No. 45 Guarantors Accounting and
Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others |
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FIP |
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Federal Implementation Plan |
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Fresh Start |
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Reporting requirements as defined by
SOP 90-7 |
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GHG |
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Greenhouse Gases |
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Hedge Reset |
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Net settlement of long-term power contracts and gas swaps by
negotiating prices to current market completed in November 2006 |
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ICT |
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Independent Coordinator of Transmission |
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IGCC |
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Integrated Gasification Combined Cycle |
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IRS |
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Internal Revenue Service |
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ISO |
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Independent System Operator, also referred to as Regional
Transmission Organizations, or RTO |
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ISO-NE |
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ISO New England, Inc. |
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ITISA |
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Itiquira Energetica S.A. |
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kW |
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Kilowatts |
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kWh |
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Kilowatt-hours |
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LFRM |
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Locational Forward Reserve Market |
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LIBOR |
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London Inter-Bank Offer Rate |
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LMP |
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Locational Marginal Prices |
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MADEP |
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Massachusetts Department of Environmental Protection |
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Merit Order |
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A term used for the ranking of power stations in order of
ascending marginal cost |
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MIBRAG |
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Mitteldeutsche Braunkohlengesellschaft mbH |
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Moodys |
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Moodys Investors Services, Inc., a credit rating agency |
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MMBtu |
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Million British Thermal Units |
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MRTU |
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Market Redesign and Technology Upgrade |
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MW |
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Megawatts |
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MWh |
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Saleable megawatt hours net of internal/parasitic load
megawatt-hours |
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NAAQS |
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National Ambient Air Quality Standards |
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Net baseload capacity |
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Nominal summer net megawatt capacity of power generation
adjusted for ownership and parasitic load, and excluding
capacity from mothballed units as of December 31, 2007 |
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Net Capacity Factor |
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Net actual generation divided by net maximum capacity for the
period hours |
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Net Generating Capacity |
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Nominal summer capacity, net of auxiliary power |
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New York Rest of State |
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New York State excluding New York City |
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NiMo |
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Niagara Mohawk Power Corporation |
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NOx |
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Nitrogen oxide |
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NOL |
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Net Operating Loss |
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NOV |
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Notice of Violation |
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NRC |
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United States Nuclear Regulatory Commission |
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NSR |
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New Source Review |
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NYPA |
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New York Power Authority |
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NYISO |
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New York Independent System Operator |
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NYSDEC |
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New York Department of Environmental Conservation |
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OCI |
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Other Comprehensive Income |
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OTC |
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Ozone Transport Commission |
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Phase II 316(b) Rule |
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A section of the Clean Water Act regulating cooling water intake
structures |
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PJM |
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PJM Interconnection, LLC |
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PJM Market |
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The wholesale and retail electric market operated by PJM
primarily in all or parts of Delaware, the District of Columbia,
Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and
West Virginia |
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PMI |
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NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which
procures transportation and fuel for the Companys
generation facilities, sells the power from these facilities,
and manages all commodity trading and hedging for NRG |
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Powder River Basin, or PRB, Coal |
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Coal produced in the northeastern Wyoming and southeastern
Montana, which has low sulfur content |
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PPA |
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Power Purchase Agreement |
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PSD |
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Prevention of Significant Deterioration |
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PUCT |
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Public Utility Commission of Texas |
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PUHCA |
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Public Utility Holding Company Act of 2005 |
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PURPA |
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Public Utility Regulatory Policy Act of 2005 |
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Repowering |
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Technologies utilized to replace, rebuild, or redevelop major
portions of an existing electrical generating facility, not only
to achieve a substantial emissions reduction, but also to
increase facility capacity, and improve system efficiency |
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RepoweringNRG |
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NRGs program designed to develop, finance, construct and
operate new, highly efficient, environmentally responsible
capacity over the next decade |
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RFP |
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Request for proposal |
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RGGI |
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Regional Greenhouse Gas Initiative |
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RMR |
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Reliability Must-Run |
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ROIC |
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Return on invested capital |
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RTO |
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Regional Transmission Organization, also referred to as an ISO |
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S&P |
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Standard & Poors, a credit rating agency |
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SARA |
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Superfund Amendments and Reauthorization Act of 1986 |
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Sarbanes-Oxley |
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Sarbanes Oxley Act of 2002 |
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Schkopau |
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Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which
NRG has a 41.9% interest |
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SCR |
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Selective Catalytic Reduction |
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SEC |
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United States Securities and Exchange Commission |
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SERC |
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Southeastern Electric Reliability Council/Entergy |
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SFAS |
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Statement of Financial Accounting Standards issued by the FASB |
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SFAS 71 |
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SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation |
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SFAS 87 |
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SFAS No. 87, Employers Accounting for
Pensions |
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SFAS 106 |
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SFAS No. 106, Employers Accounting for
Postretirement Benefits Other Than Pensions |
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SFAS 109 |
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SFAS No. 109, Accounting for Income
Taxes |
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SFAS 123 |
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SFAS No. 123, Accounting for Stock-Based
Compensation |
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SFAS 123R |
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SFAS No. 123 (revised 2004), Share-Based
Payment |
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SFAS 133 |
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SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities as amended |
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SFAS 142 |
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SFAS No. 142, Goodwill and Other Intangible
Assets |
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SFAS 143 |
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SFAS No. 143, Accounting for Asset Retirement
Obligations |
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SFAS 144 |
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SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets |
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SFAS 157 |
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SFAS No. 157, Fair Value Measurement |
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SFAS 158 |
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SFAS No. 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement
Plans an amendment of FASB Statements No. 87,
88, 106 and 132(R) |
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SO2 |
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Sulfur dioxide |
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SOP |
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Statement of Position issued by the American Institute of
Certified Public Accountants |
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SOP 90-7 |
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Statement of Position
90-7,
Financial Reporting by Entities in Reorganization Under
the Bankruptcy Code |
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STP |
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South Texas Project Nuclear generating facility
located near Bay City, Texas in which NRG owns a 44% interest |
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STPNOC |
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South Texas Project Nuclear Operating Company |
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TCEQ |
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Texas Commission on Environmental Quality |
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Texas Genco |
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Texas Genco LLC, now referred to as the Companys Texas
region |
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Tonnes |
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Metric tonnes, which are units of mass or weight in the metric
system each equal to 2,205 lbs and are the global measurement
for GHG |
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Uprate |
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A sustainable increase in the electrical rating of a generating
facility |
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US |
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United States of America |
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USEPA |
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United States Environmental Protection Agency |
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U.S. GAAP |
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Accounting principles generally accepted in the United States |
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VAR |
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Value at Risk |
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VOC |
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Volatile Organic Carbon |
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WCP |
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WCP (Generation) Holdings, Inc. |
6
PART I
General
NRG Energy, Inc., or NRG or the Company, is a wholesale power
generation company with a significant presence in major
competitive power markets in the United States. NRG is engaged
in the ownership, development, construction and operation of
power generation facilities, the transacting in and trading of
fuel and transportation services, and the trading of energy,
capacity and related products in the United States and select
international markets. As of December 31, 2007, NRG had a
total global portfolio of 191 active operating generation units
at 49 power generation plants, with an aggregate generation
capacity of approximately 24,115 MW, and approximately
740 MW under construction which includes partners
interests. Within the United States, NRG has one of the largest
and most diversified power generation portfolios in terms of
geography, fuel-type and dispatch levels, with approximately
22,880 MW of generation capacity in 175 active generating
units at 43 plants. These power generation facilities are
primarily located in Texas (approximately 10,805 MW), the
Northeast (approximately 6,980 MW), South Central
(approximately 2,850 MW), and West (approximately
2,130 MW) regions of the United States, with approximately
115 MW of additional generation capacity from the
Companys thermal assets. NRGs principal domestic
power plants consist of a mix of natural gas-, coal-, oil-fired
and nuclear facilities, representing approximately 46%, 33%, 16%
and 5% of the Companys total domestic generation capacity,
respectively. In addition, 15% of NRGs domestic generating
facilities have dual or multiple fuel capacity, which allows
plants to dispatch with the lowest cost fuel option. NRGs
domestic generation facilities consist of baseload, intermediate
and peaking power generation facilities, the ranking of which is
referred to as Merit Order, and include thermal energy
production plants. The sale of capacity and power from baseload
generation facilities accounts for the majority of the
Companys revenues and provides a stable source of cash
flow. In addition, NRGs generation portfolio provides the
Company with opportunities to capture additional revenues by
selling power during periods of peak demand, offering capacity
or similar products to retail electric providers and others, and
providing ancillary services to support system reliability.
NRGs
Major Initiatives
The Companys strategy is reflected in its five major
initiatives, four of which were announced and began
implementation in 2006. The fifth, Focus on ROIC
@NRG, or FORNRG, successfully concluded its third
year in 2007. NRGs five major initiatives, described
below, are designed to enhance the Companys competitive
advantages of the opportunities and surmount the challenges
faced by the power industry.
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I.
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FORNRG is a companywide effort, introduced in
2005, and is designed to increase the return on invested
capital, or ROIC, through operational performance improvements
to the Companys asset fleet, along with a range of
initiatives at plants and at corporate offices to reduce costs
or, in some cases, generate revenue. The FORNRG earnings
accomplishments disclosed in NRGs SEC filings and press
releases include both recurring and one time improvements
measured from a 2004 baseline, with the exception of the Texas
region where benefits are measured using 2005 as the base year.
For plant operations, the program measures cumulative current
year benefits using current gross margins times the change in
baseline levels of certain key performance indicators. The plant
performance benefits include both positive and negative results
for plant reliability, capacity, heat rate and station service.
FORNRG contributed $39 million to pre-tax earnings
in 2005 and $144 million were achieved through the end of
2006. For 2007, the Company attained its previously announced
target of $220 million which includes $11 million of
one-time benefits.
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lI.
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RepoweringNRG is a comprehensive portfolio
redevelopment program designed to develop, construct and operate
new multi-fuel, multi-technology, highly efficient and
environmentally responsible generation capacity over the next
decade. Through this initiative, the Company anticipates
retiring certain existing units and adding new generation to
meet growing demand in the Companys core markets, with an
emphasis on new baseload capacity that is expected to be
supported by long-term power purchase agreements, or PPAs, and
financed with limited or non-recourse project financing.
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llI.
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econrg represents NRGs commitment to
environmentally responsible power generation. econrg seeks to
find ways to meet the challenges of climate change, clean air
and water, and protecting our natural resources while taking
advantage of business opportunities. This initiative builds upon
its foundation in environmental compliance and embraces
environmental initiatives for the benefit of our communities,
employees and shareholders, such as encouraging investment in
new environmental technologies, pursuing activities that
preserve and protect the environment and encouraging changes in
the daily lives of our employees.
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IV.
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Future NRG is the Companys workforce planning and
development initiative and represents NRGs strong
commitment to planning for future staffing requirements to meet
the on-going needs of the Companys current operations in
addition to the Companys RepoweringNRG initiatives.
Future NRG encompasses analyzing the demographics, skill set and
size of the Companys workforce in addition to the
organizational structure with a focus on succession planning
requirements, training, development, staffing and recruiting
needs. Included under the Future NRG umbrella is NRG University,
which develops leadership, managerial, supervisory and technical
training programs and includes individual skill development
courses.
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V.
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NRG Global Giving - Respect for the community is one of
NRGs core values. NRGs Global Giving Program invests
the Companys resources to strengthen the communities where
NRG does business and seeks to make investments in four focus
areas: community and economic development, education,
environment and human welfare.
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Business
Strategy
NRGs strategy is to optimize the value of the
Companys generation assets while using its asset base as a
platform for growth and enhanced financial performance which can
be sustained and expanded upon in the years to come. NRG plans
to maintain and enhance the Companys position as a leading
wholesale power generation company in the United States in a
cost-effective and risk-mitigating manner in order to serve the
bulk power requirements of NRGs existing customer base and
other entities that offer load or otherwise consume wholesale
electricity products and services in bulk. NRGs strategy
includes the following principles:
Increase value from existing assets NRG
has a highly diversified portfolio of power generation assets in
terms of region, fuel-type and dispatch levels. Through the
FORNRG initiative, NRG will continue to focus on
extracting value from its portfolio by improving plant
performance, reducing costs and harnessing the Companys
advantages of scale in the procurement of fuels and other
commodities, parts and services, and in doing so improving the
Companys ROIC.
Reduce the volatility of the Companys cash flows
through asset-based commodity hedging
activities NRG will continue to execute
asset-based risk management, hedging, marketing and trading
strategies within well-defined risk and liquidity guidelines in
order to manage the value of the Companys physical and
contractual assets. The Companys marketing and hedging
philosophy is centered on generating stable returns from its
portfolio of baseload power generation assets while preserving
an ability to capitalize on strong spot market conditions and to
capture the extrinsic value of the Companys intermediate
and peaking facilities and portions of its baseload fleet. NRG
believes that it can successfully execute this strategy by
leveraging its (i) expertise in marketing power and
ancillary services, (ii) its knowledge of markets,
(iii) its balanced financial structure and (iv) its
diverse portfolio of power generation assets.
Pursue additional growth opportunities at existing
sites NRG is favorably positioned to pursue
growth opportunities through expansion of its existing
generating capacity and development of new generating capacity
at its existing facilities. NRG intends to invest in its
existing assets through plant improvements, repowerings,
brownfield development and site expansions to meet anticipated
requirements for additional capacity in NRGs core markets.
Through the RepoweringNRG initiative, NRG will continue
to develop, construct and operate new and enhanced power
generation facilities at its existing sites, with an emphasis on
new baseload capacity that is supported by long-term power sales
agreements and financed with limited or non-recourse project
financing. NRG expects that these efforts will provide one or
more of the following benefits: improved heat rates; lower
delivered costs; expanded electricity production capability; an
improved ability to dispatch economically across the regional
8
general portfolio; increased technological and fuel diversity;
and reduced environmental impacts, including facilities that
either have near zero greenhouse gas, or GHG, emissions or can
be equipped to capture and sequester GHG emissions.
Reduce carbon intensity of portfolio while taking advantage
of carbon-driven business opportunities NRG
continues to actively pursue investments in new generating
facilities and technologies that will be highly efficient and
will employ no and low carbon technologies to limit
CO2
emissions and other air emission. Through the
RepoweringNRG and econrg initiatives, NRG is focused on
the development of low or no GHG emitting energy generating
sources, such as nuclear, wind, clean coal and gas,
and the employment of post-combustion capture technologies,
which represent significant commercial opportunities.
Maintain financial strength and
flexibility NRG remains focused on cash
flow and maintaining appropriate levels of liquidity, debt and
equity in order to ensure continued access to capital for
investment, to enhance risk-adjusted returns and to provide
flexibility in executing NRGs business strategy. NRG will
continue to focus on maintaining operational and financial
controls designed to ensure that the Companys financial
position remains strong. At the same time, the Companys
ongoing capital allocation objective includes scheduled
repayment of debt based on the amount of cash flow by the
Company each year, as well as an annual return of capital to
shareholders, targeted at an average rate of 3% of market
capitalization, of approximately $250 million to
$300 million per year.
Pursue strategic acquisitions and
divestures NRG will continue to pursue
selective acquisitions, joint ventures and divestitures to
enhance its asset mix and competitive position in the
Companys core markets. NRG intends to concentrate on
opportunities that present attractive risk-adjusted returns. NRG
will also opportunistically pursue other strategic transactions,
including mergers, acquisitions or divestitures.
Competition
and Competitive Strengths
Competition Wholesale power generation
is a capital-intensive, commodity-driven business with numerous
industry participants. NRG competes on the basis of the location
of its plants and ownership of multiple plants in various
regions, which increases the stability and reliability of its
energy supply. Wholesale power generation is basically a local
business that is currently highly fragmented relative to other
commodity industries and diverse in terms of industry structure.
As such, there is a wide variation in terms of the capabilities,
resources, nature and identity of the companies NRG competes
with depending on the market.
Scale and diversity of assets NRG has
one of the largest and most diversified power generation
portfolios in the United States, with approximately
22,880 MW of generation capacity in 175 active generating
units at 43 plants as of December 31, 2007. The
Companys power generation assets are diversified by
fuel-type, dispatch level and region, which help mitigate the
risks associated with fuel price volatility and market demand
cycles. NRGs U.S. baseload facilities, which consist
of approximately 8,700 MW of generation capacity measured
as of December 31, 2007, provide the Company with a
significant source of stable cash flow, while its intermediate
and peaking facilities, with approximately 14,180 MW of
generation capacity as of December 31, 2007, provide NRG
with opportunities to capture the significant upside potential
that can arise from time to time during periods of high demand.
In addition, approximately 15% of the Companys domestic
generation facilities have dual or multiple fuel capability,
which allows most of these plants to dispatch with the lowest
cost fuel option.
9
The following chart demonstrates the diversification of
NRGs domestic power generation assets as of
December 31, 2007:
Reliability of future cash flows NRG has
sold forward or otherwise hedged a significant portion of its
expected baseload generation capacity through 2013. The Company
has the capacity and intent to enter into additional hedges in
later years when market conditions are favorable. In addition,
as of December 31, 2007, the Company had purchased forward
under fixed price contracts (with contractually-specified price
escalators) to provide fuel for approximately 59% of its
expected baseload coal generation output from 2008 to 2013. The
hedge percentage is reflective of the current agreement of the
Jewett mine in which NRG has the contractual ability to adjust
volumes in future years. These forward positions provide a
stable and reliable source of future cash flow for NRGs
investors, while preserving a portion of its generation
portfolio for opportunistic sales to take advantage of market
dynamics.
Favorable cost dynamics for baseload power
plants In 2007, approximately 87% of the
Companys domestic generation output was from plants fueled
by coal or nuclear fuel. In many of the competitive markets
where NRG operates, the price of power is typically set by the
marginal costs of natural gas-fired and oil-fired power plants
that currently have substantially higher variable costs than
solid fuel baseload power plants. As a result of NRGs
lower marginal cost for baseload coal and nuclear generation
assets, the Company expects the baseload assets in ERCOT to
generate power nearly 100% of the time they are available.
Locational advantages Many of NRGs
generation assets are located within densely populated areas
that are characterized by significant constraints on the
transmission of power from generators outside the particular
region. Consequently, these assets are able to benefit from the
higher prices that prevail for energy in these markets during
periods of transmission constraints. NRG has generation assets
located within New York City, southwestern Connecticut, Houston
and the Los Angeles and San Diego load basins; all areas
with constraints on the transmission of electricity. This gives
the Company the opportunity to capture additional revenues by
offering capacity to retail electric providers and others,
selling power at prevailing market prices during periods of peak
demand and providing ancillary services in support of system
reliability. These facilities also are often ideally situated
for repowering or the addition of new capacity, because their
location and existing infrastructure give them significant
advantages over newly developed sites in their regions.
10
Performance
Metrics
The following table contains a summary of NRGs operating
revenues by segment for the year ended December 31, 2007 as
discussed in Item 15 Note 17, Segment
Reporting, to the Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Energy
|
|
|
Capacity
|
|
|
Management
|
|
|
Contract
|
|
|
Thermal
|
|
|
Other
|
|
|
Operating
|
|
Region
|
|
Revenues
|
|
|
Revenues
|
|
|
Activities
|
|
|
Amortization
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
|
(In millions)
|
|
|
Texas
|
|
$
|
2,698
|
|
|
$
|
363
|
|
|
$
|
(33
|
)
|
|
$
|
219
|
|
|
$
|
|
|
|
$
|
40
|
|
|
$
|
3,287
|
|
Northeast
|
|
|
1,104
|
|
|
|
402
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
72
|
|
|
|
1,605
|
|
South Central
|
|
|
404
|
|
|
|
221
|
|
|
|
10
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
658
|
|
West
|
|
|
4
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
127
|
|
International
|
|
|
42
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
140
|
|
Thermal
|
|
|
13
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
125
|
|
|
|
16
|
|
|
|
159
|
|
Corporate/Eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,265
|
|
|
$
|
1,196
|
|
|
$
|
4
|
|
|
$
|
242
|
|
|
$
|
125
|
|
|
$
|
157
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In understanding NRGs business, the Company believes 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: Measures the percentage of maximum
generation available over time as the fraction of net maximum
generation that could be provided over a defined period of time
after all types of outages and deratings, including seasonal
deratings, are taken into account.
Gross heat rate: NRG calculates the
gross heat rate for the Companys fossil-fired power plants
by dividing the average amount of fuel in BTUs required to
generate one kWh of electricity by the generator output.
Net Capacity Factor: The net amount of
electricity that a generating unit produces over a period of
time divided by the net amount of electricity it could have
produced if it had run at full power over that time period. The
net amount of electricity produced is the total amount of
electricity generated minus the amount of electricity used
during generation.
The tables below present the North American power generation
performance metrics for the Companys power plants
discussed above for the years ended December 31, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
Equivalent
|
|
|
Average Net
|
|
|
|
|
|
|
Net Owned
|
|
|
Generation
|
|
|
Availability
|
|
|
Heat Rate
|
|
|
Net Capacity
|
|
Region
|
|
Capacity (MW)
|
|
|
(MWh)
|
|
|
Factor
|
|
|
Btu/kWh
|
|
|
Factor
|
|
|
|
(In thousands of MWh)
|
|
|
Texas
|
|
|
10,805
|
|
|
|
47,779
|
|
|
|
87.6
|
%
|
|
|
10,300
|
|
|
|
50.7
|
%
|
Northeast(a)
|
|
|
6,980
|
|
|
|
14,163
|
|
|
|
83.6
|
|
|
|
10,900
|
|
|
|
21.2
|
|
South Central
|
|
|
2,850
|
|
|
|
10,930
|
|
|
|
89.0
|
|
|
|
10,200
|
|
|
|
46.1
|
|
West
|
|
|
2,130
|
|
|
|
1,246
|
|
|
|
89.9
|
%
|
|
|
11,200
|
|
|
|
9.3
|
%
|
11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
Equivalent
|
|
|
Average Net
|
|
|
|
|
|
|
Net Owned
|
|
|
Generation
|
|
|
Availability
|
|
|
Heat Rate
|
|
|
Net Capacity
|
|
Region
|
|
Capacity (MW)
|
|
|
(MWh)
|
|
|
Factor
|
|
|
Btu/kWh
|
|
|
Factor
|
|
|
|
(In thousands of MWh)
|
|
|
Texas(b)
|
|
|
10,760
|
|
|
|
44,910
|
|
|
|
91.0
|
%
|
|
|
10,300
|
|
|
|
41.0
|
%
|
Northeast(a)
|
|
|
7,240
|
|
|
|
13,309
|
|
|
|
85.8
|
|
|
|
10,900
|
|
|
|
18.8
|
|
South Central
|
|
|
2,850
|
|
|
|
11,036
|
|
|
|
94.3
|
|
|
|
10,400
|
|
|
|
47.2
|
|
West(c)
|
|
|
1,965
|
|
|
|
1,901
|
|
|
|
89.1
|
%
|
|
|
11,400
|
|
|
|
15.1
|
%
|
|
|
|
(a)
|
|
Factor data and heat rate does not
include the Keystone and Conemaugh facilities.
|
|
(b)
|
|
For the period February 2,
2006 through December 31, 2006.
|
|
(c)
|
|
Includes fully consolidated results
of WCP for the period April 1, 2006
December 31, 2006.
|
Employees
As of December 31, 2007, NRG had 3,412 employees,
approximately 1,639 of whom were covered by U.S. bargaining
agreements. During 2007, the Company did not experience any
labor stoppages or labor disputes at any of its facilities.
Generation
Asset Overview
NRG has a significant power generation presence in major
competitive power markets of the United States as set forth in
the map below:
|
|
|
(1)
|
|
Includes 115 MW as part of
NRGs Thermal assets. For combined scale, approximately
3,450 MW is dual-fuel capable. Reflects only domestic
generation capacity as of December 31, 2007.
|
As of December 31, 2007, the Companys power
generation assets consisted of approximately 10,490 MW of
gas-fired; 7,525 MW of coal-fired; 3,690 MW of
oil-fired and 1,175 MW of nuclear generating capacity in
the United States. In addition, NRG also owns approximately
115 MW of thermal capacity domestically as well as
1,235 MW of power generation capacity overseas. The
Companys North American power generation portfolio by
12
dispatch level is comprised of approximately 38% baseload, 37%
intermediate and 25% of peaking units. NRG uses hedging
strategies which may include power and natural gas forward sales
contracts to manage the commodity price risk associated with the
Companys generation assets, and are primarily around the
Companys baseload generation assets. In addition, these
hedging strategies also provide for stable cash flow and
earnings predictability.
The following table summarizes NRGs North American
baseload capacity and the corresponding revenues and average
natural gas prices resulting from baseload hedge agreements
extending beyond December 31, 2007 and through 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average for
|
|
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2008-2013
|
|
|
|
(In millions unless otherwise stated)
|
|
|
Net Baseload Capacity (MW)
|
|
|
8,685
|
|
|
|
8,685
|
|
|
|
8,523
|
|
|
|
8,443
|
|
|
|
8,416
|
|
|
|
8,416
|
|
|
|
8,528
|
|
Forecasted Baseload Capacity (MW)
|
|
|
7,497
|
|
|
|
7,387
|
|
|
|
7,335
|
|
|
|
7,241
|
|
|
|
7,331
|
|
|
|
7,309
|
|
|
|
7,350
|
|
Total Baseload Sales
(MW)(a)
|
|
|
7,390
|
|
|
|
5,416
|
|
|
|
4,066
|
|
|
|
4,206
|
|
|
|
1,543
|
|
|
|
1,005
|
|
|
|
3,938
|
|
Percentage Baseload Capacity Sold
Forward(b)
|
|
|
99
|
%
|
|
|
73
|
%
|
|
|
55
|
%
|
|
|
58
|
%
|
|
|
21
|
%
|
|
|
14
|
%
|
|
|
54
|
%
|
Total Forward Hedged
Revenues(c)(d)
|
|
$
|
3,701
|
|
|
$
|
2,735
|
|
|
$
|
2,000
|
|
|
$
|
1,959
|
|
|
$
|
644
|
|
|
$
|
392
|
|
|
$
|
1,905
|
|
Weighted Average Hedged Price ($ per
MWh)(c)
|
|
$
|
57
|
|
|
$
|
58
|
|
|
$
|
56
|
|
|
$
|
53
|
|
|
$
|
47
|
|
|
$
|
45
|
|
|
$
|
53
|
|
Weighted Average Hedged Price ($ per MWh) excluding South
Central
region(d)
|
|
$
|
60
|
|
|
$
|
61
|
|
|
$
|
60
|
|
|
$
|
56
|
|
|
$
|
54
|
|
|
$
|
|
|
|
$
|
58
|
|
Average Equivalent Natural Gas Price ($ per
MMBtu)(e)
|
|
$
|
7.30
|
|
|
$
|
7.43
|
|
|
$
|
7.27
|
|
|
$
|
6.84
|
|
|
$
|
6.33
|
|
|
$
|
6.10
|
|
|
$
|
6.88
|
|
Average Equivalent Natural Gas Price ($ per MMBtu) excluding
South Central
region(e)
|
|
$
|
7.50
|
|
|
$
|
7.70
|
|
|
$
|
7.49
|
|
|
$
|
7.03
|
|
|
$
|
6.70
|
|
|
$
|
|
|
|
$
|
6.07
|
|
|
|
|
(a)
|
|
Includes amounts under fixed price
power sales contracts and amounts financially hedged under
natural gas contracts. The forward natural gas quantities are
reflected in equivalent MWh and are derived by first dividing
the quantity of MMBtu of natural gas hedged by the forward
market implied heat rate as of December 31, 2007 to arrive
at the equivalent MWh hedged which is then divided by
8,760 hours (total hours in a year) to arrive at MW hedged.
|
|
(b)
|
|
Percentage hedged is based on total
MW sold as power and natural gas converted using the method as
described in (a) above divided by the forecasted baseload
capacity.
|
|
(c)
|
|
Represents all North American
baseload sales including power contract prices in the Texas and
South Central regions which are comprised of a fixed demand
charge exclusive of a fixed energy charge, with the transaction
price related to these contracts being the sum of both charges.
|
|
(d)
|
|
The South Central regions
weighted average hedged prices ranges from $40/MWh
$45/MWh due to legacy cooperative load contracts entered into at
prices significantly below current market levels. These prices
include a fixed capacity charge and an estimated energy charge.
|
|
(e)
|
|
The weighted average hedged price
in natural gas equivalents is derived by first multiplying the
quantity of MWh of power hedged by the forward market implied
heat rate as of December 31, 2007 to arrive at the
equivalent MMBtu hedged which is then added with the financially
hedged gas quantity. This total quantity in MMBtu is then used
to divide the total revenues from all baseload sales to arrive
at the weighted average hedged price in natural gas equivalents.
|
The following is a discussion of NRGs generation assets by
segment for the year ended December 31, 2007.
Texas Region As of December 31,
2007, NRGs generation assets in the Texas region consisted
of approximately 5,325 MW of baseload generation assets and
approximately 5,480 MW of intermediate and peaking natural
gas-fired assets. NRG realizes a substantial portion of its
revenue and cash flow from the sale of power from the
Companys three baseload power plants located in the ERCOT
market that use solid fuel: W.A. Parish which uses coal,
Limestone which uses lignite and coal, and an undivided 44%
interest in two nuclear generating units at South Texas Project,
or STP, which uses nuclear fuel. Power plants are generally
dispatched in order of lowest operating cost and as of
December 31, 2007, approximately 72% of the net generation
capacity in the ERCOT market was natural gas-fired. In the
current natural gas price environment, NRGs three baseload
facilities have
13
significantly lower operating costs than gas plants. NRG expects
these three facilities to operate nearly 100% of the time when
available, subject to planned and forced outages.
Northeast Region As of
December 31, 2007, NRG generation assets in the Northeast
region of the United States consisted of approximately
6,980 MW generation capacity from the Companys power
plants within the control areas of the New York Independent
System Operator, or NYISO, the Independent System
Operator New England, or ISO-NE, and the PJM
Interconnection LLC, or PJM. Certain of these assets are located
in transmission constrained areas, including approximately
1,415 MW of in-city New York City generation capacity and
approximately 535 MW of southwest Connecticut generation
capacity. As of December 31, 2007, NRGs generation
assets in the Northeast region consisted of approximately
1,870 MW of baseload generation assets and approximately
5,110 MW of intermediate and peaking assets.
South Central Region As of
December 31, 2007, NRG generation assets in the South
Central region of the United States consisted of approximately
2,405 MW of generation capacity, making NRG the third
largest generator in the Southeastern Electric Reliability
Council/Entergy, or SERC-Entergy, region. The Companys
generation assets in the South Central region consists of its
primary asset, Big Cajun II, a coal-fired plant located near
Baton Rouge, Louisiana which has approximately 1,490 MW of
baseload generation assets and 1,360 MW of intermediate and
peaking assets. A significant portion of the regions
generation capacity has been sold to eleven cooperatives within
the region through 2025. In addition, the region also operates
445 MW of peaking generation in Rockford, Illinois under
the PJM region.
West Region As of December 31,
2007, NRG generation assets in the West region of the United
States consisted of approximately 2,130 MW. On
January 3, 2007, NRG completed the sale of the Red Bluff
and Chowchilla II power plants with a combined generation
capacity of approximately 95 MW to an entity controlled by
Wayzata Investment Partners LLC. On August 1, 2007, the
Company successfully completed and commissioned the repowering
of 260 MW of new gas-fired generating capacity at its Long
Beach Generating Station.
International Region As of
December 31, 2007, NRG had net ownership in approximately
1,235 MW of power generating capacity outside the United
States in Australia, Brazil, and Germany. In addition to
traditional power generation facilities, NRG also owns equity
interests in certain coal mines in Germany. On December 18,
2007, NRG entered into a sale and purchase agreement to sell its
100% interest in Tosli Acquisition B.V., which holds all of
NRGs interest in ITISA, to Brookfield Asset Management
Inc. for the purchase price of $288 million, plus the
assumption of approximately $60 million in debt. NRG
anticipates the completion of the sale transaction during the
first half 2008.
Thermal NRG owns thermal and chilled
water businesses that generate approximately 1,040 MW
thermal equivalents. In addition, NRGs thermal segment
owns certain power plants with approximately 116 MW of
power generating capacity located in Delaware and in
Pennsylvania.
Commercial
Operations Overview
NRG seeks to maximize profitability and manage cash flow
volatility through the marketing, trading and sale of energy,
capacity and ancillary services into spot, intermediate and
long-term markets and through the active management and trading
of emissions allowances, fuel supplies and
transportation-related services. The Companys principal
objectives are the realization of the full market value of its
asset base, including the capture of its extrinsic value, the
management and mitigation of commodity market risk and the
reduction of cash flow volatility over time.
NRG enters into power sales and hedging arrangements via a wide
range of products and contracts, including power purchase
agreements, fuel supply contracts, capacity auctions, natural
gas swap agreements and other financial instruments. The power
purchase agreements that NRG enters into require the Company to
deliver MWh of power to its counterparties. In addition, because
changes in power prices in the markets where NRG operates are
generally correlated to changes in natural gas prices, the
Company hedges a portion of its generation portfolio power using
natural gas swaps and other financial instruments.
14
Fuel
Supply and Transportation
NRGs fuel requirements consist primarily of nuclear fuel
and various forms of fossil fuel including oil, natural gas and
coal, including lignite. The prices of oil, natural gas and coal
are subject to macro- and micro-economic forces that can change
dramatically in both the short- and long-term. The Company
obtains its oil, natural gas and coal from multiple suppliers
and transportation sources. Although availability is generally
not an issue, localized shortages, transportation availability
and supplier financial stability issues can and do occur. Issues
related to the sources and availability of raw materials are
fairly uniform across the Companys business segments.
Coal The Company is largely hedged for
its domestic coal consumption over the next few years. Coal
hedging is dynamic, and is based on forecasted generation and
market volatility. As of December 31, 2007, NRG had
purchased forward contracts to provide fuel for approximately
59% of the Companys requirement from 2008 through 2013.
NRG arranges for the purchase, transportation and delivery of
coal for the Companys baseload coal plants via a variety
of coal purchase agreements, rail transportation agreements and
rail car lease arrangements. The Company purchased approximately
38 million tons of coal in 2007, and is one of the largest
coal purchasers in the United States.
The following table shows the percentage of the Companys
coal and lignite requirements from 2008 through 2013 that have
been purchased forward:
|
|
|
|
|
|
|
Percentage of
|
|
|
|
Companys
|
|
|
|
Requirement(1)
|
|
|
2008
|
|
|
99
|
%
|
2009
|
|
|
86
|
%
|
2010
|
|
|
58
|
%
|
2011
|
|
|
52
|
%
|
2012
|
|
|
45
|
%
|
2013
|
|
|
15
|
%
|
|
|
|
(1)
|
|
The hedge percentages reflect the
current plan for the Jewett mine. NRG has the contractual
ability to change volumes and may do so in the future.
|
As of December 31, 2007, NRG had approximately 7,600
privately leased or owned rail cars in the Companys
transportation fleet. NRG has entered into rail transportation
agreements with varying tenures that provide for substantially
all of the Companys rail transportation requirements
through the end of the decade.
Natural Gas NRG operates a fleet of
natural gas plants in the Texas, Northeast, South Central and
West regions which are primarily comprised of peaking assets
that run in times of high power demand. Due to the uncertainty
of their dispatch, the fuel needs are managed on a spot basis as
it is not prudent to forward purchase fixed price natural gas on
units that may not run. The Company contracts for natural gas
storage services as well as natural gas transportation services
to ensure delivery of natural gas when needed.
Nuclear Fuel STPs owners satisfy
STPs fuel supply requirements by (i) acquiring
uranium concentrates and contracting for conversion of the
uranium concentrates into uranium hexafluoride,
(ii) contracting for enrichment of uranium hexafluoride and
(iii) contracting for fabrication of nuclear fuel
assemblies. NRG is party to a number of long-term forward
purchase contracts with many of the worlds largest
suppliers covering STP requirements for uranium and conversion
services for the next five years, and with substantial portions
of STPs requirements procured through the end of the next
decade. NRG is party to long term contracts to procure
STPs requirements for enrichment services and fuel
fabrication for the life of the operating license.
Seasonality
and Price Volatility
Annual and quarterly operating results can be significantly
affected by weather and energy commodity price volatility.
Significant other events, such as the demand for natural gas,
interruptions in fuel supply infrastructure and relative levels
of hydroelectric capacity can increase seasonal fuel and power
price volatility. NRG derives a majority of its annual revenues
in the months of May through September, when demand for
electricity is at its
15
highest in the Companys core domestic markets. Further,
power price volatility is generally higher in the summer months,
traditionally NRGs most important season. The
Companys second most important season is the winter months
of December through March 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 the Companys business segments.
Operations
Overview
NRG provides support services to the Companys generation
facilities to ensure that high-level performance goals are
developed, best practices are shared and resources are
appropriately balanced and allocated to maximize results for the
Company. NRG sets performance goals for equivalent forced outage
rates, or EFOR, availability, procurement costs, operating
costs, safety and environmental compliance.
Support services include safety, security, and systems. These
services also include operations planning and the development
and dissemination of consistent policies and practices relating
to plant operations.
To support RepoweringNRG initiatives, the Company has
organized its project execution process into one centralized
group consisting of engineering, procurement and construction,
or EPC. This group combines regional engineering functions with
corporate project engineering, project management, procurement
and construction functions to provide a consistent and
standardized execution of the repowering initiative. This has
enabled NRG to leverage both the procurement of major equipment
as well as outside engineering resources through standardized
work processes and work packaging. This process has led to
identifying commonality in major equipment that can be procured
from Original Equipment Manufacturers, or OEMs, as well as
design processes. As a result, NRG expects to achieve cost
savings by minimizing the number of outside engineering and
construction resources, which provide detailed design and
construction services required to complete projects, in addition
to and by ensuring a consistent engineering and construction
approach across all projects.
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2008
through 2012 to meet NRGs environmental commitments will
be between $1.0 billion and $1.4 billion. These
capital expenditures, in general, are related to installation of
particulate,
SO2,
NOx,
and mercury controls to comply with Clean Air Interstate Rule,
or CAIR, the Clean Air Mercury Rule, or CAMR, and related state
requirements as well as installation of Best Technology
Available under the Phase II 316(b) rule. NRG continues to
explore cost effective alternatives that can achieve desired
results. The range reflects alternative strategies available
with respect to the Companys Indian River plant.
The following table summarizes the upper end of the estimated
range for major environmental capital expenditures for the
referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
3
|
|
|
$
|
223
|
|
|
$
|
133
|
|
|
$
|
359
|
|
2009
|
|
|
5
|
|
|
|
192
|
|
|
|
211
|
|
|
|
408
|
|
2010
|
|
|
24
|
|
|
|
178
|
|
|
|
117
|
|
|
|
319
|
|
2011
|
|
|
28
|
|
|
|
112
|
|
|
|
53
|
|
|
|
193
|
|
2012
|
|
|
11
|
|
|
|
66
|
|
|
|
15
|
|
|
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
71
|
|
|
$
|
771
|
|
|
$
|
529
|
|
|
$
|
1,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG plans to reduce the impact of a portion of the above
environmental capital expenditures. NRG has the ability to
monetize a portion of the Companys excess allowances over
the 2008 through 2012 timeframe and still hold sufficient
allowances to operate the fleet with proposed controls through
at least 2020. In addition, NRGs current contracts with
the Companys rural electrical customers in the South
Central region allow for recovery of a significant portion of
the capital costs, along with a capital return incurred by
complying with new laws, including interest over the asset life
of the required expenditures. Actual recoveries will depend,
among other things, on the duration of the contracts and the
treatment of these expenditures.
16
Carbon
Update
There is a growing consensus in the U.S. and globally that
GHG emissions are a major cause of global warming. At the
national level and at various regional and state levels,
policies are under development to regulate GHG emissions,
thereby effectively putting a cost on such emissions in order to
create financial incentive to reduce them. In addition, earlier
this year, the U.S. Supreme Court found that
CO2,
the most common GHG, could be regulated as a pollutant and that
the USEPA should regulate
CO2
emissions from mobile sources. Since power plants, particularly
coal-fired plants, are a significant source of GHG emissions
both in the United States and globally, it is almost certain
that GHG regulatory actions will encompass power plants as well
as other GHG emitting stationary sources. In 2007, in the course
of producing approximately 80 million MWh of electricity,
NRGs power plants emitted 68 million tonnes of
CO2,
of which 61 million tonnes were emitted in the United
States, 3 million tonnes in Australia and 4 million
tonnes in Germany.
Federal, state or regional regulation of GHG emissions could
have a material impact on the Companys financial
performance. The actual impact on the Companys financial
performance will depend on a number of factors, including the
overall level of GHG reductions required under any such
regulations, the price and availability of offsets, and the
extent to which NRG would be entitled to receive GHG emissions
allowances without having to purchase them in an auction or on
the open market. For example, the U.S. Senate is currently
considering climate change legislation sponsored by Senators
Lieberman and Warner. If legislation with the same level of
allocations to existing generation resources and emissions
reductions as those contained in the current version of the
Lieberman-Warner legislation were enacted, NRG expects that the
legislation will have a minimal impact on the Companys
financial performance through the next decade. Thereafter, under
such legislation, the impact on NRG would depend on the
Companys level of success in developing and deploying low
and no carbon technologies being pursued as part of our
RepoweringNRG and econrg initiatives. Additionally,
NRGs current contracts with its South Central
regions cooperative customers allows for the recovery of
emission-based costs.
State and regional initiatives such as the Regional Greenhouse
Gas Initiative, or RGGI, in the Northeast, and the Western
Climate Initiative, or WCI, are developing market-based programs
to counteract climate change. The RGGI states are in the process
of promulgating state regulations needed for implementation with
six of the ten states issuing drafts for comment. With state
legislation and regulation in place, the first regional auction
of RGGI allowances needed by power generators could be held as
early as the summer of 2008. WCI is in the formative stages of
the regional effort. California has enacted Assembly Bill
32 California Global Warming Solutions Act of 2006,
or AB32, which requires the California Air Resources Board to
develop a GHG reduction program to reduce emissions to 1990
levels by 2020, a reduction of approximately 25%. This reduction
program will be phased in beginning 2012 pursuant to regulations
to be adopted by 2011.
NRG does not expect that implementation of AB32 in California
will have a significant adverse financial impact on the Company
for a variety of reasons, including the fact that NRGs
California portfolio consists of natural gas-fired peaking
facilities and will likely be able to pass through any costs of
purchasing allowances in power prices. However, of the
approximately 61 million tonnes of
CO2
emitted by NRG in the United States in 2007, approximately
12 million tonnes were emitted from the Companys
generating units in Connecticut, Delaware, Maryland,
Massachusetts and New York that will likely be subject to RGGI
in 2009. The impact of RGGI on power prices (and thus on the
Companys financial performance), indirectly through
generators seeking to pass through the cost of their
CO2
emissions, cannot be predicted. However, NRG believes that due
to the absence of any significant allowance allocations under
RGGI, the direct financial impact on NRG is likely to be
negative as the Company will incur costs in the course of
securing the necessary allowances and offsets at auction and in
the market.
In this regard, the Company has a multifold strategy with
respect to climate change and related GHG regulation. First, the
Company is seeking to influence public policy as it emerges at
various levels of government in order to ensure that such
legislation is fair and effective in reducing GHG emissions. To
ensure such effectiveness, NRG believes it is particularly
important that legislation be supportive of the research,
development, demonstration and deployment of low and no carbon
power generation technologies. The Company is carrying out its
efforts to influence public policy on its own and as part of two
collective efforts. In July 2007, NRG joined the United States
Climate Action Partnership, or USCAP, an alliance of major
businesses and leading climate and environmental
17
groups which are calling for federal legislation requiring
significant reductions of GHG emissions. Also in January 2007,
the Company joined with 46 other global business leaders to
support a new initiative, Combating Climate Change, or 3C. This
initiative calls for the global business community to take a
leadership role in designing the road map to a low carbon
society.
Second, the Company is actively pursuing investments in new
generating facilities and technologies that will be highly
efficient and will employ no and low carbon technologies to
limit
CO2
emissions and other air emissions through its
RepoweringNRG program. The Company anticipates that these
investments will result in long-term GHG intensity reductions in
its generating portfolio. The most notable of these projects in
terms of the potential impact on the GHG intensity of the
Companys portfolio is the 2,700 MW (gross) STP units
3 and 4 nuclear project in Texas. In addition to the nuclear
development project, the Company has other low and no GHG
emitting wind, clean coal and gas projects under
active development. The extent to which these projects, and our
remaining coal projects under development, impact our overall
carbon exposure will depend on our ability to complete
development of these projects, the nature and geographic reach
of any GHG regulation which goes into effect and the extent to
which the carbon risk associated with our development projects
are allocated between the Company and any offtakers under power
purchase agreements or similar arrangements.
Third, the Company is seeking to demonstrate through its econrg
program the large scale viability of post-combustion carbon
capture technologies. For example, NRG is working with Powerspan
Corp, or Powerspan, to deploy a scaled up demonstration of their
ammonium-based
ECO2tm
carbon capture technology at the Companys W.A. Parish
facility in Texas. The captured
CO2
would be either sequestered or used in enhanced oil recovery
operations. The Company believes that there may be significant
commercial opportunity in participating in such a project.
Fourth, the Company is preparing for the commercial operations
activities which will be required as part of any climate change
regulatory scheme that is implemented. In May 2007, the Company
joined the Chicago Climate Exchange, a GHG emissions reduction,
registry and trading system, as part of the Companys
ongoing program to increase its climate change awareness, track
its
CO2
emissions and address climate change proactively.
Fifth, and finally, the Company has for the past year, and will
going forward, factor into its capital investment decision
making process assumptions regarding the costs of complying with
anticipated GHG regulations. As a result, all decisions with
respect to acquisitions, repowerings, project development and
further investment in our existing facilities will be made on
the assumption that there will be a cost associated with GHG
emissions in the future.
FORNRG
Update
For 2007, NRG attained its previously announced target of
$220 million which includes $11 million of
one-time
benefits. The 2007 results were largely driven by corporate
initiatives and improved performance of the generating fleet
particularly in the area of generating capacity, heat rate and
station service. During 2007, the Company announced the
acceleration and planned conclusion of the FORNRG 1.0
program by bringing forward the previously announced 2009 target
of $250 million in pre tax income improvements to 2008.
During 2008, the Company will launch the next phase of the
program under the banner FORNRG 2.0.
RepoweringNRG
Update
In 2006, NRG announced a comprehensive portfolio redevelopment
program, referred to as RepoweringNRG, which involves the
development, construction and operation of new multi-fuel,
multi-technology generation capacity at NRGs existing
domestic sites to meet the growing demand in the Companys
core markets. Through this initiative, the Company anticipates
retiring certain existing units and adding new generation, with
an emphasis on new baseload capacity that is expected to be
supported by long-term power purchase agreements, or PPAs, and
financed with limited or non-recourse project financing. NRG
continues to expect that these repowering investments will
provide one or more of the following benefits: improved heat
rates; lower delivered costs; expanded electricity production
capability; an improved ability to dispatch economically across
the Merit Order; increased technological and fuel diversity; and
reduced environmental impacts. The Company anticipates that the
RepoweringNRG program will also result in indirect
benefits, including the continuation of operations and retention
of key personnel at its existing facilities.
18
A critical aspect of the RepoweringNRG program is the
extent to which the Company is actively pursuing investments in
new generating facilities that will be highly efficient and will
employ no
and/or low
carbon technologies to limit
CO2
emissions and other air emissions. The Company anticipates that
these investments will result in long-term GHG intensity
reductions in its generating portfolio.
Although NRG believes it is unlikely that the program will be
fully implemented as originally proposed, the Company expects
that the overall capital expenditures in connection with the
program will be substantial. The Company plans to mitigate the
capital cost of the program through equity partnerships and
public-private partnerships, as well as through the
reimbursement of development fees for certain projects. To
further mitigate the investment risks, NRG anticipates entering
into long-term PPAs and engineering, procurement and
construction, or EPC, contracts. In addition, the proposed
increase in generation capacity and capital costs resulting from
RepoweringNRG could change as proposed projects are
included or removed from the program due to a number of factors,
including successfully obtaining required permits, long-term
PPAs, availability of financing on favorable terms, and
achieving targeted project returns. The projects that have been
identified as part of the RepoweringNRG program are also
subject to change as NRG refines the program to take into
account the success rate for completion of projects, changes in
the targeted minimum return thresholds, and evolving market
dynamics.
The following is a summary of repowering projects that have
either been completed and are operating, under construction or
in certain stages of development. In addition, NRG continues to
participate in active bids in response to requests for proposals
in markets in which it operates, particularly in the West and
Northeast regions.
Plants
Completed and Operating
Long Beach On August 1, 2007, the
Company successfully completed and commissioned the repowering
of 260 MW of new gas-fired generating capacity at its Long
Beach Generating Station. This new generation will provide
needed support for the summer peak demand to Southern California
Edison, or SCE, and California Independent System Operator, or
CAISO. This project is backed by a
10-year PPA
executed with SCE in November 2006. The total incremental
capital cost for the project was approximately $78 million.
Plants
under Construction
Cedar Bayou Generating Station In
August 2007, NRG Cedar Bayou Development Company LLC, or NRG
Cedar Bayou, a subsidiary of NRG Energy, Inc., and EnergyCo
Cedar Bayou 4, LLC, or EnergyCo Cedar Bayou, a subsidiary of
EnergyCo, LLC, which is a joint venture between PNM Resources
Inc. and a subsidiary of Cascade Investment, LLC, agreed to
jointly develop, construct, operate and own, on a 50/50
undivided interest basis, a new 550 MW combined cycle
natural gas turbine generating plant at NRGs Cedar Bayou
Generating Station in Chambers County, Texas.
NRG will also provide various ongoing services related to
construction management, plant operations and maintenance, and
use of existing NRG facilities in return for a fixed fee plus
reimbursement of the Companys costs.
On July 26, 2007, the Texas Commission on Environmental Air
Quality, or TCEQ, granted an air permit required for
construction and operation of the new plant, and on
August 1, 2007, NRG Cedar Bayou and EnergyCo Cedar Bayou
entered into an EPC agreement with Zachry Construction
Corporation to construct the plant which is expected to be
completed in 2009.
Sherbino Wind Farm On February 1,
2008, NRG, through its wholly owned subsidiary, Padoma Wind
Power LLC., entered into a fifty percent partnership with BP
Alternative Energy North America Inc. to build the first phase
of the Sherbino Wind Farm, a 150 MW wind project. The
Sherbino I Wind Farm will be located on a more than
9,000 acre mesa with an elevation of approximately
3,000 feet above sea level, approximately 40 miles
east of Fort Stockton in Pecos County, Texas. Initial
construction of the Sherbino I Wind Farm commenced in November
2007 and will utilize 50 Vestas V90 3 MW wind turbine
generators. The project is scheduled to reach commercial
operations by the end of 2008 with NRGs 50 percent
ownership providing a net capacity of 75 MW or the
equivalent of 25 generators.
19
Cos Cob The Company continues to
proceed with the repowering project at its Cos Cob site in
Connecticut, with the construction of 40 MW of peaking
capacity following the receipt of the siting and air permits.
The Company anticipates completion and commissioning of the unit
in the summer of 2008.
Plants
under Development
STP Units 3 and 4 On November 30,
2007, the Nuclear Regulatory Commission, or NRC, accepted the
Companys Combined Construction and Operating License
Application, or COLA, which was filed September 24, 2007,
together with San Antonios CPS Energy and South Texas
Project Nuclear Operating Company, or STPNOC, to build and
operate two new nuclear units at the STP nuclear power station
site. The total rated capacity of the new units, STP units 3 and
4, will equal or exceed 2,700 MW. The acceptance review
confirms that the application, the first to be filed with the
NRC in 29 years, is technically complete and sufficiently
addresses all necessary subject areas. With the COLA accepted or
docketed, the NRC begins a comprehensive and detailed review
process that includes requests for additional information, site
visits, responses from NRG, public hearings, NRC Environmental
Impact Statements and NRC Safety Evaluation Reports. The Company
expects to achieve commercial operation for Unit 3 approximately
48 months after issuance of the COLA, and commercial
operation for Units 4 approximately 12 months thereafter.
On October 29, 2007, NRG and the City of San Antonio,
acting through the City Public Service Board of
San Antonio, or CPS Energy, entered into an agreement
whereby the parties agreed to be equal partners in the
development of the two new units, and, in the event either party
chooses at any time not to proceed, gives the other party the
right to proceed with the project on its own. The agreement
provides for CPS Energy, based on its ownership percentage, to
reimburse NRG for a pro rata share of project costs NRG has
incurred, and to pay a pro rata share of future development
costs.
The Company and STPNOC have also signed a project services
agreement with Toshiba Corporation, a diversified major Japanese
manufacturer. Under this agreement, Toshiba will support NRG in
the design, engineering, construction, and procurement of two
nuclear reactors. STPNOC and NRG are engaged in continuing
negotiations with Toshiba and its potential consortium members
about a definitive EPC agreement. In addition, NRG has also
reserved for major, long-lead components for the STP expansion
projects, including the first reactor pressure vessel.
Huntley IGCC In December 2006, NRG won
a conditional award of a power purchase agreement in support of
the construction of a 600MW IGCC plant in a competitive bid
process with the New York Power Authority, or NYPA. This plant
would be built at the Companys existing Huntley facility.
The bid included selling capacity and energy to NYPA under a
long-term PPA. As part of the conditional award, NYPA entered
into a strategic alliance with NRG to pursue support from
federal, state and local programs in order to close the
perceived pricing gap between NRGs proposal and
NYPAs requirements, while preserving the material benefits
of NRGs proposal relating to innovative clean coal power
generation, including
CO2
capture and geologic sequestration plans which the State of New
York subsequently required as part of the overall award.
Since the announcement of the conditional award, NRG has worked
with Mitsubishi Heavy Industries, or MHI, as a technology
provider for this project. To date the initial engineering, or
feasibility study has been completed for the project. The next
phase includes front-end engineering design, or FEED. During
this phase, NRG will determine specific design requirements and
costing for the project, including
CO2
capture. At the same time, NRG and MHI would negotiate the form
of an EPC agreement. NRG has also completed its detailed
geological assessment of target sequestration sites which
indicates that no fatal flaws exist for the long term injection
and storage of the captured
CO2.
NRG is working with the State of New York to build the legal and
regulatory infrastructure for the injection of the
CO2
and the future responsibility for sequestered carbon.
With respect to the price gap closure initiative, the Company
has identified existing local and state incentives and programs
that can effectively close the price gap. It has submitted these
initiatives to the State, where analysis against the
States budget has begun. NRG expects the State to formally
respond to the price gap analysis during the first half of 2008.
Any remaining price gaps will need to be closed through federal
initiatives and the Company has a federal outreach effort in
place to address these initiatives in Washington D.C.
20
The next significant phase of this project, particularly the
FEED work, will require monthly spending at a level that could
not be a supported without the State formally approving the
award. NRG is working with NYPA and the Governors staff to
secure this award before moving to the next phase of the project.
Big Cajun I NRG is continuing its
development efforts to repower the Big Cajun I site with a 207
net MW circulating fluidized bed boiler, or CFB. NRG has
signed a memorandum of understanding with potential co-owners
for approximately 50% of the plants capacity and has also
signed term sheets for long-term PPAs for the remaining 50%. In
January 2008, the Company received the Title V air permit
for the project from the Louisiana Department of Environmental
Quality, or LDEQ, however in February 2008, certain
environmental advocacy groups initiated a state court proceeding
to challenge of the LDEQs decision to issue the air permit
and stay the effectiveness of the air permit. NRG believes that
claims of the environmental advocacy groups are without merit,
and NRG plans to intervene in the state court proceedings.
Subject to the favorable resolution of the state court
proceedings, the project timeline anticipates an engineering and
construction start date in late 2008.
Connecticut Peakers In 2007, the
Connecticut legislature passed a law that required state
utilities, and permitted others, to submit plans for new peaking
generation facilities in Connecticut subject to a regulated
long-term
contract. In the fall of 2007, NRG and United Illuminating
Company, or UI, a wholly-owned subsidiary of UIL Holding
Corporation, announced a joint venture to respond to this
procurement process. NRG and UI subsequently formed GenConn
Energy LLC as their joint venture vehicle and submitted a joint
qualification package, as required, on February 1, 2008
with the Department of Public Utility Control, or DPUC. UI and
NRG are evaluating the optimal combination of project size and
locations that might be offered into their proposal. Binding
bids are due March 3, 2008, with a final decision
anticipated by June 2008.
econrg
Update
econrg is a complementary program to RepoweringNRG.
econrg seeks to reduce the Companys carbon intensity
through the implementation of low and no carbon repowering
projects and through the investment in and demonstration of
carbon capture and other environmentally advanced technologies.
econrg is also focused on increasing environmental awareness,
the advocacy of sound environmental policy and reducing the
environmental footprint of the Company, its assets and its
employees. The following is a summary of the Companys
econrg projects.
Commercial
Scale Carbon Capture and Sequestration
Demonstration
On November 2, 2007, NRG signed a memorandum of
understanding with Powerspan Corp., or Powerspan, to jointly
design, construct, and operate a demonstration facility that
will be among the largest carbon capture and sequestration
projects in the world and may be the first to achieve commercial
scale from an existing coal-fueled power plant. The project will
be constructed at NRGs W.A. Parish plant near Sugar Land,
Texas, and is designed to capture and sequester up to 90% of the
carbon dioxide from flue gas equal in quantity to that from a
125 MW unit using Powerspans proprietary
ECO2tm
technology, a post-combustion, regenerative process which uses
an ammonia-based solution to capture
CO2
from the flue gas and release it in a form that is ready for
safe transportation and permanent geological storage. The
CO2
from the process would either be sequestered or sold for use in
enhanced oil recovery projects. The project, which is expected
to be operational in 2012, will be funded by NRG, potential
partners and federal and state grants.
Plasma
Gasification Technology
On April 3, 2007, NRG purchased approximately
2.2 million shares at CAD$2.25 per share for a 6% interest
in Alter Nrg Corporation, a Canadian company that provides
alternative energy solutions using plasma gasification, a
process that converts carbon-containing materials into synthetic
gas. As part of the transaction NRG has been granted an
exclusive license to use Alter Nrg Corporations plasma
torch technology to (i) gasify fossil fuel and biomass in
power projects in the United States, and (ii) develop other
gasification projects in the vicinity of existing NRG plants. In
January 2008, the Company received a qualified approval from the
Massachusetts Department of Environmental Protection to convert
the Somerset, MA facility to a coal and biomass gasification
power facility.
21
Regional
Business Descriptions
NRG is organized into business units, with each of the
Companys core regions operating as a separate business
segment as discussed below.
TEXAS
NRGs largest business segment is located in Texas and is
comprised of investments in generation facilities located in the
physical control areas of the ERCOT market. These assets were
acquired on February 2, 2006, as part of the acquisition of
Texas Genco LLC.
Operating
Strategy
The Companys business in Texas is comprised of two sets of
assets: a set of three large solid-fuel baseload plants and a
set of gas-fired plants located in and around Houston.
NRGs operating strategy to maximize value and opportunity
across these assets is to (i) ensure the availability of
the baseload plants to fulfill their commercial obligations
under long-term forward sales contracts already in place,
(ii) manage the natural gas assets for profitability while
ensuring the reliability and flexibility of power supply to the
Houston market, (iii) take advantage of the skill sets and
market/regulatory knowledge to grow the business through
incremental capacity uprates and repowering development of
solid-fuel baseload and gas-fired units, and (iv) play a
leading role in the development of the ERCOT market by active
membership and participation in market and regulatory issues.
NRGs strategy is to sell forward a majority of its
solid-fuel baseload capacity in the ERCOT market under long-term
contracts or to enter into hedges by using natural gas as a
proxy for power prices. Accordingly, the Companys primary
focus will be to keep these solid-fuel baseload units running
efficiently. With respect to gas-fired assets, NRG will continue
contracting forward a significant portion of gas-fired capacity
one to two years out while holding a portion for
back-up in
case there is an operational issue with one of the baseload
units and to provide upside for expanding heat rates. For the
gas-fired capacity sold forward, the Company will offer a range
of products tailored to our customers needs. For the gas-fired
capacity that NRG will continue to sell commercially into the
market, the Company will focus on making this capacity available
to the market whenever it is economical to run.
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
32,648
|
|
|
|
31,371
|
|
|
|
31,299
|
|
Gas
|
|
|
5,407
|
|
|
|
7,983
|
|
|
|
6,806
|
|
Nuclear(a)
|
|
|
9,724
|
|
|
|
9,385
|
|
|
|
6,412
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
47,779
|
|
|
|
48,739
|
|
|
|
44,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
MWh information reflects the
undivided interest in total MWh generated by STP. On
May 19, 2005, Texas Genco LLC increased its undivided
interest in STP from 30.8% to 44.0%.
|
22
Generation
Facilities
As of December 31, 2007, NRGs generation facilities
in Texas consisted of approximately 10,805 MW of generation
capacity. The following table describes NRGs electric
power generation plants and generation capacity as of
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)(c)
|
|
|
Fuel-type
|
|
Solid Fuel Baseload Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A.
Parish(a)
|
|
Thompsons, TX
|
|
|
100.0
|
|
|
|
2,460
|
|
|
Coal
|
Limestone
|
|
Jewett, TX
|
|
|
100.0
|
|
|
|
1,690
|
|
|
Lignite/Coal
|
South Texas
Project(b)
|
|
Bay City, TX
|
|
|
44.0
|
|
|
|
1,175
|
|
|
Nuclear
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Solid Fuel Baseload
|
|
|
|
|
|
|
|
|
5,325
|
|
|
|
Operating Natural Gas-Fired Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cedar Bayou
|
|
Baytown, TX
|
|
|
100.0
|
|
|
|
1,500
|
|
|
Natural Gas
|
T. H. Wharton
|
|
Houston, TX
|
|
|
100.0
|
|
|
|
1,025
|
|
|
Natural Gas
|
W. A.
Parish(a)
|
|
Thompsons, TX
|
|
|
100.0
|
|
|
|
1,190
|
|
|
Natural Gas
|
S. R. Bertron
|
|
Deer Park, TX
|
|
|
100.0
|
|
|
|
840
|
|
|
Natural Gas
|
Greens Bayou
|
|
Houston, TX
|
|
|
100.0
|
|
|
|
760
|
|
|
Natural Gas
|
San Jacinto
|
|
LaPorte, TX
|
|
|
100.0
|
|
|
|
165
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Natural Gas-Fired
|
|
|
|
|
|
|
|
|
5,480
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Capacity
|
|
|
|
|
|
|
|
|
10,805
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
W. A. Parish has nine units, four
of which are baseload coal-fired units and five of which are
natural gas-fired units.
|
|
(b)
|
|
Generation capacity figure consists
of the Companys 44.0% undivided interest in the two units
at STP.
|
|
(c)
|
|
Actual capacity can vary depending
on factors including weather conditions, operational conditions
and other factors. ERCOT requires periodic demonstration of
capability, and the capacity may vary individually and in the
aggregate from time to time. Excludes 2,200 MW of
mothballed capacity available for redevelopment.
|
The following is a description of NRGs most significant
revenue generating plants in the Texas region:
W.A. Parish NRGs W.A. Parish plant
is one of the largest fossil-fired plants in the United States
based on total MWs of generation capacity. This plants
power generation units include four coal-fired steam generation
units with an aggregate generation capacity of 2,460 MW as
of December 31, 2007. Two of these units are 645/650 MW
steam units that were placed in commercial service in December
1977 and December 1978, respectively. The other two units are
565 MW and 600 MW steam units that were placed in
commercial service in June 1980 and December 1982, respectively.
All four units are serviced by two competing railroads that
diversify NRGs coal transportation options at competitive
prices. Each of the four coal-fired units have
low-NOx
burners and Selective Catalytic Reductions, or SCRs, installed
to reduce
NOx
emissions and baghouses to reduce particulates. In addition,
W.A. Parish Unit 8 has a scrubber installed to reduce
SO2
emissions.
Limestone NRGs Limestone plant is
a lignite and coal-fired plant located approximately
140 miles northwest of Houston. This plant includes two
steam generation units with an aggregate generation capacity of
1,690 MW as of December 31, 2007. The first unit is an
830 MW steam unit that was placed in commercial service in
December 1985. The second unit is an 860 MW steam unit that
was placed in commercial service in December 1986. Limestone
burns lignite from an adjacent mine, but also burns low sulfur
coal and petroleum coke. This serves to lower average fuel costs
by eliminating fuel transportation costs, which can represent up
to two-thirds of delivered fuel costs for plants of this type.
Both units have installed
low-NOx
burners to reduce
NOx
emissions and scrubbers to reduce
SO2
emissions.
NRG owns the mining equipment and facilities and a portion of
the lignite reserves located at the adjacent mine. Mining
operations are conducted by Texas Westmoreland Coal Co., a
single purpose, wholly-owned
23
subsidiary of Westmoreland Coal Company and the owner of a
substantial portion of the remaining lignite reserves. The
contract, entered into August 1999, ended December 31,
2007. Effective January 1, 2008, NRG entered into an
agreement with Texas Westmoreland Coal Co. to continue to supply
lignite from the same surface mine adjacent to the facility for
a nominal term of ten years with an option for future year
supply purchases. This is a cost-plus arrangement
under which NRG will pay all of Westmorelands agreed upon
production costs, capital expenditures, and a per ton mark up.
The annual volume demand is determined by NRG. The agreement
ensures lignite supply to NRG and confirms NRGs
responsibility for the final reclamation at the mine.
South Texas Project Electric Generating
Station STP is one of the newest and
largest nuclear-powered generation plants in the United States
based on total megawatts of generation capacity. This plant is
located approximately 90 miles south of downtown Houston,
near Bay City, Texas and consists of two generation units each
representing approximately 1,335 MW of generation capacity.
STPs two generation units commenced operations in August
1988 and June 1989, respectively. For the year ended
December 31, 2007, STP had a zero percent forced outage
rate and a 97% net capacity factor.
STP is currently owned as a tenancy in common between NRG and
two other co-owners. NRG owns a 44%, or approximately
1,175 MW, interest in STP, the City of San Antonio
owns a 40% interest and the City of Austin owns the remaining
16% interest. Each co-owner retains its undivided ownership
interest in the two nuclear-fueled generation units and the
electrical output from those units. Except for certain plant
shutdown and decommissioning costs and NRC licensing
liabilities, NRG is severally liable, but not jointly liable,
for the expenses and liabilities of STP. The four original
co-owners of STP organized South Texas Project Nuclear Operating
Company, or STPNOC, to operate and maintain STP. STPNOC is
managed by a board of directors composed of one director
appointed by each of the three co-owners, along with the chief
executive officer of STPNOC. STPNOC is the NRC-licensed operator
of STP. No single owner controls STPNOC and most significant
commercial as well as asset investment decisions for the
existing units must be approved by two or more owners who
collectively control more than 60% of the interests.
The two STP generation units operate under licenses granted by
the NRC that expire in 2027 and 2028, respectively. These
licenses may be extended for additional
20-year
terms if the project satisfies NRC requirements. Adequate
provisions exist for long-term
on-site
storage of spent nuclear fuel throughout the remaining life of
the existing STP plant licenses.
Market
Framework
The ERCOT market is one of the nations largest and fastest
growing power markets. It represents approximately 85% of the
demand for power in Texas and covers the whole state, with the
exception of the far west (El Paso), a large part of the
Texas Panhandle and two small areas in the eastern part of the
state. For the past ten years, peak hourly demand in the ERCOT
market grew at a compound annual rate of 2.5%, compared to a
compound annual rate of growth of 2.1% in the United States for
the same period. For 2007, hourly demand ranged from a low of
21,790 MW to a high of 62,188 MW. ERCOT has limited
interconnections compared to other markets in the United
States currently limited to 1,106 MW of
generation capacity, and wholesale transactions within the ERCOT
market are not subject to regulation by the Federal Energy
Regulatory Commission, or FERC. Any wholesale producer of power
that qualifies as a power generation company under the Texas
electric restructuring law and that accesses the ERCOT electric
power grid is allowed to sell power in the ERCOT market at
unregulated rates.
The ERCOT market experienced significant construction of new
generation plants, with over 29,000 MW of new generation
capacity added to the market since 1996. As of December 31,
2007, aggregate net generation capacity of approximately
76,800 MW existed in the ERCOT market, of which 71.7% was
natural gas-fired. Approximately 20,600 MW, or 26.9%, was
lower marginal cost generation capacity such as coal, lignite
and nuclear plants. NRGs coal and nuclear fuel baseload
plants represent approximately 5,325 MW gross, or 25.9%, of
the total solid fuel baseload net generation capacity in the
ERCOT market. ERCOT has established a target equilibrium reserve
margin level of approximately 12.5%. The reserve margin for 2007
was 14.6% forecast to drop to 13.1% for 2008 per ERCOTs
latest Capacity Demand and Reserve Report. With the exception of
wind generation units, there has been very little generation
that has come online since 2004, and ERCOT projects reserve
margins to decrease in
24
2009 primarily due to load growth. Several new projects have
been announced or are under construction for 2010 and beyond,
and there are currently plans being considered by the PUCT to
build a significant amount of transmission from west Texas and
continuing across the state to enable wind generation to reach
load. The ultimate impact on the reserve margin and wholesale
dynamics from these plans are unknown.
In the ERCOT market, buyers and sellers enter into bilateral
wholesale capacity, power and ancillary services contracts or
may participate in the centralized ancillary services market,
including balancing energy, which ERCOT administers. An
October 1, 2005 Report on Existing and Potential
Electric System Constraints and Needs found that
natural gas-fired power plants set the market price of power
more than 90% of the time in the ERCOT market. As a result of
NRGs lower marginal cost for baseload coal and nuclear
generation assets, the Company expects these ERCOT assets to
generate power nearly 100% of the time they are available.
The ERCOT market is currently divided into four regions or
congestion zones, namely: North, Houston, South and West, which
reflect transmission constraints that are commercially
significant and which have limits as to the amount of power that
can flow across zones. NRGs W.A. Parish plant, STP, and
all its natural gas-fired plants are located in the Houston
zone. NRGs Limestone plant is located in the North zone.
The ERCOT market operates under the reliability standards set by
the North American Electric Reliability Council, or NERC. The
PUCT has primary jurisdiction over the ERCOT market to ensure
the adequacy and reliability of power supply across Texass
main interconnected power transmission grid. ERCOT is
responsible for facilitating reliable operations of the bulk
electric power supply system in the ERCOT market. Its
responsibilities include ensuring that power production and
delivery are accurately accounted for among the generation
resources and wholesale buyers and sellers. Unlike power pools
with independent operators in other regions of the country, the
ERCOT market is not a centrally dispatched power pool and ERCOT
does not procure power on behalf of its members other than to
maintain the reliable operations of the transmission system.
ERCOT also serves as an agent for procuring ancillary services
for those who elect not to provide their own ancillary services.
Power sales or purchases from one location to another may be
constrained by the power transfer capability between locations.
Under current ERCOT protocol, the commercially significant
constraints and the transfer capabilities along these paths are
reassessed every year and congestion costs are directly assigned
to those parties causing the congestion. This has the potential
to increase power generators exposure to the congestion
costs associated with transferring power between zones.
The PUCT has adopted a rule directing ERCOT to develop and
implement a wholesale market design that, among other things,
includes a day-ahead energy market and replaces the existing
zonal wholesale market design with a nodal market design that is
based on locational marginal prices for power. See also,
Regional Regulatory Developments Texas Region.
One of the stated purposes of the proposed market
restructuring is to reduce local (intra-zonal) transmission
congestion costs. The market redesign project is expected to
take effect in December 2008. NRG expects that implementation of
any new market design will require modifications to its existing
procedures and systems. Although NRG does not expect the
Companys competitive position in the ERCOT market to be
materially adversely affected by the proposed market
restructuring, the Company does not know for certain how the
planned market restructuring will affect its revenues, and some
of NRGs plants in ERCOT may experience adverse pricing
effects due to their location on the transmission grid.
NORTHEAST
NRGs second largest asset base is located in the Northeast
region of the United States and is comprised of investments in
generation facilities primarily located in the physical control
areas of NYISO, the ISO-NE and PJM.
Operating
Strategy
The Northeast regions strategy is focused on optimizing
the value of NRGs broad and varied generation portfolio in
the three interconnected and actively traded competitive
markets: the NYISO, the ISO-NE and the PJM. In the Northeast
markets, load-serving entities generally lack their own
generation capacity, with much of the generation base aging and
the current ownership of the generation highly disaggregated.
Thus, commodity prices are more volatile on an as-delivered
basis than in other NRG regions due to the distance and
occasional physical
25
constraints that impact the delivery of fuel into the region. In
this environment, NRG seeks both to enhance its ability to be
the low cost wholesale generator capable of delivering wholesale
power to load centers within the region from multiple locations
using multiple fuel sources, and to be properly compensated for
delivering such wholesale power and related services.
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
11,527
|
|
|
|
11,042
|
|
|
|
11,363
|
|
Oil
|
|
|
1,169
|
|
|
|
1,217
|
|
|
|
3,148
|
|
Gas
|
|
|
1,467
|
|
|
|
1,050
|
|
|
|
1,735
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
14,163
|
|
|
|
13,309
|
|
|
|
16,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs Northeast region assets are located in or near load
centers and inside chronic transmission constraints such as New
York City, Southwest Connecticut and the Delmarva Peninsula.
Assets in these areas tend to attract higher capacity revenues
and higher energy revenues and thus present opportunities for
repowering these sites. The Company seeks to enhance the value
of these sites primarily through the advocacy of capacity market
reforms that better reflect their locational value. Over the
past year, the Company has benefited from the introduction of
more robust capacity market reforms in both the New England
Power Pool, or NEPOOL, and PJM. The Locational Forward Reserve
Markets, or LFRM, in the NEPOOL, was effective October 1,
2006, and the transition capacity payments were effective
December 1, 2006 with an initial price of $3.05/kw month.
In all three LFRM auctions to date, the market has cleared at
the administratively set price of $14/kw month reflecting the
shortage of peaking generation especially in the Connecticut
zone. These relatively new markets serve as a prelude to the
full implementation of the Forward Capacity Market, or FCM,
which begins June 1, 2010, and for which the first auction
was conducted in February 2008. PJMs reliability pricing
model, or RPM, was effective June 1, 2007 and the Company
has participated in auctions providing capacity price certainty
through May 2011.
RMR Agreements Several of the Northeast
regions Connecticut assets are located in
transmission-constrained load pockets and have been designated
as required to be available to ISO-NE to ensure reliability.
These assets are subject to reliability must-run, or RMR,
agreements, which are contracts under which NRG agrees to
maintain its facilities to be available to run when needed, and
are paid to provide these capability services based on the
Companys costs. During 2007, Middletown and Montville were
covered by an RMR agreement. Unless terminated earlier, these
agreements will terminate on June 1, 2010 which coincides
with the commencement of the FCM in NEPOOL. On July 16,
2007, FERC conditionally accepted, subject to refund, the
Companys RMR filing for its Norwalk plant. This RMR was
retroactive to June 19, 2007, which coincides with the FERC
decision to eliminate PUSH bidding. The Company is engaged in
settlement discussions with FERC to determine the actual value
of the RMR payment this plant should receive. In the
recently-concluded FCM auction for delivery year 2010/2011, the
Company sought to de-list Norwalks units 1 and 2. ISO-NE
declined to accept that de-list bid on the grounds these units
were needed for reliability. Norwalk will likely operate
pursuant to an RMR agreement after June 1, 2010.
Generation
Facilities
As of December 31, 2007, NRGs generation facilities
in the Northeast region consisted of approximately 6,980 MW
of generation capacity, including assets located in transmission
constrained areas, such as New York City
1,415 MW, and Southwest Connecticut 535 MW.
26
The Northeast region power generation assets are summarized in
the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
|
|
|
Fuel-type
|
|
Oswego
|
|
Oswego, NY
|
|
|
100.0
|
|
|
|
1,635
|
|
|
Oil
|
Arthur Kill
|
|
Staten Island, NY
|
|
|
100.0
|
|
|
|
865
|
|
|
Natural Gas
|
Middletown
|
|
Middletown, CT
|
|
|
100.0
|
|
|
|
770
|
|
|
Oil
|
Indian River
|
|
Millsboro, DE
|
|
|
100.0
|
|
|
|
740
|
|
|
Coal
|
Astoria Gas Turbines
|
|
Queens, NY
|
|
|
100.0
|
|
|
|
550
|
|
|
Natural Gas
|
Huntley
|
|
Tonawanda, NY
|
|
|
100.0
|
|
|
|
380
|
|
|
Coal
|
Dunkirk
|
|
Dunkirk, NY
|
|
|
100.0
|
|
|
|
530
|
|
|
Coal
|
Montville
|
|
Uncasville, CT
|
|
|
100.0
|
|
|
|
500
|
|
|
Oil
|
Norwalk Harbor
|
|
So. Norwalk, CT
|
|
|
100.0
|
|
|
|
340
|
|
|
Oil
|
Devon
|
|
Milford, CT
|
|
|
100.0
|
|
|
|
140
|
|
|
Natural Gas
|
Vienna
|
|
Vienna, MD
|
|
|
100.0
|
|
|
|
170
|
|
|
Oil
|
Somerset Power
|
|
Somerset, MA
|
|
|
100.0
|
|
|
|
125
|
|
|
Coal
|
Connecticut Remote Turbines
|
|
Four locations in CT
|
|
|
100.0
|
|
|
|
105
|
|
|
Oil
|
Conemaugh
|
|
New Florence, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone
|
|
Shelocta, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast Region
|
|
|
|
|
|
|
|
|
6,980
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a description of NRGs most significant
revenue generating plants in the Northeast region:
Arthur Kill NRGs Arthur Kill plant is a
natural gas-fired power plant consisting of three units and is
located on the west side of Staten Island, New York. The plant
produces an aggregate generation capacity of 865 MW from
two intermediate load units (Units 20 and 30) and one peak
load unit (Unit GT-1). Unit 20 produces an aggregate generation
capacity of 350 MW and was installed in 1959. Unit 30
produces an aggregate generation capacity of 500 MW and was
installed in 1969. Both Unit 20 and Unit 30 were converted from
coal-fired to natural gas-fired facilities in the early 1990s.
Unit GT-1 produces an aggregate generation capacity of
15 MW and is activated when ConEd issues a maximum
generation alarm on hot days and during thunderstorms.
Astoria Gas Turbine Located in Astoria,
Queens, New York, the NRG Astoria Gas Turbine facility occupies
approximately 15 acres within the greater Astoria
Generating complex which includes several competing generating
facilities. NRGs Astoria Gas Turbine facility has an
aggregate generation capacity of approximately 550 MW from
19 operational combustion turbine generators classified into
three types of turbines. The first group consists of 12
gas-fired Pratt & Whitney GG-4 Twin Packs in Buildings
2, 3 and 4, which have a net generation capacity of 145 MW
per building. The second group consists of Westinghouse
Industrial Combustion Turbines #191A in Buildings 5, 7 and
8 that fire on liquid distillate with a net generation capacity
of approximately 12 MW per building. The third group
consists of Westinghouse Industrial Gas Turbines #251GG
located in Buildings 10, 11, 12 and 13 and fired on liquid
distillate with a net generation capacity of 20 MW per
building. The Astoria units also supply Black Start Service to
the NYISO. The site also contains tankage for distillate fuel
with a capacity of 86,000 barrels.
Dunkirk The Dunkirk plant is a coal-fired
plant located on Lake Erie in Dunkirk, New York. This plant
produces an aggregate generation capacity of 530 MW from
four baseload units. Units 1 and 2 produce up to 75 MW each
and were put in service in 1950, and Units 3 and 4 produce
approximately 190 MW each and were put in service in 1959
and 1960, respectively. In the spring of 2006, the plant
completed changes to switch from eastern bituminous coal to low
sulfur PRB coal in order to comply with various federal and
state emissions standards, as well as the New York Department of
Environmental Conservation, or NYSDEC, settlement referred to in
the following paragraph.
27
Huntley The Huntley plant is a coal-fired
plant consisting of six units and is located in Tonawanda,
New York, approximately three miles north of Buffalo. The
plant has a net generation capacity of 380 MW from two
baseload units (Units 67 and 68). Units 67 and 68 generate a net
capacity of approximately 190 MW each, and were put in
service in 1957 and 1958, respectively. Units 63 and 64 are
inactive and were officially retired in May 2006. NRG retired
Units 65 and 66 effective June 3, 2007 pursuant to a
settlement agreement reached with NYSDEC in January 2005. Per
that agreement, NRG will reduce
NOx
and
SO2
emissions from the Companys Huntley and Dunkirk plants
through 2013 in the aggregate by over 8,090 lbs and 8,690 lbs,
respectively. A large portion of these reductions will be
achieved through the use of low sulfur PRB coal and through
installation of back end control facilities referred to as
baghouses. Construction of the back end control facilities
commenced in 2007 and is anticipated to be completed in fall of
2008 for the Huntley facility and fall of 2009 for the Dunkirk
facility.
Indian River The Indian River Power plant is
a coal-fired plant located in southern Delaware on a
1,170 acre site. The plant consists of four coal-fired
electric steam units, Units 1 through 4 and one 15 MW
combustion turbine, bringing total plant capacity to
approximately 740 MW. Units 1 and 2 are each 80 MW of
capacity and were placed in service in 1957 and 1959,
respectively. Unit 3 is 155 MW of capacity and was placed
in service in 1970, while Unit 4 is 410 MW of capacity and
was placed in service in 1980. Units 3 and 4 are equipped with
selective non-catalytic reduction systems, for the reduction of
NOx
emissions. All four units are equipped with electrostatic
precipitators to remove fly ash from the flue gases as well as
low
NOx
burners with over fired air to control
NOx
emissions. Units 1, 2 and 3 combust eastern bituminous coal,
while Unit 4 is fueled with low sulfur compliance coal. Pursuant
to a consent order dated September 25, 2007, between NRG
and DNREC, NRG agreed to operate the units in a manner that
would limit the emissions of
NOx,
SO2
and mercury. Further, the Company agreed to mothball unit 2 by
May 1, 2010, and unit 1 by May 1, 2011, and has
notified PJM of the plan to mothball these units. In the absence
of the appropriate control technology installed at this
facility, Units 3 and 4 totaling approximately 565 MW,
could not operate beyond December 31, 2011, per terms of
the consent order.
Market
Framework
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,
similar market designs. Each ISO dispatches power plants to meet
system energy and reliability needs, and settles physical power
deliveries at Locational Marginal Prices, or LMPs, which reflect
the value of energy at a specific location at the specific 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 create a reliable and least-cost
dispatch. The ISO-sponsored LMP energy markets consist of two
separate and characteristically distinct settlement time frames.
The first is a financially firm, day-ahead unit commitment
market. The second is a financially settled, real-time dispatch
and balancing market. Prices paid in these LMP energy markets,
however, are affected by, among other things, market mitigation
measures, which can result in lower prices associated with
certain generating units that are mitigated because they are
deemed to have locational market power, and by $1,000/MWh energy
market price caps that are in place in all three Northeast ISOs.
SOUTH
CENTRAL
As of December 31, 2007, NRG owned approximately
2,850 MW of generating capacity in the South Central region
of the United States. The region lacks a regional transmission
organization or ISO and, therefore, remains a bilateral market,
making it less efficient than a region with an ISO-administered
energy market using large scale economic dispatch, such as the
Northeast region. NRG operates the LaGen Control Area which
encompasses the generating facilities and the Companys
cooperative load. As a result, the LaGen control area is capable
of providing control area services, in addition to wholesale
power, that allows NRG to provide full requirement services to
load-serving entities, thus making the LaGen Control Area a
competitive alternative to the integrated utilities operating in
the region.
Operating
Strategy
NRGs South Central region seeks to capitalize on three
factors: (1) its position as a significant coal-fired
generator in a market that is highly dependent on natural gas
for power generation, (2) its long-term contractual and
28
historical service relationship with eleven rural cooperatives
around Louisiana, and (3) its ability to make incremental
wholesale energy sales during periods when its coal-fired
capacity exceeds the cooperative contract requirements. The
South Central region works with its cooperative customers to
expand their and the Companys customer bases on terms
advantageous to all parties. The Company also works within the
confines of the Entergy Transmission System to obtain paths for
these incremental sales as well as secure transmission service
for long-term sales or expansions.
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
10,812
|
|
|
|
10,968
|
|
|
|
9,924
|
|
Gas
|
|
|
118
|
|
|
|
68
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10,930
|
|
|
|
11,036
|
|
|
|
10,009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Generation
Facilities
NRGs generating assets in the South Central region consist
primarily of its net ownership of power generation facilities in
New Roads, Louisiana, which is referred to as Big Cajun II, and
also includes the Sterlington, Rockford, Bayou Cove and Big
Cajun peaking facilities.
NRGs power generation assets in the South Central region
as of December 31, 2007 are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary Fuel
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
|
|
|
type
|
|
Big Cajun
II(a)
|
|
New Roads, LA
|
|
|
86.0
|
|
|
|
1,490
|
|
|
Coal
|
Bayou Cove
|
|
Jennings, LA
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Big Cajun I (Peakers) Units 3 & 4
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
210
|
|
|
Natural Gas
|
Big Cajun I Units 1 & 2
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
220
|
|
|
Natural Gas/Oil
|
Rockford I
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Rockford II
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
145
|
|
|
Natural Gas
|
Sterlington
|
|
Sterlington, LA
|
|
|
100.0
|
|
|
|
185
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total South Central
|
|
|
|
|
|
|
|
|
2,850
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
NRG owns 100% of Units 1 & 2;
58% of Unit 3
|
Big Cajun II NRGs Big
Cajun II plant is a coal-fired, sub-critical baseload plant
located along the banks of the Mississippi River, near Baton
Rouge, Louisiana. This plant includes three coal-fired
generation units (Units 1, 2 and 3) with an aggregate
generation capacity of 1,730 MW as of December 31,
2007, and generation capacity per unit of 580 MW,
575 MW and 575 MW, respectively. The plant uses coal
supplied from the Powder River Basin and was commissioned
between 1981 and 1983. NRG owns 100% of Units 1 and 2 and a 58%
undivided interest in Unit 3 for an aggregate owned
capacity of 1,490 MW of the plant. All three units have
been upgraded with advanced
low-NOx
burners and overfire air systems. The generators on Units 1 and
3 have been rewound, and the turbine controls on these units
have been replaced with a modern digital control system. Unit 2
is scheduled for a generator rewind and turbine controls
replacement in future years. Additionally, the turbine high and
intermediate pressure steam path on Unit 3 was replaced with a
high-efficiency design. Units 1 and 2 are scheduled for similar
upgrades in future years. These improvements are expected to
cost approximately $28 million. As part of future CAIR and
CAMR emission reductions, work is being finalized in the
evaluation of installation of new environmental equipment
and/or
participation in Cap and Trade as allowed in Louisianas
implementation plan.
29
Market
Framework
NRGs assets in the South Central region are located within
the franchise territories of vertically integrated utilities,
primarily Entergy Corp., or Entergy. In the South Central
region, all power sales and purchases are consummated
bilaterally between individual counterparties. Transacting
counterparties are required to procure transmission service from
the relevant transmission owners at their FERC-approved tariff
rates.
As of December 31, 2007, NRG had long-term all-requirements
contracts with eleven Louisiana distribution cooperatives with
initial terms ranging from five to twenty-five years. The South
Central region has seven contracts in the region that expire in
2025, with the remaining four contracts expiring between 2009
and 2014. In addition, NRG also has certain long-term contracts
with the Municipal Energy Authority of Mississippi, South
Mississippi Electric Power Association, and Southwestern
Electric Power Company, which collectively comprise an
additional 13% of the regions contract load requirement.
During limited peak demand periods, the load requirements of
these contract customers exceed the baseload capacity of
NRGs coal-fired Big Cajun II plant. During such peak
demand periods, NRG typically employs its own gas-fired assets,
or alternatively purchases power from external sources
frequently at higher prices than can be recovered under the
Companys contracts. As the load of the regions
customers grows, the Company can expect this imbalance to
worsen, unless NRG is successful in renegotiating the terms of
these long-term contracts or purchasing other low-cost
generation to meet demand. NRG has been successful in
negotiating contract modifications with several of the
regions long-term cooperative customers, which has
prevented the addition of large industrial or municipal loads at
the contract rates. Also, to minimize this risk during the peak
summer and winter seasons, the Company has been successful in
entering into structured agreements to reduce or eliminate the
need for spot market purchases.
WEST
NRGs portfolio in the West region currently consists of
the Long Beach Generating Station, the El Segundo Generating
Station, the Encina Generating Station and Cabrillo II, which
consists of 12 combustion turbines located in San Diego
county. In addition, NRG owns a 50% interest in the Saguaro
power plant located in Nevada. On March 31, 2006, NRG
purchased Dynegy Incs 50% ownership interest in WCP and
became the sole owner of the WCP assets. On January 3,
2007, NRG sold the Red Bluff and the Chowchilla II power
plants to Wayzata Investment Partners LLC.
Operating
Strategy
NRGs West region strategy is focused on maximizing the
cash flow and value associated with its generating plants and
the development of repowering projects that leverage off of
existing assets and sites, and the preservation of the
commercial value of the underlying real estate. There are three
principal components to this strategy: (1) responding to
expected market demand, initially in load serving entity RFPs
and eventually into a capacity market, and (2) using
existing emission allowances to permit new, more efficient
generating units at existing sites or siting plants at less
valuable property and (3) optimizing the value of the
regions coastal property for other purposes.
The Companys Encina Generating Station has sold all energy
and capacity, 965 MW, in the aggregate, to a load-serving
entity through 2009, on a tolling basis, and recovers its
operating costs plus a capacity payment. The tolling agreement
includes the sale of Resource Adequacy, or RA, capacity and
consequently the RMR contract with the CAISO on the Encina units
has been terminated effective December 31, 2007. CAISO and
Cabrillo Power I, LLC, Encinas owner, entered into
dual fuel and black start agreements to supplement the
availability obligations to the CAISO provided for under the
tolling agreements. The El Segundo Station has sold all energy
and capacity, 670 MW, in the aggregate, to a load-serving
entity through April 30, 2008, on a tolling basis, and
recovers its operating costs plus a capacity payment. For
calendar year 2008, the El Segundo station has entered into
Resource Adequacy, or RA, contracts with multiple load-serving
entities or power marketers, and a tolling agreement with a
power marketer for the period May 1, 2008 through
December 31, 2008, covering 387 MW of the available
670 MW. Cabrillo II sold 28 MW of RA capacity for
2008 and 88 MW of RA capacity from January 1, 2009
through November 30, 2013. To the extent not covered by an
RA agreement, Cabrillo IIs cost of operations including a
30
return on investment is covered by an RMR agreement that extends
through December 31, 2008. It is expected that Cabrillo
IIs RMR status will be renewed in 2009.
The Saguaro power plant is located in Henderson, Nevada, and is
contracted to Nevada Power and two steam hosts. The Saguaro
plant is contracted to Nevada Power through 2022, one steam
host, referred to as Olin (formerly known as Pioneer), whose
contract was extended in 2007 for an additional two years, and a
steam off taker, Ocean Spray, whose contract runs through 2015.
Saguaro Power Company, LP, the project company, procures fuel in
the open market. NRG manages its share of any fuel price risk
through NRGs commodity price risk strategy.
Generation
Facilities
NRGs power generation assets in the West region as of
December 31, 2007 are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
|
|
|
Fuel-type
|
|
Encina
|
|
Carlsbad, CA
|
|
|
100.0
|
|
|
|
965
|
|
|
Natural Gas
|
El Segundo
|
|
El Segundo, CA
|
|
|
100.0
|
|
|
|
670
|
|
|
Natural Gas
|
Long Beach
|
|
Long Beach, CA
|
|
|
100.0
|
|
|
|
260
|
|
|
Natural Gas
|
Cabrillo II
|
|
San Diego, CA
|
|
|
100.0
|
|
|
|
190
|
|
|
Natural Gas
|
Saguaro
|
|
Henderson, NV
|
|
|
50.0
|
|
|
|
45
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total West Region
|
|
|
|
|
|
|
|
|
2,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following are descriptions of the Companys most
significant revenue generating plants in the West region:
Encina The Encina Station is located in
Carlsbad, California and has a combined generating capacity of
965 MW from five fossil-fuel steam-electric generating
units and one combustion turbine. The five fossil-fuel
steam-electric units provide intermediate load services and
primarily use natural gas but also maintain dual fuel capability
for use only during gas supply force majeure conditions. Also
located at the Encina Station is a combustion turbine that
provides peaking services of 15 MW. Units 1, 2 and 3 each
have a generation capacity of approximately 107 MW and were
installed in 1954, 1956 and 1958, respectively. Units 4 and 5
have a generation capacity of approximately 300 MW and
330 MW respectively, and were installed in 1973 and 1978.
The combustion turbine was installed in 1966. Units 1, 2 and 3
are projected to be retired after 2010. Low
NOx
burner modifications and SCR equipment have been installed on
Units 1, 2, 3, 4 and 5.
El Segundo The El Segundo plant is
located in El Segundo, California and produces an aggregate
generation capacity of 670 MW from two gas-fired
intermediate load units (Units 3 and 4). These units, which have
a generation capacity of 335 MW each, were installed in
1964 and 1965, respectively. SCR equipment has been installed on
Units 3 and 4.
Long Beach On August 1, 2007, the
Company successfully completed and commissioned the repowering
of 260 MW of new gas-fired generating capacity at its Long
Beach Generating Station. This new generation provides needed
support for the summer peak demand to Southern California
Edison, or SCE, and California Independent System Operator
systems. This project is backed by a
10-year PPA
executed with SCE in November 2006. Total capital spending for
the project was approximately $78 million.
Cabrillo II Cabrillo II consists of
12 combustion turbines located on 4 sites throughout
San Diego county with an aggregate generating capacity of
190 MW. The combustion turbines were installed between 1968
and 1972 and are operated under a license agreement with
SDG&E through 2013. The combustion turbines provide peaking
services and serve a reliability function for the CAISO.
Market
Framework
NRGs assets in the West region primarily consist of older,
higher heat rate, natural gas-fired plants in southern
California. These plants, while older and less efficient than
newer combined cycle plants, provide an important
31
reliability function and were under tolling agreements for 2007.
CAISO has designated all of the units comprising El Segundo,
Encina and Cabrillo II to be capacity that meets the local
capacity procurement requirements of the local load-serving
entities. At times, all of the plants have been designated as
RMR, which entitles designated plants to certain fixed-cost
payments from the CAISO for the right to dispatch those units
during periods of locational constraints. Although CAISO retains
the option of renewing units as RMR, the current market
framework obligates Load Serving Entities to buy a portion of
their capacity requirements in the local areas where their load
resides. This local procurement obligation drives in part demand
for RA or tolling agreements on the units.
Californias investor-owned utilities are sponsoring
competitive solicitations for new fossil and renewable
generating capacity. NRG has submitted offers for new generation
capacity to be constructed at the El Segundo and Encina sites.
The new projects are in the process of siting permit review by
the California Energy Commission and their respective regional
air districts, and are supported by air emissions credits that
have been banked after the retirement of older generating units.
While neither project will be constructed without a long-term
off-take agreement with a credit worthy counter-party, both
projects have cost and location advantages that enhance their
competitive prospects.
INTERNATIONAL
As of December 31, 2007, NRG, through certain foreign
subsidiaries, had investments in power generation projects
located in Australia, Germany and Brazil with approximately
1,235 MW of generation capacity. In addition, NRG owns
interests in coal mines located in Germany. The Companys
strategy is to maximize its return on investment and therefore
concentrates on contract management; monitoring of its facility
operators to ensure safe, profitable and sustainable operations;
management of cash flow and finances; and growth of its
businesses through investments in projects related to current
businesses.
NRGs international power generation assets as of
December 31, 2007, are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
|
|
|
Fuel-type
|
|
Gladstone
|
|
Australia
|
|
|
37.5
|
|
|
|
605
|
|
|
Coal
|
Schkopau
|
|
Germany
|
|
|
41.9
|
|
|
|
400
|
|
|
Lignite
|
MIBRAG
|
|
Germany
|
|
|
50.0
|
|
|
|
75
|
|
|
Lignite
|
ITISA(a)
|
|
Brazil
|
|
|
99.2
|
|
|
|
155
|
|
|
Hydro
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
|
|
|
|
|
|
1,235
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
NRG entered into an agreement to
sell ITISA on December 18, 2007. The sale is subject to
regulatory and customary closing conditions.
|
Australia On June 8, 2006, NRG
announced the sale of the Companys 37.5% equity interest
in the Gladstone power station, Gladstone, and NRG subsidiary,
Gladstone Operating Services, to Transfield Services
an Australia-based company, for a purchase price of
approximately $209 million (AU$239 million), subject
to customary purchase price adjustments. The members of the
Gladstone joint venture have withheld consent to NRGs sale
of its equity interest in the venture and the transfer of
NRGs rights and obligations in the operation and
maintenance contract. NRG will continue to seek to close the
transaction in 2008 as agreed or on alternative terms.
Germany NRGs interests in Germany
include a 50% equity interest in MIBRAG, which mines
approximately 16 million metric tonnes of lignite per year
and owns 150 MW of electric generation capacity, and a
41.9% interest in Schkopau, a 900 MW generating plant
fueled with lignite from MIBRAG. NRG does not have direct
operational control of either of these facilities.
Approximately 84% of MIBRAGs revenues is generated from
lignite sales. MIBRAGs generation capacity comprises three
plants, 33% of their output is used to power MIBRAGs
mining operations and the balance is sold, either under a
contract or at spot, primarily to EnviaM, the local distribution
utility. NRG, through its wholly-owned subsidiary Saale Energie
GmbH, or SEG, owns 400 MW of the Schkopau plants
electric capacity which is sold under a long-term contract to
Vattenfall Europe Generation, AG.
32
Brazil Through its wholly-owned
subsidiary Tosli Acquisition B.V., or Tosli, a Netherlands
private limited liability company, NRG owns a 99.2% voting
equity interest in a 156 MW hydroelectric power plant
through Itiquira Energetica S.A., or ITISA, which is located in
the state of Mato Grosso, Brazil. On December 18, 2007, NRG
entered into a sale and purchase agreement to sell its 100%
interest in Tosli to Brookfield Power Inc., a wholly-owned
subsidiary of Brookfield Asset Management Inc., a Canadian asset
management company, focused on property, power and
infrastructure assets, for a purchase price of approximately
$288 million, plus the assumption of approximately
$60 million in debt. The sale is subject to the receipt of
regulatory approval and other customary closing conditions. NRG
anticipates completion of the sale transaction during first half
2008 and as discussed in Item 3 Note 3,
Discontinued Operations, the activities of Tosli and
ITISA have been classified as discontinued operations.
THERMAL
Through its wholly-owned subsidiary, NRG Thermal LLC, or NRG
Thermal, the Company owns thermal and chilled water businesses
that have a steam and chilled water capacity of approximately
1,040 megawatts thermal equivalent, or MWt. As of
December 31, 2007, NRG Thermal provided steam heating to
approximately 525 customers and chilled water to 100 customers
in five cities in the United States. The Companys thermal
businesses in Pittsburgh, Harrisburg and San Francisco are
regulated by their respective state Public Utility Commission.
The other thermal businesses are subject to contract terms with
their customers. In addition, NRG Thermal owns and operates a
thermal project that serves an industrial customer with
high-pressure steam. NRG Thermal also owns an 88 MW
combustion turbine peaking generation facility and a 16 MW
coal-fired cogeneration facility in Dover, Delaware as well as a
12 MW gas-fired project in Harrisburg, Pennsylvania.
Approximately 36% of NRG Thermals revenues are derived
from its district heating and chilled water business in
Minneapolis, Minnesota.
Regulatory
Matters
As operators of power plants and participants in wholesale
energy markets, certain NRG entities are subject to regulation
by various federal and state government agencies. These include
CFTC, FERC, NRC, PUCT and other public utility commissions in
certain states where NRGs generating assets are located.
In addition, NRG is subject to the market rules, procedures, and
protocols of the various ISO markets in which it participates.
The operations of, and wholesale electric sales from, NRGs
Texas region are not subject to rate regulation by FERC, as they
are deemed to operate solely within the ERCOT market and not in
interstate commerce. As discussed below, these operations are
subject to regulation by PUCT, as well as to regulation by the
NRC with respect to the Companys ownership interest in STP.
Commodities
Futures Trading Commission, or CFTC
CFTC, among other things, has regulatory oversight authority
over the trading of electricity and gas commodities, including
financial products and derivatives, under the Commodity Exchange
Act, or CEA. Specifically, under existing statutory authority,
CFTC has the authority to commence enforcement actions and seek
injunctive relief against any person, whenever that person
appears to be engaged in the communication of false or
misleading or knowingly inaccurate reports concerning market
information or conditions that affected or tended to affect the
price of natural gas, a commodity in interstate commerce, or
actions intended to or attempting to manipulate commodity
markets. CFTC also has the authority to seek civil monetary
penalties, as well as the ability to make referrals to the
Department of Justice for criminal prosecution, in connection
with any conduct that violates the CEA. Proposals are pending in
Congress to expand CFTC oversight of the over-the-counter
markets and bilateral financial transactions.
Federal
Energy Regulatory Commission
FERC, among other things, regulates the transmission and the
wholesale sale of electricity in interstate commerce under the
authority of the Federal Power Act, or FPA. In addition, under
existing regulations, FERC determines whether an entity owning a
generation facility is an Exempt Wholesale Generator, or EWG, as
defined in the Public Utility Holding Company Act of 2005, or
PUHCA of 2005. FERC also determines whether a
33
generation facility meets the ownership and technical criteria
of a Qualifying Facility, or QF, under Public Utility Regulatory
Policies Act of 1978, or PURPA. Each of NRGs
U.S. generating facilities has either been determined by
FERC to qualify as a QF, or the subsidiary owning the facility
has been determined to be a EWG.
Federal Power Act The FPA gives FERC
exclusive rate-making jurisdiction over the wholesale sale of
electricity and transmission of electricity in interstate
commerce. Under the FPA, FERC, with certain exceptions,
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. NRGs QFs are currently exempt from FERCs
rate regulation under Sections 205 and 206 of the FPA to
the extent that sales are made pursuant to a state regulatory
authoritys implementation of PURPA.
Public utilities under the FPA are required to obtain
FERCs acceptance, pursuant to Section 205 of the FPA,
of their rate schedules for the wholesale sale of electricity.
All of NRGs non-QF generating and power marketing
companies in the United States make sales of electricity
pursuant to market-based rates authorized by FERC. FERCs
orders that grant NRGs generating and power marketing
companies market-based rate authority reserve the right to
revoke or revise that authority if FERC subsequently determines
that NRG can exercise market power, create barriers to entry, or
engage in abusive affiliate transactions. In addition,
NRGs market-based sales are subject to certain market
behavior rules and, if any of its generating or power marketing
companies were deemed to have violated any one of those rules,
they would be subject to potential disgorgement of profits
associated with the violation
and/or
suspension or revocation of their market-based rate authority,
as well as criminal and civil penalties. As a condition to the
orders granting NRG market-based rate authority, every three
years NRG is required to file a market update to demonstrate
that it continues to meet FERCs standards with respect to
generating market power and other criteria used to evaluate
whether its entities qualify for market-based rates. NRG is also
required to report to FERC any material changes in status that
would reflect a departure from the characteristics that FERC
relied upon when granting NRGs various generating and
power marketing companies market-based rates. If NRGs
generating and power marketing companies were to lose their
market-based rate authority, such companies would be required to
obtain FERCs acceptance of a cost-of-service rate schedule
and could become subject to the accounting, record-keeping, and
reporting requirements that are imposed on utilities with
cost-based rate schedules.
NRG filed the most recent triennial update of its market power
analysis on March 26, 2007, and this filing was accepted by
FERC on August 9, 2007. On June 21, 2007, FERC issued
its long-awaited final rule on market-based rates for wholesale
sales of electric energy, capacity, and ancillary services. Of
particular note to NRG, the new rule now requires applicants to
use submarkets within an RTO region as the relevant geographic
market, specifically identifying Southwest Connecticut (and the
Connecticut Import interface), New York City, and PJM East as
such submarkets. The impact of this rule, and any additional
mitigation that may be imposed by FERC as a result of a
determination of market power in a submarket, cannot be
determined at this time.
Section 203 of the FPA requires FERCs prior approval
for the transfer of control of assets subject to FERCs
jurisdiction. Section 204 of the FPA gives FERC
jurisdiction over a public utilitys issuance of securities
or assumption of liabilities. However, FERC typically grants
blanket approval for future securities issuances and the
assumption of liabilities to entities with market-based rate
authority. In the event that one of NRGs generating and
power marketing companies were to lose its market-based rate
authority, such companys future securities issuances or
assumption of liabilities could require prior approval from FERC.
In compliance with Section 215 of the Energy Policy Act of
2005, or EPAct of 2005, FERC has approved the North American
Electric Reliability Corporation, or NERC, as the National
Energy Reliability Organization, or ERO. As the ERO, NERC is
responsible for the development and enforcement of mandatory
reliability standards for the wholesale electric power system.
NRG is responsible for complying with the standards in the
regions in which it operates. As the ERO, NERC has the ability
to assess financial penalties for non-compliance. In addition to
complying with NERC requirements, each NRG entity must comply
with the requirements of the regional reliability council for
the region in which it is located.
Public Utility Holding Company Act of
2005 PUHCA of 2005 provides FERC with
certain authority over and access to books and records of public
utility holding companies not otherwise exempt by virtue of
their ownership of EWGs, QFs, and Foreign Utility Companies, or
FUCOs. NRG is a public utility holding company, but
34
because all of the Companys generating facilities have QF
status or are owned through EWGs, it is exempt from the
accounting, record retention, and reporting requirements of
PUHCA.
Public Utility Regulatory Policies
Act PURPA was passed in 1978 in large part
to promote increased energy efficiency and development of
independent power producers. PURPA created QFs to further both
goals, and FERC is primarily charged with administering PURPA as
it applies to QFs. As discussed above, under current law, some
categories of QFs may be exempt from regulation under the FPA as
public utilities. PURPA incentives also initially included a
requirement that utilities must buy and sell power to QFs. Among
other things, EPAct of 2005 provides for the elimination of the
obligation imposed on certain utilities to purchase power from
QFs at an avoided cost rate under certain conditions. However,
the purchase obligation is only eliminated if FERC first finds
that a QF has non-discriminatory access to wholesale energy
markets having certain characteristics, including
nondiscriminatory transmission and interconnection services
provided by a regional transmission entity in certain
circumstances. Existing contracts entered into under PURPA are
not expected to be impacted. NRG currently owns only one QF,
Saguaro Power Company, a Limited Partnership, which is
interconnected to and has a contact with Nevada Power Company.
Nevada Power Company is not located in a region with an ISO
market.
Nuclear
Regulatory Commission, or NRC
The NRC is authorized under the Atomic Energy Act of 1954, as
amended, or the AEA, among other things, to grant licenses for,
and regulate the operation of, commercial nuclear power
reactors. As a holder of an ownership interest in STP, NRG is an
NRC licensee and is subject to NRC regulation. The NRC license
gives the Company the right to only possess an interest in STP
but not to operate it. Operating authority under the NRC
operating license for STP is held by STPNOC. NRC regulation
involves licensing, inspection, enforcement, testing,
evaluation, and modification of all aspects of plant design and
operation including the right to order a plant shutdown,
technical and financial qualifications, and decommissioning
funding assurance in light of NRC safety and environmental
requirements. In addition, NRCs written approval is
required prior to a licensee transferring an interest in its
license, either directly or indirectly. As a possession-only
licensee, i.e., non-operating co-owner, the NRCs
regulation of NRG is primarily focused on the Companys
ability to meet its financial and decommissioning funding
assurance obligations. In connection with the NRC license, the
Company and its subsidiaries have a support agreement to provide
up to $120 million to support operations at STP.
Decommissioning Trusts − Upon expiration of
the operation licenses for the two generating units at STP,
currently scheduled for 2027 and 2028, the co-owners of STP are
required under federal law to decontaminate and decommission the
STP facility. Under NRC regulations, a power reactor licensee
generally must pre-fund the full amount of its estimated NRC
decommissioning obligations unless it is a rate-regulated
utility, or a state or municipal entity that sets its own rates,
or has the benefit of a state-mandated non-bypassable charge
available to periodically fund the decommissioning trust such
that the trust, plus allowable earnings, will equal the
estimated decommissioning obligations by the time the
decommissioning is expected to begin.
As a result of the acquisition of Texas Genco LLC, NRG through
its 44% ownership interest has become the beneficiary of
decommissioning trusts that have been established to provide
funding for decontamination and decommissioning of STP.
CenterPoint Energy Houston Electric, LLC, or CenterPoint, and
American Electric Power, or AEP, collect, through rates or other
authorized charges to their electric utility customers, amounts
designated for funding NRGs portion of the decommissioning
of the facility.
In the event that the funds from the trusts are ultimately
determined to be inadequate to decommission the STP facilities,
the original owners of the Companys STP interests,
CenterPoint and AEP, each will be required to collect, through
their PUCT-authorized non-bypassable rates or other charges to
customers, additional amounts required to fund NRGs
obligations relating to the decommissioning of the facility.
Following the completion of the decommissioning, if surplus
funds remain in the decommissioning trusts, those excesses will
be refunded to the respective rate payers of CenterPoint or AEP,
or their successors.
Public
Utility Commission of Texas, or PUCT
NRGs Texas generation subsidiaries are registered as power
generation companies with PUCT. The companies within the Texas
region are also regulated as a Qualified Scheduling Entity. PUCT
also has jurisdiction over
35
power generation companies with regard to their sales in the
wholesale markets, the implementation of measures to address
undue market power or price volatility, and the administration
of nuclear decommissioning trusts. The PUCT exercises its
jurisdiction both directly, and indirectly, through its
oversight of ERCOT, the regional transmission organization. NRG
Power Marketing LLC, or PMI, is registered as a power marketer
with the PUCT and thus is also subject to the jurisdiction of
the PUCT with respect to its sales in ERCOT.
Regional
Regulatory Developments
In New England, New York, the Mid-Atlantic region, the Midwest
and California, FERC has approved regional transmission
organizations, also commonly referred to as independent system
operators, or ISOs. Most of these ISOs administer a wholesale
centralized bid-based spot market in their regions pursuant to
tariffs approved by FERC and associated ISO market rules. These
tariffs/market rules dictate how the capacity and energy markets
operate, how market participants may make bilateral sales with
one another, and how entities with market-based rates are
compensated within those markets. The ISOs in these regions also
control access to and the operation of the transmission grid
within their regions. In Texas, pursuant to a 1999 restructuring
statute, the PUCT granted similar responsibilities to ERCOT.
NRG is affected by rule/tariff changes that occur in the ISO
regions. The ISOs 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
market power or volatility in these markets. These types of
price limitations and other regulatory mechanisms may adversely
affect the profitability of NRGs generation facilities
that sell capacity and energy into the wholesale power markets.
In addition, new approaches to the sale of electric power are
being implemented, and it is not clear whether they will operate
effectively or whether they will provide adequate compensation
to generators over the long-term.
Texas
Region
ERCOT has adopted Texas Nodal Protocols that will
revise the wholesale market design to incorporate locational
marginal pricing (in place of the current ERCOT zonal market).
Major elements of the Texas Nodal Protocols include the
continued capability for bilateral contracting of energy and
ancillary services, a financially binding day-ahead market,
resource-specific energy and ancillary service bid curves, the
direct assignment of all congestion rents, nodal energy prices
for resources, aggregation of nodal to zonal energy prices for
loads, congestion revenue rights (including pre-assignment for
public power entities), and pricing safeguards. The PUCT
approved the Texas Nodal Protocols on April 5, 2006, and
full implementation of the new market design is expected in
December 2008. In other rulemakings, the PUCT has expanded its
enforcement policy, increased market oversight, and established
market and generator-specific data disclosure requirements
designed to increase market transparency.
Northeast
Region
New England NRGs Middletown and
Montville facilities continue to be operated pursuant to RMR
agreements that were accepted by the Commission on
February 1, 2006 (effective January 1, 2006). Unless
terminated earlier, the Middletown and Montville RMR agreements
will terminate upon the commencement of the Forward Capacity
Market, or FCM, as discussed below. The Devon RMR Agreement
terminated on December 31, 2006. On July 16, 2007,
FERC conditionally accepted, subject to refund, an RMR agreement
filed on April 26, 2007 by Norwalk Power for its units 1
and 2, specifying a June 19, 2007 effective date.
Norwalks RMR rate, as well as its eligibility for the RMR
agreement determined based upon the facilitys projected
market revenues and costs, are subject to further proceedings.
Norwalk filed for the RMR agreement in response to FERCs
order eliminating the Peaking Unit Safe Harbor bidding mechanism
which took effect on June 19, 2007. In the
recently-concluded FCM auction for delivery year 2010/2011, the
Company sought to de-list Norwalks units 1 and 2. ISO-NE
declined to accept that de-list bid on the grounds these units
were needed for reliability. Norwalk will likely operate
pursuant to an RMR agreement after June 1, 2010.
On December 28, 2006, the Attorneys General of the State of
Connecticut and Commonwealth of Massachusetts filed in the U.S.
Court of Appeals for the D.C. Circuit an appeal of the FERC
orders accepting
36
the settlement of the New England capacity market design. The
settlement, filed March 7, 2006, by a broad group of New
England market participants, provides for interim capacity
transition payments for all generators in New England for
the period starting December 1, 2006 through May 31,
2010, and the establishment of a FCM commencing May 31,
2010. On June 16, 2006, FERC issued an order accepting the
settlement, which was reaffirmed on rehearing by order dated
October 31, 2006. Interim capacity transition payments
provided for under the FCM settlement commenced December 1,
2006, as scheduled. The first FCM auction for the 2010/2011
delivery year was concluded on February 6, 2008, and
bidding reached the minimum floor price of $4.50 per kW-month. A
successful appeal by the Attorneys General could disturb the
settlement and create a refund obligation of interim capacity
transition payments. Oral arguments were held on
February 14, 2008.
New York On July 6, 2007, FERC
issued an order establishing an approximately six-month paper
hearing process to address reforms to the in-city Installed
Capacity, or ICAP, market and to formulate comprehensive
solutions. On October 4, 2007, the NYISO filed its proposal
for revisions to the ICAP market for the New York City zone.
While the NYISOs proposal will retain the existing ICAP
market structure, it will impose additional market power
mitigation on the current owners of Consolidated Edisons
divested generation units in New York City (which include
NRGs Arthur Kill and Astoria facilities) who are deemed to
be pivotal suppliers. Specifically, the NYISO proposal will
impose a reference price on pivotal suppliers and require bids
to be submitted at or below the reference price. The reference
price will be the expected clearing price based upon the
intersection of the supply curve and the ICAP Demand Curve if
all suppliers bid as price-takers. The NYISO proposal is
expected to result in a significant decrease in the clearing
price for New York City ICAP. Earlier this year, FERC had
rejected proposed mitigation that would have effectively lowered
the capacity offer cap for those units from $105/kW-year to
$82/kW-year. Although that proposal was rejected on
March 6, 2007, FERC initiated an investigation to determine
the justness and reasonableness of the NYISOs in-city
installed capacity market, setting a refund effective date of
May 12, 2007. The NYISOs October 4, 2007, filing
proposes that any market reforms should be implemented only
prospectively and that no refunds should be required.
The state-wide Installed Reserve Margin, or IRM, is set annually
by the New York State Reliability Council, or NYSRC, and affects
the overall demand for capacity in the New York market. On
December 14, 2007, the NYSRC approved a 2008 IRM of 15%,
which is a reduction of 1.5% from last years requirement
and effectively offsets any increased demand for capacity that
would have occurred due to load growth. Additionally, on
January 29, 2008, FERC accepted the NYISOs installed
capacity demand curves for 2008/2009, 2009/2010, and 2010/2011.
The demand curves serve as a critical determinant of capacity
market prices, and if approved, would potentially increase
prices slightly in the rest-of-state market while reducing
prices below their current levels in the New York City market
for the next two years, all other factors remaining constant.
PJM On December 22, 2006, FERC issued an
order approving the settlement agreement filed
September 29, 2006, in the Reliability Pricing Model, or
RPM, proceeding establishing a new capacity market mechanism,
the key components of which include the determination of
capacity prices through use of a downward-sloping demand curve,
locational pricing, and a forward capacity market. PJM has
conducted the RPM auctions for the 2007/2008, 2008/2009,
2009/2010, and 2010/2011 delivery years, and has been operating
under the RPM since June 1, 2007. Several parties, however,
have appealed the FERCs order accepting the settlement. A
successful appeal could potentially disrupt RPM implementation
and create a refund obligation. On January 31, 2008, PJM
submitted to FERC a proposal to increase its Cost of New Entry,
which is a critical component of the demand curve in the RPM
market, for the 2011/2012 delivery year. PJMs proposed
increase is opposed by consumer interests.
South
Central Region
Entergy has begun to implement its Independent Coordinator of
Transmission, or ICT, proposal that will provide
(i) independent oversight over the operations of the
Entergy transmission system, including the processing of
interconnection and transmission requests; (ii) a new
process and standard for assigning cost responsibility for
transmission upgrades; and (iii) a new weekly procurement
process that will allow both Entergy and NRG, as a purchaser of
power, to more efficiently utilize the transmission system. The
Southwest Power Pool has been selected as the ICT and began
performing its responsibilities in November 2006.
37
Entergys ICT proposal will impact the regions
existing operations by revising the manner in which transmission
service is obtained. Compounding the uncertainty caused by the
transition to the ICT, FERC has promulgated new regulations with
respect to its pro-forma open access transmission tariff,
referred to as Order No. 890, that may affect South
Centrals ability to transmit, and thus buy and sell, power.
West
Region
California has transitioned to a market structure where
load-serving entities, or LSEs, have an obligation to procure a
portion of their Resource Adequacy, or RA, capacity requirements
in transmission-constrained areas. All of NRGs California
assets operate in one or more of these constrained areas. This
local procurement obligation is leading to a phase-out of RMR
agreements with the CAISO, although CAISO retains the option of
renewing RMR agreements as necessary to maintain local
reliability. During 2008, only Cabrillo Power II LLC will
be operating under an RMR agreement, and only for ten of its
twelve peaking units. Cabrillo Power I LLCs Encina
facility terminated its RMR agreement with CAISO effective
December 31, 2007. Please see the Regional Business
Description for a discussion of the contracting activities
that have occurred on the units pursuant to the states RA
program.
There is no organized capacity market in California. As noted
above, the CPUC has imposed local capacity requirements on
load-serving entities but the application of this Resource
Adequacy Capacity Product obligation is uneven. On
December 20, 2007, FERC ordered the CAISO to extend its
Reliability Capacity Services Tariff, which was set to expire on
December 31, 2007, until the implementation of the
CAISOs Market Redesign and Technology Upgrade, or MRTU, or
an alternate backstop capacity procurement mechanism, and
initiated an investigation into the justness and reasonableness
of the existing capacity procurement process. It is unclear what
compensation will be provided to generators needed for
reliability purposes. In addition, several generators, including
El Segundo Power, LLC, filed a complaint at FERC on
November 30, 2007, similarly seeking just and reasonable
compensation for the value of capacity-related reliability
services.
On September 21, 2006, FERC conditionally accepted the MRTU
proposal which is currently scheduled to go into effect during
2008. Significant components of the MRTU include
(i) locational marginal pricing of energy; (ii) a more
effective congestion management system; (iii) a day-ahead
market; and (iv) an increase to the existing bid caps. NRG
considers these market reforms to be a positive development for
its assets in the region. Several parties have appealed
FERCs orders accepting the MRTU proposal, seeking to
materially modify the proposal
and/or delay
its implementation.
See also Item 15 Note 22, Regulatory
Matters, to the Consolidated Financial Statements for a
further discussion.
Environmental
Matters
NRG is subject to a wide range of environmental regulations
across a broad number of jurisdictions in the development,
ownership, construction and operation of domestic and
international projects. These laws and regulations generally
require that governmental permits and approvals be obtained
before construction and during operation of power plants.
Environmental laws have become increasingly stringent in recent
years, especially around the regulation of air emissions from
power generators. Such laws generally require regular capital
expenditures for power plant upgrades, modifications and the
installation of certain pollution control equipment. In general,
future laws and regulations are expected to require the addition
of emission controls or other environmental quality equipment or
the imposition of certain restrictions on the operations of the
Companys facilities. NRG expects that future liability
under, or compliance with, environmental requirements could have
a material effect on the Companys operations or
competitive position.
Federal
Environmental Initiatives
Air On May 18, 2005, the U.S
Environmental Protection Authority, or USEPA, published the
Clean Air Mercury Rule, or CAMR, to permanently cap and reduce
mercury emissions from coal-fired power plants. CAMR imposes
38
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. The rule was challenged by New
Jersey and ten other states. On February 8, 2008, the
U.S. Court of Appeals for the D.C. Circuit vacated
USEPAs rule delisting coal- and oil-fired electric
generating units from regulation under CAA §112 (the
Delisting Rule) and CAMR. More specifically, cap and
trade, allowing power plants to meet emission targets by buying
credits, was struck. The three-judge panel agreed with the
states that challenged the rule that the USEPA did not have the
authority to exempt power plants. Certain states in which NRG
operates coal plants, such as Delaware, Massachusetts and New
York adopted state implementation plans which did not permit
trading in lieu of the CAMR federal implementation plan. Texas
and Louisiana adopted the federal CAMR through the state
implementation plan, or SIP process. USEPA has already approved
the Louisiana SIP, but Texas has not yet been approved. At this
time, it is unclear how programs in these states will be
affected by the Courts actions.
On May 12, 2005, the USEPA published the Clean Air
Interstate Rule, or CAIR. This rule applies to 28 eastern states
and the District of Columbia, or D.C., and caps both
SO2
and
NOx
emissions from power plants in two phases; 2010 and 2015 for
SO2
and 2009 and 2015 for
NOx.
CAIR will apply to some of the Companys power plants in
New York, Massachusetts, Connecticut, Delaware, Louisiana,
Illinois, Pennsylvania, Maryland and Texas. On August 24,
2005, the USEPA published a proposed FIP to ensure that
generators affected by CAIR reduce emissions on schedule.
Furthermore: (i) on December 20, 2005, the USEPA signed
proposed revisions to address attainment for fine particulates,
or NAAQS for PM2.5, which will require affected states to
implement further rules to address
SO2
and
NOx
emissions; and (ii) on November 9, 2005, the USEPA proposed
the second phase of the 8-hour ozone NAAQS rule relating to
NOx
emissions. A number of environmental groups, states and industry
organizations challenged aspects of CAIR. The challenges were
consolidated into South Coast Air Quality Management
District v. EPA. In a ruling on December 22, 2006,
the D.C. Circuit overturned portions of USEPAs Phase I
implementation rule for the new 8-hour ozone standard.
Specifically, the court ruled that USEPA could revoke the 1-hour
standard as long as there was no backsliding from more stringent
control measures. This ruling could result in the imposition of
fees under Section 185 of the Clean Air Act, or the CAA, on
volatile organic carbon, or VOC, and
NOx
emissions in severe non-attainment areas. The fees could be as
high as $7,700/ton for emissions above 80% of baseline emissions
levels. Depending on the determination of baseline emission
levels, this could materially impact NRGs operations in
California, New York City and Texas.
The clean air visibility rule was published by the USEPA on
July 6, 2005. The rule requires regional haze controls by
targeting
SO2
and
NOx
emissions from sources including power plants of a certain
vintage through the installation of Best Available Retrofit
Technology, or BART, in certain cases. States were required to
develop implementation plans by December 2007. Most of the
Companys facilities will likely be able to satisfy their
obligations under the BART rule through compliance with the more
stringent CAIR. Accordingly, no material additional expenditures
are anticipated by the Company beyond those required by CAIR.
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 facilities over the years. As a result, the USEPA and several
states filed suits against a number of coal-fired power plants
in mid-western and southern states alleging violations of the
CAA New Source Review, or NSR, and Prevention of Significant
Deterioration, or PSD, requirements. The USEPA has issued an NOV
against NRGs Big Cajun II plant alleging that
NRGs predecessors had undertaken projects that triggered
requirements under the PSD program, including the installation
of emission controls. NRG has evaluated the claims and believes
they have no merit. Nonetheless, NRG has had discussions with
the USEPA about resolving the claims. See the South Central
region below for a further discussion.
There is a growing consensus in the U.S. and globally that
GHG emissions are a major cause of global warming. At the
national level and at various regional and state levels,
policies are under development to regulate GHG emissions,
thereby effectively putting a cost on such emissions in order to
create financial incentives to reduce them. In addition, earlier
this year, the U.S. Supreme Court found that
CO2,
the most common GHG, could be regulated as a pollutant and that
the USEPA should regulate
CO2
emissions from mobile sources. Since power plants, particularly
coal-fired plants, are a significant source of GHG emissions
both in the United States and globally, it is almost certain
that GHG regulatory actions will encompass power plants as well
as other GHG emitting stationary sources. In 2007, in the course
of producing approximately 80 million MWh of electricity,
39
NRGs power plants emitted 68 million tonnes of
CO2,
of which 61 million tonnes were emitted in the United
States, 3 million tonnes in Australia and 4 million
tonnes in Germany.
Federal, state or regional regulation of GHG emissions could
have a material impact on the Companys financial
performance. The actual impact on the Companys financial
performance will depend on a number of factors, including the
overall level of GHG reductions required under any such
regulations, the price and availability of offsets, and the
extent to which NRG would be entitled to receive GHG emissions
allowances without having to purchase them in an auction or on
the open market. For example, the U.S. Senate is currently
considering climate change legislation sponsored by Senators
Lieberman and Warner. If legislation with the same level of
allocations to existing generation resources and emissions
reductions as those contained in the current version of the
Lieberman-Warner legislation were enacted, NRG expects that the
legislation will have minimal impact on the Companys
financial performance through the next decade. Thereafter, under
such legislation as currently drafted, the impact on NRG would
depend on the Companys level of success in developing and
deploying low and no carbon technologies being pursued as part
of our RepoweringNRG and econrg initiatives.
Water In July 2004, the USEPA published
rules governing cooling water intake structures at existing
power facilities commonly referred to as the Phase II
316(b) rules. These rules specify 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. On January 25, 2007, the
2nd Circuit Court of Appeals made its decision in
the Riverkeeper vs. USEPA appeal over the Phase II
316(b) regulation. Riverkeeper prevailed on nearly all issues
and the decision essentially remands all of the important
aspects of the rule back to the USEPA for reconsideration and
restricted their ability to allow generators to substitute
mitigation for aquatic specie losses through habitat restoration
or other measures. In July 2007, the USEPA suspended the rule,
except for the requirement that permitting agencies develop best
professional judgment controls for existing facility cooling
water intake structures that reflect the best technology
available for minimizing adverse environmental impact. The
Phase II 316(b) rule affects a number of NRGs plants,
specifically those with once-through cooling systems. While NRG
has included the capital costs associated with the rule within
the Companys estimated environmental capital expenditures
based on good faith estimates, until consultations on the plans
have occurred with USEPA or its delegated state or regional
agencies, and the USEPA has concluded its reconsideration of the
Phase II 316(b) rules, it is not possible to estimate with
certainty the capital costs that will be required for compliance
with the Phase II 316(b) rules.
Nuclear Waste Under the U.S. Nuclear
Waste Policy Act of 1982, the federal government must remove and
ultimately dispose of spent nuclear fuel and high-level
radioactive waste from nuclear plants. Consistent with the Act,
owners of nuclear plants, including the owners of STP, entered
into contracts setting out the obligations of the owners and the
U.S. Department of Energy, or DOE, including the fees to be
paid by the owners for DOEs services. Since 1998, the DOE
has been in default on its obligations to begin removing spent
nuclear fuel and high-level radioactive waste from reactors. On
January 28, 2004, the owners of STP filed a breach of
contract suit against the DOE in order to protect against the
running of a statute of limitations.
Under the federal Low-Level Radioactive Waste Policy Act of
1980, as amended, the state of Texas is required to provide,
either on its own or jointly with other states in a compact, for
the disposal of all low-level radioactive waste generated within
the state. The state of Texas has agreed to a compact with the
state of Vermont for a disposal facility that would be located
in Texas. That compact was ratified by Congress and signed by
President Clinton in 1998. In 2003, the state of Texas enacted
legislation allowing a private entity to be licensed to accept
low-level radioactive waste for disposal. NRG intends to
continue to ship low-level waste material from STP offsite for
as long as an alternative disposal site is available. Should
existing off-site disposal become unavailable, the low-level
waste material will then be stored
on-site.
STPs
on-site
storage capacity is expected to be adequate for STPs needs
until other off-site facilities become available.
40
Regional
U.S. Environmental Initiatives
Northeast
Region
NRGs facilities in the eastern U.S. are subject to a
cap-and-trade
program governing
NOx
emissions during the ozone season, which typically begins May 1
and lasts through September 30. These rules essentially
require that one
NOx
allowance be held for each ton of
NOx
emitted. Each of NRGs facilities that are subject to these
rules have been allocated
NOx
emission allowances. NRG currently estimates that its total
NOx
emission allowances is sufficient to generally cover operations
at these facilities through 2009, reflecting the fact that
NOx
allowances are allocated on a three-year, look-back basis.
However, if at any point the Companys
NOx
emission allowances are insufficient for the anticipated
operation of each of these facilities, NRG must purchase
NOx
allowances. Any obligation to purchase a substantial number of
additional
NOx
emission allowances could have a material adverse effect on the
Companys results of operations, financial position and
cash flows.
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. The OTC
proposes to implement a regional plan containing emission
reduction targets for power plants that exceed those under CAIR.
The OTC targets and timelines are implemented on a state by
state basis. Current attention is focused on
NOx
emissions from units run primarily on High Energy Demand Days,
or HEDD, of which NRG owns facilities in Connecticut, Delaware
and New York. NRG continues to be actively engaged in the OTC
stakeholder process including providing technical expertise to
improve policy decision making. While it is not possible to
predict the outcome of this regional effort, to the extent that
the OTC is successful in implementing emission requirements that
are more stringent than existing regimes, NRG could be
materially impacted.
On December 20, 2005, several northeastern states entered
into a Memorandum of Understanding, or MOU, to create a RGGI to
establish a
cap-and-trade
GHG program for electric generators. The RGGI states are now in
the process of promulgating state regulations needed for
implementation. To date, all declared states have selected, with
the exception of specific set asides, to auction all of the
allowances. With state legislation and regulation in place, the
first regional auction of RGGI allowances needed by power
generators could be held as early as the summer of 2008.
Approximately 12 million tonnes of
CO2
were emitted from the Companys generating units in
Connecticut, Delaware, Maryland, Massachusetts and New York that
will likely be subject to RGGI in 2009. The impact of RGGI on
power prices (and thus on the Companys financial
performance), indirectly through generators seeking to pass
through the cost of their
CO2
emissions, cannot be predicted. However, NRG believes that due
to the absence of allowance allocations under RGGI, the direct
financial impact on NRG is likely to be negative as the Company
will incur costs in the course of securing the necessary
allowances and offsets at auction and in the market.
New England 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.
NRGs Somerset plant is subject to these regulations. NRG
has installed natural gas reburn technology to meet the
NOx
and
SO2
limits. On June 4, 2004, the Massachusetts Department of
Environmental Protection, or 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 as of January 1, 2008 and must
achieve a reduction in its mercury inlet-to-outlet concentration
of 85%. NRG plans to meet the requirements through the
management of its fuels and the use of early and off-site
reduction credits. Additionally, NRG has entered into an
agreement with MADEP to retire or repower the Somerset station
by the end of 2009. A permit for repowering the facility was
approved by the MADEP in 2007.
The Massachusetts carbon regulation 310 CMR 7.29 Emissions
Standards for Power Plants requires coal-fired generation
located within the state to comply with
CO2
emissions restrictions. A carbon emissions rate requirement will
apply in 2008. It is expected that Somerset will purchase
offsets to comply.
New York NRGs Huntley Power LLC,
Dunkirk Power LLC and Oswego Power LLC entered into a Consent
Order with the New York State Department of Environmental
Conservation, or NYSDEC, effective March 31, 2004,
regarding certain alleged opacity exceedances. The Order
stipulates penalties for future violations of opacity
requirements and compliance will be achieved with the
installation of baghouses to further control particulates at
41
the Huntley and Dunkirk facilities in 2008 and 2009,
respectively. In 2007, NRG accrued amounts payable to NYSDEC of
$0.3 million to cover the stipulated penalty payments.
Delaware In November 2006, the Delaware
Department of Natural Resources and Environmental Control, or
DNREC, promulgated Regulation No. 1146, or Reg 1146,
Electric Generating Unit Multi-Pollutant Regulation and
Section 111(d) of the State Plan for the Control of Mercury
Emissions from Coal-Fired Electric Steam Generating Units. These
regulations govern the control of
SO2,
NOx,
and mercury emissions from electric generating units. NRGs
plan to install controls at the Companys Indian River
facility, while on an accelerated basis, was unable to meet
certain deadlines, taking into account the time required, as a
practical matter, to design, install and commission the
necessary equipment. NRG filed a challenge to Reg 1146 with the
Environmental Appeals Board, or EAB, on December 6, 2006.
In addition, NRG also filed a protective appeal with the
Delaware Superior Court on December 29, 2006. This
challenge was settled when DNREC and NRG signed a Consent Order
on September 25, 2007, and filed that document with the
Delaware Superior Court thereby ending the case. Under this
agreement, continued operations at the Companys Indian
River Generating Station are conditioned upon installation of
controls on Units 1 and 2 by May 1, 2008, to reduce
NOx;
installation of controls on Units 1-4 by January 1, 2009 to
meet mercury requirements; mothball of Units 1 and 2 by
May 1, 2011, and May 1, 2010, respectively; and
installation of advanced controls on Units 3 and 4 in 2011 to
further reduce
NOx
and
SO2.
If the plant emits
NOx
in excess of 1,700 tons in any given ozone season, it will be
subject to a graduated scale of stipulated penalties, up to a
maximum $2,500/ton. The capital costs associated with this
settlement are included in the Companys estimated
environmental capital expenditures. In the absence of the
appropriate control technology installed at this facility, Units
3 and 4 totaling approximately 565 MW, could not operate
beyond December 31, 2011, per terms of the consent order.
West
Region
On September 27, 2006, Governor Arnold Schwarzenegger
signed Assembly Bill 32, or AB32, California Global Warming
Solutions Act of 2006. AB 32 requires the California Air
Resources Board, or CARB, to develop a GHG reduction program to
reduce emissions to 1990 levels by 2020, a reduction of
approximately 25%. The reductions are to be phased in beginning
2012 pursuant to regulations to be adopted by 2011. NRG does not
expect that implementation of AB32 in California will have a
significant adverse financial impact on the Company for a
variety of reasons, including the fact that NRGs
California portfolio consists of natural gas-fired peaking
facilities and will likely be able to pass through any costs of
purchasing allowances in power prices.
South
Central Region
On January 27, 2004, NRGs Louisiana Generating, LLC
and the Companys Big Cajun II plant received a
request under Section 114 of the Clean Air Act from the
United States Environmental Protection Agency, or USEPA, seeking
information primarily related to physical changes made at the
Big Cajun II plant, and subsequently received a notice of
violation, or NOV, on February 15, 2005, alleging that
NRGs predecessors had undertaken projects that triggered
requirements under the Prevention of Significant Deterioration
program, including the installation of emission controls. NRG
submitted multiple responses commencing February 27, 2004
and ending on October 20, 2004. On May 9, 2006, these
entities received from the Department of Justice, or DOJ, a
Notice of Deficiency related to their responses, to which NRG
responded on May 22, 2006. A document review was conducted
at NRGs Louisiana Generating, LLC offices by the DOJ
during the week of August 14, 2006. On December 8,
2006, the USEPA issued a supplemental NOV updating the original
February 15, 2005 NOV. Discussions with the USEPA are
ongoing and the Company cannot predict with certainty the
outcome of this matter.
Nuclear
Insurance
STPNOC purchases insurance coverage on behalf of NRG and the
other owners of STP. STP maintains property, decontamination
liability and nuclear hazard liability insurance coverage as
required by law and periodically reviews available limits and
coverage for additional protection. Currently, STP has a
$2.75 billion limit in property and decontamination
liability insurance coverage, which is above the legally
required minimum of $1.06 billion. The $2.75 billion
includes $1 billion excess blanket coverage that is shared
with two other nuclear power plants, namely Diablo Canyon and
D.C. Cook. The deductible for property damage is
$2.5 million. STP also
42
carries a primary accidental outage policy, which allows for six
weeks of indemnity at $3.5 million per week after a
17 week deductible is met. The $3.5 million weekly
indemnity would be allocated between the three owners of STP
according to their ownership percentages. NRG has purchased
additional accidental outage coverage for its 44% ownership
stake in STP. This policy provides coverage after the six week
indemnity period has been paid under the primary policy, and
will provide NRG $1.98 million weekly indemnity per unit
for 52 weeks and $1.58 million per week for the next
71 weeks. If both units at STP are affected by an outage
arising out of the same accident, weekly indemnity per unit is
limited to 80% of the single unit recovery. There is no coverage
for partial outages, and the outage must be the result of a
property damage caused by a sudden and fortuitous event.
The Price-Anderson Act, as amended through 2025 by the Energy
Policy Act of 2005, requires owners of nuclear power plants in
the U.S. to purchase the maximum amount of insurance
available (currently $300 million) in the insurance market
for liability claims that arise in the event of a nuclear
accident. In addition, the Act provides a secondary layer of
protection of up to $10.5 billion. Under this provision,
each licensed reactor company is obliged to contribute up to
approximately $101 million per unit per accident in
retrospective premiums for any single incident at any nuclear
power plant. Annual installments per reactor cannot exceed
$15 million. STP is a two reactor facility but NRGs
liability would be capped at 44% due to the Companys
ownership interest in STP. The Price-Anderson Act only covers
nuclear liability associated with an accident in the course of
operation of the nuclear reactor, transportation of nuclear fuel
to the reactor site, storage of nuclear fuel and waste at the
reactor site and the transportation of the spent nuclear fuel
and nuclear waste from the nuclear reactor. Any substantial
retrospective premiums imposed under the Price-Anderson Act or
losses not covered by insurance could have a materially adverse
effect on NRGs financial condition, the results of
operations and statement of cash flows.
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. NRG 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 a 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 the courts have interpreted liability under such
laws to be strict (without fault) and joint and several. Cleanup
obligations can often be triggered during the closure or
decommissioning of a facility, in addition to spills or other
occurrences during its operations.
In January 2006, NRGs Indian River Operations, Inc.
received a letter of informal notification from DNREC stating
that it may be a potentially responsible party with respect to a
historic captive landfill. On October 1, 2007, NRG filed a
Facility Evaluation with DNREC, through the Voluntary
Clean-up
Program to investigate the site. DNREC responded to the Facility
Evaluation on February 4, 2008 finding no further action is
required in relation to surface water and that a previously
planned shoreline stabilization project would adequately address
shore line erosion. The landfill itself will require a further
Remedial Investigation and Feasibility Study to determine the
type and scope of any additional work required. Until the
Remedial Investigation and Feasibility Study is completed, the
Company is unable to predict the impact of any required
remediation.
Further details regarding the Companys Domestic Site
Remediation obligations can be found in Item 15
Note 22, Regulatory Matters, to the Consolidated
Financial Statements.
International
Environmental Matters
Most of the foreign countries in which NRG owns 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 those in the U.S., are constantly evolving
and have a significant impact on international wholesale power
producers. In particular, NRGs international power
generation facilities will likely be affected by emissions
limitations and operational requirements imposed by the Kyoto
Protocol, an international
43
treaty related to greenhouse gas emissions enacted on
February 16, 2005, as well as country-based restrictions
pertaining to global climate change concerns.
NRG retains appropriate advisors in foreign countries and seeks
to design its 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 affect the Companys
international operations.
MIBRAG/Schkopau, Germany On June 22,
2007, Germany enacted the German National
CO2
Allocation Plan 2008 2012, in which MIBRAG was
granted
CO2
allocations that are less than the needs of its three generating
plants. The financial impact of this regulation on MIBRAGs
results is not yet clear and management of MIBRAG is
implementing a number of options to minimize any adverse impact.
MIBRAG has also submitted an application under the hardship
clause of the law to receive a higher allocation of the
CO2
allowances. The cost of compliance with the
CO2
regulation for NRGs Schkopau plant is expected to be
passed through to its off-taker of energy under its existing PPA.
Gladstone, Australia On December 3,
2007, Australia ratified the Kyoto Protocol that commits to
targets for GHG reductions. Australia also set a target to
reduce greenhouse gas emissions to 60% of 2000 levels by 2050.
The government is establishing a single national system for
reporting of GHG, abatement actions, and energy consumption and
generation starting July 1, 2008. This will underpin the
Australian Emissions Trading Scheme, currently in the early
stages of design that will be operational no later than 2010.
Available
Information
NRGs annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and amendments to those reports filed or furnished pursuant to
section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended, are available free of charge through the
Companys website, www.nrgenergy.com, as soon as
reasonably practicable after they are electronically filed with,
or furnished to, the Securities and Exchange Commission.
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Item 1A
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Risk
Factors Related to NRG Energy, Inc.
|
Many
of NRGs power generation facilities operate, wholly or
partially, without long-term power sale
agreements.
Many of NRGs facilities operate as merchant
facilities without long-term power sales agreements for some or
all of their generating capacity and output, and therefore are
exposed to market fluctuations. Without the benefit of long-term
power sales agreements for these assets, NRG cannot be sure that
it will be able to sell any or all of the power generated by
these facilities at commercially attractive rates or that these
facilities will be able to operate profitably. This could lead
to future impairments of the Companys property, plant and
equipment or to the closing of certain of its facilities,
resulting in economic losses and liabilities, which could have a
material adverse effect on the Companys results of
operations, financial condition or cash flows.
NRGs
financial performance may be impacted by changing natural gas
prices, significant and unpredictable price fluctuations in the
wholesale power markets and other market factors that are beyond
the Companys control.
A significant percentage of the Companys domestic revenues
are derived from baseload power plants that are fueled by coal.
In many of the competitive markets where NRG operates, the price
of power typically is set by marginal cost natural gas-fired
power plants that currently have substantially higher variable
costs than NRGs coal-fired baseload power plants. The
current pricing and cost environment allows the Companys
baseload coal generation assets to earn attractive operating
margins compared to plants fueled by natural gas. A decrease in
natural gas prices could result in a corresponding decrease in
the market price of power but would generally not affect the
cost of the coal that the plants use. This could significantly
reduce the operating margins of the Companys baseload
generation assets and materially and adversely impact its
financial performance.
In addition, because changes in power prices in the markets
where NRG operates are generally correlated with changes in
natural gas prices, NRGs hedging portfolio includes
natural gas derivative instruments to hedge power
44
prices for its baseload generation. If this correlation between
power prices and natural gas prices is not maintained and a
change in gas prices is not proportionately offset by a change
in power prices, the Companys natural gas hedges may not
fully cover this differential. This could have a material
adverse impact on the Companys cash flow and financial
position.
Market prices for power, generation capacity and ancillary
services tend to fluctuate substantially. 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, power prices are subject to significant volatility
from supply and demand imbalances, especially in the day-ahead
and spot markets. Long- and short-term power prices may also
fluctuate substantially due to other factors outside of the
Companys control, including:
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increases and decreases in generation capacity in the
Companys markets, including the addition of new supplies
of power from existing competitors or new market entrants as a
result of the development of new generation plants, expansion of
existing plants or additional transmission capacity;
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changes in power transmission or fuel transportation capacity
constraints or inefficiencies;
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electric supply disruptions, including plant outages and
transmission disruptions;
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heat rate risk;
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weather conditions;
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changes in the demand for power or in patterns of power usage,
including the potential development of demand-side management
tools and practices;
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development of new fuels and new technologies for the production
of power;
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regulations and actions of the ISOs; and
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federal and state power market and environmental regulation and
legislation.
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These factors have caused the Companys operating results
to fluctuate in the past and will continue to cause them to do
so in the future.
NRGs
costs, results of operations, financial condition and cash flows
could be adversely impacted by disruption of its fuel
supplies.
NRG relies on coal, oil and natural gas to fuel a majority of
its power generation facilities. Delivery of these fuels to the
facilities is dependent upon the continuing financial viability
of contractual counterparties as well as upon the infrastructure
(including rail lines, rail cars, barge facilities, roadways,
and natural gas pipelines) available to serve each generation
facility. As a result, the Company is subject to the risks of
disruptions or curtailments in the production of power at its
generation facilities if a counterparty fails to perform or if
there is a disruption in the fuel delivery infrastructure.
NRG has sold forward a substantial portion of its baseload power
in order to lock in long-term prices that it deemed to be
favorable at the time it entered into the forward sale
contracts. In order to hedge its obligations under these forward
power sales contracts, the Company has entered into long-term
and short-term contracts for the purchase and delivery of fuel.
Many of the forward power sales contracts do not allow the
Company to pass through changes in fuel costs or discharge the
power sale obligations in the case of a disruption in fuel
supply due to force majeure events or the default of a fuel
supplier or transporter. Disruptions in the Companys fuel
supplies may therefore require it to find alternative fuel
sources at higher costs, to find other sources of power to
deliver to counterparties at a higher cost, or to pay damages to
counterparties for failure to deliver power as contracted. Any
such event could have a material adverse effect on the
Companys financial performance.
NRG also buys significant quantities of fuel on a short-term or
spot market basis. Prices for all of the Companys fuels
fluctuate, sometimes rising or falling significantly over a
relatively short period of time. The price NRG 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 or
45
delivery costs. This may have a material adverse effect on the
Companys financial performance. Changes in market prices
for natural gas, coal and oil may result from the following:
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weather conditions;
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seasonality;
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demand for energy commodities and general economic conditions;
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disruption or other constraints or inefficiencies of
electricity, gas or coal transmission or transportation;
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additional generating capacity;
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availability and levels of storage and inventory for fuel stocks;
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natural gas, crude oil, refined products and coal production
levels;
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changes in market liquidity;
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federal, state and foreign governmental regulation and
legislation; and
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the creditworthiness and liquidity and willingness of fuel
suppliers/transporters to do business with the Company.
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NRGs plant operating characteristics and equipment,
particularly at its coal-fired plants, 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 the Company may not be able to
transport such coal to its facilities on a timely basis. In this
case, the Company may not be able to run the coal facility even
if it would be profitable. Operating a coal facility with
different quality coal can lead to emission or operating
problems. If the Company had sold forward the power from such a
coal facility, it 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 the Companys results of operations.
There
may be periods when NRG will not be able to meet its commitments
under forward sale obligations at a reasonable cost or at
all.
A substantial portion of the output from NRGs baseload
facilities has been sold forward under fixed price power sales
contracts through 2013, and the Company also sells forward the
output from its intermediate and peaking facilities when its
deems it commercially advantageous to do so. Because the
obligations under most of these agreements are not contingent on
a unit being available to generate power, NRG is generally
required to deliver power to the buyer, even in the event of a
plant outage, fuel supply disruption or a reduction in the
available capacity of the unit. To the extent that the Company
does not have sufficient lower cost capacity to meet its
commitments under its forward sale obligations, the Company
would be required to supply replacement power either by running
its other, higher cost power plants or by obtaining power from
third-party sources at market prices that could substantially
exceed the contract price. If NRG fails to deliver the
contracted power, it would be required to pay the difference
between the market price at the delivery point and the contract
price, and the amount of such payments could be substantial.
In the South Central region, NRG has long-term contracts with
rural cooperatives that require it to serve all of the
cooperatives requirements at prices that generally reflect
the costs of coal-fired generation. At times, the output from
NRGs coal-fired Big Cajun II facility has been and
will continue to be inadequate to serve these obligations, and
when that happens the Company has typically purchased power from
other power producers, often at a loss. NRGs financial
returns from its South Central region are likely to deteriorate
over time as the rural cooperatives grow their customer base,
unless the Company is able to amend or renegotiate its contracts
with the cooperatives or add generating capacity.
46
NRGs
trading operations and the use of hedging agreements could
result in financial losses that negatively impact its results of
operations.
The Company typically enters into hedging agreements, including
contracts to purchase or sell commodities at future dates and at
fixed prices, in order to manage the commodity price risks
inherent in its power generation operations. These activities,
although intended to mitigate price volatility, expose the
Company to other risks. When the Company sells power forward, it
gives up the opportunity to sell power at higher prices in the
future, which not only may result in lost opportunity costs but
also may require the Company to post significant amounts of cash
collateral or other credit support to its counterparties.
Further, if the values of the financial contracts change in a
manner that the Company does not anticipate, or if a
counterparty fails to perform under a contract, it could harm
the Companys business, operating results or financial
position.
NRG does not typically hedge the entire exposure of its
operations against commodity price volatility. To the extent it
does not hedge against commodity price volatility, the
Companys results of operations and financial position may
be improved or diminished based upon movement in commodity
prices.
NRG may engage in trading activities, including the trading of
power, fuel and emissions allowances that are not directly
related to the operation of the Companys generation
facilities or the management of related risks. These trading
activities take place in volatile markets and some of these
trades could be characterized as speculative. The Company would
expect to settle these trades financially rather than through
the production of power or the delivery of fuel. This trading
activity may expose the Company to the risk of significant
financial losses which could have a material adverse effect on
its business and financial condition.
NRG
may not have sufficient liquidity to hedge market risks
effectively.
The Company is exposed to market risks through its power
marketing business, which involves the sale of energy, capacity
and related products and the purchase and sale of fuel,
transmission services and emission allowances. These market
risks include, among other risks, volatility arising from
location and timing differences that may be associated with
buying and transporting fuel, converting fuel into energy and
delivering the energy to a buyer.
NRG undertakes these marketing activities through agreements
with various counterparties. Many of the Companys
agreements with counterparties include provisions that require
the Company to provide guarantees, offset of netting
arrangements, letters of credit, a second lien on assets
and/or cash
collateral to protect the counterparties against the risk of the
Companys default or insolvency. The amount of such credit
support that must be provided typically is based on the
difference between the price of the commodity in a given
contract and the market price of the commodity. Significant
movements in market prices can result in the Company being
required to provide cash collateral and letters of credit in
very large amounts. The effectiveness of the Companys
strategy may be dependent on the amount of collateral available
to enter into or maintain these contracts, and liquidity
requirements may be greater than the Company anticipates or will
be able to meet. Without a sufficient amount of working capital
to post as collateral in support of performance guarantees or as
a cash margin, the Company may not be able to manage price
volatility effectively or to implement its strategy. An increase
in the amount of letters of credit or cash collateral required
to be provided to the Companys counterparties may
negatively affect the Companys liquidity and financial
condition.
Further, if any of NRGs facilities experience unplanned
outages, the Company may be required to procure replacement
power at spot market prices in order to fulfill contractual
commitments. Without adequate liquidity to meet margin and
collateral requirements, the Company may be exposed to
significant losses, may miss significant opportunities, and may
have increased exposure to the volatility of spot markets.
The
accounting for NRGs hedging activities may increase the
volatility in the Companys quarterly and annual financial
results.
NRG engages in commodity-related marketing and price-risk
management activities in order to financially hedge its exposure
to market risk with respect to electricity sales from its
generation assets, fuel utilized by those assets, and emission
allowances.
47
NRG generally attempts to balance its 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 133, Accounting for Derivative Instruments and
Hedging Activities, as amended, or SFAS 133, which
requires the Company 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 cash
flow hedge accounting treatment. Whether a derivative qualifies
for cash flow hedge accounting treatment depends upon it meeting
specific criteria used to determine if the cash flow hedge is
and will remain appropriate for the term of the derivative.
Economic hedges will not necessarily qualify for cash flow hedge
accounting treatment. As a result, the Company may be unable to
accurately predict the impact that its risk management decisions
may have on its quarterly and annual operating results.
Competition
in wholesale power markets may have a material adverse effect on
NRGs results of operations, cash flows and the market
value of its assets.
NRG has numerous competitors in all aspects of its business, and
additional competitors may enter the industry. Because many of
the Companys facilities are old, newer plants owned by the
Companys competitors are often more efficient than
NRGs aging plants, which may put some of these plants at a
competitive disadvantage to the extent the Companys
competitors are able to consume the same or less fuel as the
Companys plants consume. Over time, the Companys
plants may be squeezed out of their markets, or may be unable to
compete with these more efficient plants.
In NRGs power marketing and commercial operations, it
competes on the basis of its relative skills, financial position
and access to capital 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
compete successfully, the Company seeks 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.
Other companies with which NRG competes with may have greater
liquidity, greater access to credit and other financial
resources, lower cost structures, more effective risk management
policies and procedures, greater ability to incur losses,
longer-standing relationships with customers, greater potential
for profitability from ancillary services or greater flexibility
in the timing of their sale of generation capacity and ancillary
services than NRG does.
NRGs competitors may be able to respond more quickly to
new laws or regulations or emerging technologies, or to devote
greater resources to the construction, expansion or
refurbishment of their power generation facilities than NRG can.
In addition, current and potential competitors may make
strategic acquisitions or establish cooperative relationships
among themselves or with third parties. Accordingly, it is
possible that new competitors or alliances among current and new
competitors may emerge and rapidly gain significant market
share. There can be no assurance that NRG will be able to
compete successfully against current and future competitors, and
any failure to do so would have a material adverse effect on the
Companys business, financial condition, results of
operations and cash flow.
Operation
of power generation facilities involves significant risks and
hazards customary to the power industry that could have a
material adverse effect on NRGs revenues and results of
operations. NRG may not have adequate insurance to cover these
risks and hazards.
The ongoing operation of NRGs facilities involves risks
that include the breakdown or failure of equipment or processes,
performance below expected levels of output or efficiency and
the inability to transport the Companys product to its
customers in an efficient manner due to a lack of transmission
capacity. Unplanned outages of generating units, including
extensions of scheduled outages due to mechanical failures or
other problems occur from time to time and are an inherent risk
of the Companys business. Unplanned outages typically
increase the Companys operation and maintenance expenses
and may reduce the Companys revenues as a result of
selling fewer MWh or require NRG to incur significant costs as a
result of running one of its higher cost units or obtaining
replacement power from third parties in the open market to
satisfy the Companys forward power sales obligations.
48
NRGs inability to operate the Companys plants
efficiently, manage capital expenditures and costs, and generate
earnings and cash flow from the Companys asset-based
businesses could have a material adverse effect on the
Companys results of operations, financial condition or
cash flows. While NRG maintains insurance, obtains warranties
from vendors and obligates contractors to meet certain
performance levels, the proceeds of such insurance, warranties
or performance guarantees may not be adequate to cover the
Companys lost revenues, increased expenses or liquidated
damages payments should the Company experience equipment
breakdown or non-performance by contractors or vendors.
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,
other hazards, such as fire, explosion, structural collapse and
machinery failure are inherent risks in the Companys
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 NRG 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. NRG maintains an amount of insurance protection that
it considers adequate, but the Company cannot provide any
assurance that its insurance will be sufficient or effective
under all circumstances and against all hazards or liabilities
to which it may be subject. A successful claim for which the
Company is not fully insured could hurt its financial results
and materially harm NRGs financial condition. Further, due
to rising insurance costs and changes in the insurance markets,
NRG cannot provide any assurance that its insurance coverage
will continue to be available at all or at rates or on terms
similar to those presently available. Any losses not covered by
insurance could have a material adverse effect on the
Companys financial condition, results of operations or
cash flows.
Maintenance,
expansion and refurbishment of power generation facilities
involve significant risks that could result in unplanned power
outages or reduced output and could have a material adverse
effect on NRGs results of operations, cash flow and
financial condition.
Many of NRGs facilities are old and 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.
NRG cannot be certain of the level of capital expenditures that
will be required due to changing environmental and safety laws
and regulations (including changes in the interpretation or
enforcement thereof), needed facility repairs and unexpected
events (such as natural disasters or terrorist attacks). The
unexpected requirement of large capital expenditures could have
a material adverse effect on the Companys liquidity and
financial condition.
If NRG makes any major modifications to its power generation
facilities, the Company may be required to install the best
available control technology or to achieve the lowest achievable
emissions rates, as such terms are defined under the new source
review provisions of the federal Clean Air Act. Any such
modifications would likely result in substantial additional
capital expenditures.
The
Company may incur additional costs or delays in the construction
and operation of new plants, improvements to existing plants, or
the implementation of environmental control equipment at
existing plants and may not be able to recover their investment
or complete the project.
The Company is in the process of constructing new generation
facilities, improving its existing facilities and adding
environmental controls to its existing facilities. The
construction, expansion, modification and refurbishment of power
generation facilities involve many additional risks, including:
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delays in obtaining necessary permits and licenses;
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environmental remediation of soil or groundwater at contaminated
sites;
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interruptions to dispatch at the Companys facilities;
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supply interruptions;
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49
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work stoppages;
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labor disputes;
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weather interferences;
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unforeseen engineering, environmental and geological problems;
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unanticipated cost overruns;
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exchange rate risks; and
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performance risks.
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Any of these risks could cause NRGs financial returns on
new investments to be lower than expected, or could cause the
Company to operate below expected capacity or availability
levels, which could result in lost revenues, increased expenses,
higher maintenance costs and penalties. Insurance is maintained
to protect against these risks, warranties are generally
obtained for limited periods relating to the construction of
each project and its equipment in varying degrees, and
contractors and equipment suppliers are obligated to meet
certain performance levels. The insurance, warranties or
performance guarantees, however, may not be adequate to cover
increased expenses. As a result, a project may cost more than
projected and may be unable to fund principal and interest
payments under its construction financing obligations, if any. A
default under such a financing obligation could result in losing
the Companys interest in a power generation facility.
If the Company is unable to complete the development or
construction of a facility or environmental control, or decides
to delay or cancel such project, it may not be able to recover
its investment in that facility or environmental control.
Furthermore, if construction projects are not completed
according to specification, the Company may incur liabilities
and suffer reduced plant efficiency, higher operating costs and
reduced net income.
The
Companys RepoweringNRG program is subject to financing
risks that could adversely impact NRGs financial
performance.
While NRG currently intends to develop and finance the more
capital intensive, solid fuel-fired projects included in the
RepoweringNRG program on a non-recourse or limited
recourse basis through separate project financed entities, and
intends to seek additional investments in most of these projects
from third parties, NRG anticipates that it will need to make
significant equity investments in these projects. NRG may also
decide to develop and finance some of the projects, such as
smaller gas-fired and renewable projects, using corporate
financial resources rather than non-recourse debt, which could
subject NRG to significant capital expenditure requirements and
to risks inherent in the development and construction of new
generation facilities. In addition to providing some or all of
the equity required to develop and build the proposed projects,
NRGs ability to finance these projects on a non-recourse
basis is contingent upon a number of factors, including the
terms of the EPC contracts, construction costs, PPAs and fuel
procurement contracts, capital markets conditions, the
availability of tax credits and other government incentives for
certain new technologies. To the extent NRG is not able to
obtain non-recourse financing for any project or should the
credit rating agencies attribute a material amount of the
project finance debt to NRGs credit, the financing of the
RepoweringNRG projects could have a negative impact on
the credit ratings of NRG.
As part of the RepoweringNRG program, NRG may also choose
to undertake the repowering, refurbishment or upgrade of current
facilities based on the Companys assessment that such
activity will provide adequate financial returns. Such projects
often require several years of development and capital
expenditures before commencement of commercial operations, and
key assumptions underpinning a decision to make such an
investment may prove incorrect, including assumptions regarding
construction costs, timing, available financing and future fuel
and power prices.
50
Supplier
and/or customer concentration at certain of NRGs
facilities may expose the Company to significant financial
credit or performance risks.
NRG often relies on a single contracted supplier or a small
number of suppliers for the provision of fuel, transportation of
fuel and other services required for the operation of certain of
its facilities. If these suppliers cannot perform, the Company
utilizes the marketplace to provide these services. There can be
no assurance that the marketplace can provide these services as,
when and where required.
At times, NRG relies 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 account
for a substantial percentage of the anticipated revenue from a
given facility. The Company has also hedged a portion of its
exposure to power price fluctuations through forward fixed price
power sales and natural gas price swap agreements.
Counterparties to these agreements may breach or may be unable
to perform their obligations. NRG may not be able to enter into
replacement agreements on terms as favorable as its existing
agreements, or at all. If the Company was unable to enter into
replacement PPAs, the Company would sell its plants
power at market prices. If the Company is unable to enter into
replacement fuel or fuel transportation purchase agreements, NRG
would seek to purchase the Companys fuel requirements at
market prices, exposing the Company to market price volatility
and the risk that fuel and transportation may not be available
during certain periods at any price.
The failure of any supplier or customer to fulfill its
contractual obligations to NRG could have a material adverse
effect on the Companys financial results. Consequently,
the financial performance of the Companys facilities is
dependent on the credit quality of, and continued performance
by, suppliers and customers.
NRG
relies on power transmission facilities that the Company does
not own or control and that are subject to transmission
constraints within a number of the Companys core regions.
If these facilities fail to provide NRG with adequate
transmission capacity, the Company may be restricted in its
ability to deliver wholesale electric power to its customers and
the Company may either incur additional costs or forego
revenues. Conversely, improvements to certain transmission
systems could also reduce revenues.
NRG depends on transmission facilities owned and operated by
others to deliver the wholesale power it sells from the
Companys power generation plants to its customers. If
transmission is disrupted, or if the transmission capacity
infrastructure is inadequate, NRGs ability to sell and
deliver wholesale power may be adversely impacted. If a
regions power transmission infrastructure is inadequate,
the Companys recovery of wholesale costs and profits may
be limited. If restrictive transmission price regulation is
imposed, the transmission companies may not have sufficient
incentive to invest in expansion of transmission infrastructure.
The Company cannot also predict whether transmission facilities
will be expanded in specific markets to accommodate competitive
access to those markets.
In addition, in certain of the markets in which NRG operates,
energy transmission congestion may occur and the Company may be
deemed responsible for congestion costs if it schedules delivery
of power between congestion zones during times when congestion
occurs between the zones. If NRG were liable for such congestion
costs, the Companys financial results could be adversely
affected.
In the California ISO, New York ISO and New England ISO markets,
the Company has a significant amount of generation located in
load pockets, making that generation valuable, particularly with
respect to maintaining the reliability of the transmission grid.
Expansion of transmission systems to reduce or eliminate these
load pockets could negatively impact the value or profitability
of our existing facilities in these areas.
Because
NRG owns less than a majority of some of its project
investments, the Company cannot exercise complete control over
their operations.
NRG has limited control over the operation of some project
investments and joint ventures because the Companys
investments are in projects where it beneficially owns less than
a majority of the ownership interests. NRG seeks to exert a
degree of influence with respect to the management and operation
of projects in which it owns 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, the
Company may not always succeed in such negotiations. NRG may be
dependent on its co-venturers to operate such projects. The
51
Companys 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 NRG to
receive distributions of funds from projects or to transfer the
Companys interest in projects.
Future
acquisition activities may have adverse effects.
NRG may seek to acquire additional companies or assets in the
Companys industry. The acquisition of power generation
companies and assets is subject to substantial risks, including
the failure to identify material problems during due diligence,
the risk of over-paying for assets and the inability to arrange
financing for an acquisition as may be required or desired.
Further, the integration and consolidation of acquisitions
requires substantial human, financial and other resources and,
ultimately, the Companys acquisitions may not be
successfully integrated. There can be no assurances that any
future acquisitions will perform as expected or that the returns
from such acquisitions will support the indebtedness incurred to
acquire them or the capital expenditures needed to develop them.
NRGs
business is subject to substantial governmental regulation and
may be adversely affected by legislative or regulatory changes,
as well as liability under, or any future inability to comply
with, existing or future regulations or
requirements.
NRGs business is subject to extensive foreign, and
U.S. federal, state and local laws and regulation.
Compliance with the requirements under these various regulatory
regimes may cause the Company to incur significant additional
costs, and failure to comply with such requirements could result
in the shutdown of the non-complying facility, the imposition of
liens, fines,
and/or civil
or criminal liability.
Public utilities under the Federal Power Act, or FPA, are
required to obtain FERC acceptance of their rate schedules for
wholesale sales of electricity. All of NRGs non-qualifying
facility generating companies and power marketing affiliates in
the United States make sales of electricity in interstate
commerce and are public utilities for purposes of the FPA. FERC
has granted each of NRGs generating and power marketing
companies the authority to sell electricity at market-based
rates. The FERCs orders that grant NRGs generating
and power marketing companies market-based rate authority
reserve the right to revoke or revise that authority if FERC
subsequently determines that NRG can exercise market power in
transmission or generation, create barriers to entry, or engage
in abusive affiliate transactions. In addition, NRGs
market-based sales are subject to certain market behavior rules,
and if any of NRGs generating and power marketing
companies were deemed to have violated one of those rules, they
are subject to potential disgorgement of profits associated with
the violation
and/or
suspension or revocation of their market-based rate authority.
If NRGs generating and power marketing companies were to
lose their market-based rate authority, such companies would be
required to obtain FERCs acceptance of a cost-of-service
rate schedule and could become subject to the accounting,
record-keeping, and reporting requirements that are imposed on
utilities with cost-based rate schedules. This could have an
adverse effect on the rates NRG charges for power from its
facilities.
NRG is also affected by legislative and regulatory changes, as
well as changes to market design, market rules, tariffs, cost
allocations, and bidding rules that occur in the existing ISOs.
The ISOs that oversee most of the wholesale power markets
impose, and in the future may continue to impose, mitigation,
including price limitations, offer caps, and other mechanisms to
address some of the volatility and the potential exercise of
market power in these markets. These types of price limitations
and other regulatory mechanisms may have an adverse effect on
the profitability of NRGs generation facilities that sell
energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power
industry has undergone substantial changes over the past several
years as a result of restructuring initiatives at both the state
and federal levels. These changes are ongoing and the Company
cannot predict the future design of the wholesale power markets
or the ultimate effect that the changing regulatory environment
will have on NRGs business. In addition, in some of these
markets, interested parties have proposed material market design
changes, including the elimination of a single clearing price
mechanism, as well as proposals to re-regulate the markets or
require divestiture by generating companies to reduce their
market share. Other proposals to re-regulate may be made and
legislative or other attention to the electric power market
restructuring process may delay or reverse the deregulation
process. If competitive restructuring of
52
the electric power markets is reversed, discontinued, or
delayed, our business prospects and financial results could be
negatively impacted.
NRGs
ownership interest in a nuclear power facility subjects the
Company to regulations, costs and liabilities uniquely
associated with these types of facilities.
Under the Atomic Energy Act of 1954, as amended, or AEA,
operation of STP, of which NRG indirectly owns a 44.0% interest,
is subject to regulation by the Nuclear Regulatory Commission,
or NRC. Such regulation includes licensing, inspection,
enforcement, testing, evaluation and modification of all aspects
of nuclear reactor power plant design and operation,
environmental and safety performance, technical and financial
qualifications, decommissioning funding assurance and transfer
and foreign ownership restrictions. NRGs 44% share of the
output of STP represents approximately 1,175 MW of
generation capacity.
There are unique risks to owning and operating a nuclear power
facility. These include liabilities related to the handling,
treatment, storage, disposal, transport, release and use of
radioactive materials, particularly with respect to spent
nuclear fuel, and uncertainties regarding the ultimate, and
potential exposure to, technical and financial risks associated
with modifying or decommissioning a nuclear facility. The NRC
could require the shutdown of the plant for safety reasons or
refuse to permit restart of the unit after unplanned or planned
outages. New or amended NRC safety and regulatory requirements
may give rise to additional operation and maintenance costs and
capital expenditures. STP may be obligated to continue storing
spent nuclear fuel if the Department of Energy continues to fail
to meet its contractual obligations to STP made pursuant to the
U.S. Nuclear Waste Policy Act of 1982 to accept and dispose
of STPs spent nuclear fuel. See also
Environmental Matters U.S. Federal
Environmental Initiatives Nuclear Waste in
Item 1. Costs associated with these risks could be
substantial and have a material adverse effect on NRGs
results of operations, financial condition or cash flow. In
addition, to the extent that all or a part of STP is required by
the NRC to permanently or temporarily shut down or modify its
operations, or is otherwise subject to a forced outage, NRG may
incur additional costs to the extent it is obligated to provide
power from more expensive alternative sources either
NRGs own plants, third party generators or the
ERCOT to cover the Companys then existing
forward sale obligations. Such shutdown or modification could
also lead to substantial costs related to the storage and
disposal of radioactive materials and spent nuclear fuel.
NRG and the other owners of STP maintain nuclear property and
nuclear liability insurance coverage as required by law. The
Price-Anderson Act, as amended by the Energy Policy Act of 2005,
requires owners of nuclear power plants in the United States to
be collectively responsible for retrospective secondary
insurance premiums for liability to the public arising from
nuclear incidents resulting in claims in excess of the required
primary insurance coverage amount of $300 million per
reactor. The Price-Anderson Act only covers nuclear liability
associated with any accident in the course of operation of the
nuclear reactor, transportation of nuclear fuel to the reactor
site, in the storage of nuclear fuel and waste at the reactor
site and the transportation of the spent nuclear fuel and
nuclear waste from the nuclear reactor. All other non-nuclear
liabilities are not covered. Any substantial retrospective
premiums imposed under the Price-Anderson Act or losses not
covered by insurance could have a material adverse effect on
NRGs financial condition, results of operations or cash
flows.
NRG is
subject to environmental laws and regulations that impose
extensive and increasingly stringent requirements on the
Companys ongoing operations, as well as potentially
substantial liabilities arising out of environmental
contamination. These environmental requirements and liabilities
could adversely impact NRGs results of operations,
financial condition and cash flows.
NRGs business is subject to the environmental laws and
regulations of foreign, federal, state and local authorities.
The Company must comply with numerous environmental laws and
regulations and obtain numerous governmental permits and
approvals to operate the Companys plants. Should NRG fail
to comply with any environmental requirements that apply to its
operations, the Company could be subject to administrative,
civil and/or
criminal liability and fines, and regulatory agencies could take
other actions seeking to curtail the Companys operations.
In addition, when new requirements take effect or when existing
environmental requirements are revised, reinterpreted or subject
to changing enforcement policies, NRGs business, results
of operations, financial condition and cash flows could be
adversely affected.
53
Environmental laws and regulations have generally become more
stringent over time, and the Company expects this trend to
continue. Future federally imposed changes in the National
Ambient Air Quality Standard for ozone could result in
additional reduction of
NOx
limits or reduced compliance flexibility for power generating
units. Challenges to CAMR, if successful, could result in a unit
by unit command and control approach to mercury resulting in
additional controls to NRG coal facilities in Louisiana and
Texas.
Furthermore, certain environmental laws impose strict, joint and
several liability for costs required to clean up and restore
sites where hazardous substances have been disposed or otherwise
released. The Company is generally responsible for all
liabilities associated with the environmental condition of its
power generation plants, including any soil or groundwater
contamination that may be present, regardless of when the
liabilities arose and whether the liabilities are known or
unknown, or arose from the activities of predecessors or third
parties.
Policies
at the national, regional and state levels to regulate GHG
emissions could adversely impact NRGs result of
operations, financial condition and cash flows.
There is a growing consensus in the U.S. and globally that
GHG emissions are a major cause of global warming. At the
national level and at various regional and state levels,
policies are under development to regulate GHG emissions,
thereby effectively putting a cost on such emissions in order to
create financial incentive to reduce them. Earlier this year,
the U.S. Supreme Court found that
CO2,
the most common GHG, could be regulated as a pollutant and that
the USEPA should regulate
CO2
emissions from mobile sources. Since power plants, particularly
coal-fired plants, are a significant source of GHG emissions
both in the United States and globally, it is almost certain
that GHG regulatory actions will encompass power plants as well
as other GHG emitting stationary sources. In 2007, in the course
of producing approximately 80 million MWh of electricity,
NRGs power plants emitted 68 million tonnes of
CO2,
of which 61 million tonnes were emitted in the United
States, 3 million tonnes in Australia and 4 million
tonnes in Germany.
Federal, state or regional regulation of GHG emissions could
have a material impact on the Companys financial
performance. The actual impact on the Companys financial
performance will depend on a number of factors, including the
overall level of GHG reductions required under any such
regulations, the price and availability of offsets, and the
extent to which NRG would be entitled to receive GHG emissions
allowances without having to purchase them in an auction or on
the open market.
State and regional initiatives such as the RGGI, in the
Northeast, and the Western Climate Initiative, or WCI, are
developing market based programs to counteract climate change.
The RGGI states are in the process of promulgating state
regulations needed for implementation with six of the ten states
issuing drafts for comment. With state legislation and
regulation in place, the first regional auction of RGGI
allowances needed by power generators could be held as early as
the summer of 2008.
However, of the approximately 61 million tonnes of
CO2
emitted by NRG in the United States in 2007, approximately
12 million tonnes were emitted from the Companys
generating units in Connecticut, Delaware, Maryland,
Massachusetts and New York that will likely be subject to RGGI
in 2009. The impact of RGGI on power prices (and thus on the
Companys financial performance), indirectly through
generators seeking to pass through the cost of their
CO2
emissions, cannot be predicted. However, NRG believes that due
to the absence of allowance allocations under RGGI, the direct
financial impact on NRG is likely to be negative as the Company
will incur costs in the course of securing the necessary
allowances and offsets at auction and in the market.
NRGs
business, financial condition and results of operations could be
adversely impacted by strikes or work stoppages by its unionized
employees or inability to replace employees as they
retire.
As of December 31, 2007, approximately 66% of NRGs
employees at its U.S. generation plants were covered by
collective bargaining agreements. In the event that the
Companys union employees strike, participate in a work
stoppage or slowdown or engage in other forms of labor strife or
disruption, NRG would be responsible for procuring replacement
labor or the Company could experience reduced power generation
or outages. NRGs ability to procure such labor is
uncertain. Strikes, work stoppages or the inability to negotiate
future collective bargaining agreements on favorable terms could
have a material adverse effect on the Companys business,
financial condition,
54
results of operations and cash flow. In addition, a number of
our employees at our plants are close to retirement. Our
inability to replace those workers could create potential
knowledge and expertise gaps as those workers retire.
Changes
in technology may impair the value of NRGs power
plants.
Research and development activities are ongoing to provide
alternative and more efficient technologies to produce power,
including fuel cells, clean coal and coal gasification,
micro-turbines, photovoltaic (solar) cells and improvements in
traditional technologies and equipment, such as more efficient
gas turbines. Advances in these or other technologies could
reduce the costs of power production to a level below what the
Company has currently forecasted, which could adversely affect
its cash flow, results of operations or competitive position.
Acts
of terrorism could have a material adverse effect on NRGs
financial condition, results of operations and cash
flows.
NRGs 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 the facilities 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
the Companys financial condition, results of operations
and cash flow.
NRGs
international investments are subject to additional risks that
its U.S. investments do not have.
NRG has investments in power projects in Australia, Germany and
Brazil. International investments are subject to risks and
uncertainties relating to the political, social and economic
structures of the countries in which it invests. The likelihood
of such occurances and their overall effect upon NRG may vary
greatly from country to country and are not predictable. Risks
specifically related to our investments in international
projects may include:
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fluctuations in currency valuation;
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currency inconvertibility;
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expropriation and confiscatory taxation;
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restrictions on the repatriation of capital; and
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approval requirements and governmental policies limiting returns
to foreign investors.
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NRGs
level of indebtedness could adversely affect its ability to
raise additional capital to fund its operations, or return
capital to stockholders. It could also expose it to the risk of
increased interest rates and limit its ability to react to
changes in the economy or its industry.
NRGs substantial debt could have important consequences,
including:
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increasing NRGs vulnerability to general economic and
industry conditions;
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requiring a substantial portion of NRGs cash flow from
operations to be dedicated to the payment of principal and
interest on its indebtedness, therefore reducing NRGs
ability to pay dividends to holders of its preferred or common
stock or to use its cash flow to fund its operations, capital
expenditures and future business opportunities;
|
|
|
|
limiting NRGs ability to enter into long-term power sales
or fuel purchases which require credit support;
|
|
|
|
exposing NRG to the risk of increased interest rates because
certain of its borrowings, including borrowings under its new
senior secured credit facility are at variable rates of interest;
|
|
|
|
limiting NRGs ability to obtain additional financing for
working capital including collateral postings, capital
expenditures, debt service requirements, acquisitions and
general corporate or other purposes; and
|
55
|
|
|
|
|
limiting NRGs ability to adjust to changing market
conditions and placing it at a competitive disadvantage compared
to its competitors who have less debt.
|
The indentures for NRGs notes and senior secured credit
facility contain financial and other restrictive covenants that
may limit the Companys ability to return capital to
stockholders or otherwise engage in activities that may be in
its long-term best interests. NRGs failure to comply with
those covenants could result in an event of default which, if
not cured or waived, could result in the acceleration of all of
the Companys indebtedness.
In addition, NRGs ability to arrange financing, either at
the corporate level or at a non-recourse project-level
subsidiary, and the costs of such capital, are dependent on
numerous factors, including:
|
|
|
|
|
general economic and capital market conditions;
|
|
|
|
credit availability from banks and other financial institutions;
|
|
|
|
investor confidence in NRG, its partners and the regional
wholesale power markets;
|
|
|
|
NRGs financial performance and the financial performance
of its subsidiaries;
|
|
|
|
NRGs level of indebtedness and compliance with covenants
in debt agreements;
|
|
|
|
maintenance of acceptable credit ratings;
|
|
|
|
cash flow; and
|
|
|
|
provisions of tax and securities laws that may impact raising
capital.
|
NRG 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 its
business and operations.
Goodwill
and/or other intangible assets not subject to amortization that
NRG has recorded in connection with its acquisitions are subject
to mandatory annual impairment evaluations and as a result, the
Company could be required to write off some or all of this
goodwill and other intangible assets, which may adversely affect
the Companys financial condition and results of
operations.
In accordance with Financial Accounting Standard No. 142,
Goodwill and Other Intangible Assets, goodwill is not
amortized but is reviewed annually or more frequently for
impairment and other intangibles are also reviewed at least
annually or more frequently, if certain conditions exist, and
may be amortized. Any reduction in or impairment of the value of
goodwill or other intangible assets will result in a charge
against earnings which could materially adversely affect
NRGs reported results of operations and financial position
in future periods.
Because
the historical financial information may not be representative
of the results of operation as a combined company or capital
structure after the Acquisition, and NRGs and Texas Genco
LLCs historical financial information are not comparable
to their current financial information, you have limited
financial information on which to evaluate the combined company,
NRG and Texas Genco LLC.
Texas Genco LLC did not exist prior to July 19, 2004, and
Texas Genco LLC and its subsidiaries had no operations and no
material activities until December 15, 2004 when Texas
Genco LLC acquired its gas- and coal-fired assets. Consequently,
Texas Genco LLCs historical financial information is not
comparable to the Texas regions current financial
information.
NRG and Texas Genco LLC had been operating as separate companies
prior to February 2, 2006. NRG and Texas Genco LLC had no
prior history as a combined company, nor have they been
previously managed on a combined basis. The historical financial
statements may not reflect what the combined companys
results of operations, financial position and cash flows would
have been had both companies operated on a combined basis and
may not be indicative of what the combined companys
results of operations, financial position and cash flows will be
in the future.
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 that may cause
56
NRG Energy, Inc.s 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 statements. These factors,
risks and uncertainties include the factors described under
Risks Related to NRG in Item 1A of NRGs 2007 Annual
Report on
Form 10-K
and the following:
|
|
|
|
|
General economic conditions, changes in the wholesale power
markets and fluctuations in the cost of fuel;
|
|
|
|
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 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 NRG
may not have adequate insurance to cover losses as a result of
such hazards;
|
|
|
|
The effectiveness of NRGs risk management policies and
procedures, and the ability of NRGs counterparties to
satisfy their financial commitments;
|
|
|
|
Counterparties collateral demands and other factors
affecting NRGs liquidity position and financial condition;
|
|
|
|
NRGs ability to operate its businesses efficiently, manage
capital expenditures and costs tightly (including general and
administrative expenses), and generate earnings and cash flows
from its asset-based businesses in relation to its debt and
other obligations;
|
|
|
|
NRGs potential inability to enter into contracts to sell
power and procure fuel on acceptable terms and prices;
|
|
|
|
The liquidity and competitiveness of wholesale markets for
energy commodities;
|
|
|
|
Government regulation, including compliance with regulatory
requirements and changes in market rules, rates, tariffs and
environmental laws and increased regulation of carbon dioxide
and other greenhouse gas emissions;
|
|
|
|
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 NRGs generation units for all of its
costs;
|
|
|
|
NRGs ability to borrow additional funds and access capital
markets, as well as NRGs substantial indebtedness and the
possibility that NRG may incur additional indebtedness going
forward;
|
|
|
|
Operating and financial restrictions placed on NRG contained in
the indentures governing NRGs outstanding notes in
NRGs senior credit facility and in debt and other
agreements of certain of NRG subsidiaries and project affiliates
generally;
|
|
|
|
NRGs ability to implement its RepoweringNRG
strategy of developing and building new power generation
facilities, including new nuclear units and Integrated
Gasification Combined Cycle, or IGCC, units;
|
|
|
|
NRGs ability to implement its econrg strategy of finding
ways to meet the challenges of climate change, clean air and
protecting our natural resources while taking advantage of
business opportunities; and
|
|
|
|
NRGs ability to achieve its strategy of regularly
returning capital to shareholders.
|
Forward-looking statements speak only as of the date they were
made, and NRG Energy, Inc. undertakes 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 NRGs actual
results to differ materially from those contemplated in any
forward-looking statements included in this Annual Report on
Form 10-K
should not be construed as exhaustive.
|
|
Item 1B
|
Unresolved
Staff Comments
|
None.
57
Listed below are descriptions of NRGs interests in
facilities, operations
and/or
projects owned as of December 31, 2007. The MW figures
provided represent nominal summer net megawatt capacity of power
generated as adjusted for the Companys ownership position
excluding capacity from inactive/mothballed units as of
December 31, 2007. The following table summarizes
NRGs power production and cogeneration facilities by
region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Power
|
|
|
|
|
Generation
|
|
|
|
Name and Location of Facility
|
|
Market
|
|
% Owned
|
|
|
Capacity(MW)
|
|
|
Primary Fuel-type
|
|
Texas Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A. Parish, Thompsons, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
2,460
|
|
|
Coal
|
Limestone, Jewett, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,690
|
|
|
Lignite/Coal
|
South Texas Project, Bay City,
Texas(a)
|
|
ERCOT
|
|
|
44.0
|
|
|
|
1,175
|
|
|
Nuclear
|
Cedar Bayou, Baytown, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,500
|
|
|
Natural Gas
|
T. H. Wharton, Houston, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,025
|
|
|
Natural Gas
|
W. A. Parish, Thompsons, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,190
|
|
|
Natural Gas
|
S. R. Bertron, Deer Park, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
840
|
|
|
Natural Gas
|
Greens Bayou, Houston, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
760
|
|
|
Natural Gas
|
San Jacinto, LaPorte, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
165
|
|
|
Natural Gas
|
Northeast Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oswego, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
1,635
|
|
|
Oil
|
Arthur Kill, Staten Island, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
865
|
|
|
Natural Gas
|
Middletown, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
770
|
|
|
Oil
|
Indian River, Millsboro, Delaware
|
|
PJM
|
|
|
100.0
|
|
|
|
740
|
|
|
Coal
|
Astoria Gas Turbines, Queens, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
550
|
|
|
Natural Gas
|
Dunkirk, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
530
|
|
|
Coal
|
Huntley, Tonawanda,
New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
380
|
|
|
Coal
|
Montville, Uncasville, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
500
|
|
|
Oil
|
Norwalk Harbor, So. Norwalk, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
340
|
|
|
Oil
|
Devon, Milford, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
140
|
|
|
Natural Gas
|
Vienna, Maryland
|
|
PJM
|
|
|
100.0
|
|
|
|
170
|
|
|
Oil
|
Somerset, Massachusetts
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
125
|
|
|
Coal
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Power
|
|
|
|
|
Generation
|
|
|
|
Name and Location of Facility
|
|
Market
|
|
% Owned
|
|
|
Capacity(MW)
|
|
|
Primary Fuel-type
|
|
Connecticut Jet Power, Connecticut (four sites)
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
105
|
|
|
Oil
|
Conemaugh, New Florence, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone, Shelocta, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
South Central Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Cajun II, New Roads,
Louisiana(b)
|
|
SERC-Entergy
|
|
|
86.0
|
|
|
|
1,490
|
|
|
Coal
|
Bayou Cove, Jennings, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Big Cajun I, Jarreau, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
210
|
|
|
Natural Gas
|
Big Cajun I, Jarreau, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
220
|
|
|
Natural Gas/Oil
|
Rockford I, Illinois
|
|
PJM
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Rockford II, Illinois
|
|
PJM
|
|
|
100.0
|
|
|
|
145
|
|
|
Natural Gas
|
Sterlington, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
185
|
|
|
Natural Gas
|
West Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Encina, Carlsbad, California
|
|
Cal ISO
|
|
|
100.0
|
|
|
|
965
|
|
|
Natural Gas
|
El Segundo Power, California
|
|
Cal ISO
|
|
|
100.0
|
|
|
|
670
|
|
|
Natural Gas
|
San Diego Combustion Turbines, California (three sites)
|
|
Cal ISO
|
|
|
100.0
|
|
|
|
190
|
|
|
Natural Gas
|
Saguaro Power Co., Henderson, Nevada
|
|
WECC
|
|
|
50.0
|
|
|
|
45
|
|
|
Natural Gas
|
Long Beach, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
260
|
|
|
Natural Gas
|
International Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gladstone Power
|
|
Enertrade/Boyne
|
|
|
|
|
|
|
|
|
|
|
Station, Queensland, Australia
|
|
Smelters
|
|
|
37.5
|
|
|
|
605
|
|
|
Coal
|
Schkopau Power Station, Germany
|
|
Vattenfall Europe
|
|
|
41.9
|
|
|
|
400
|
|
|
Lignite
|
MIBRAG,
Germany(c)
|
|
Schkopau & Lippendorf/ ENVIA
|
|
|
50.0
|
|
|
|
75
|
|
|
Lignite
|
ITISA,
Brazil(d)
|
|
COPEL
|
|
|
99.2
|
|
|
|
155
|
|
|
Hydro
|
|
|
|
(a)
|
|
For the nature of NRGs
interest and various limitations on the Companys interest,
please read Item 1 Business
Texas Generation Facilities section
|
|
(b)
|
|
Units 1 and 2 owned 100.0%, Unit 3
owned 58.0%
|
|
(c)
|
|
Primarily a coal mining facility
|
|
(d)
|
|
On December 18, 2007, NRG
entered into a sale and purchase agreement to sell its interest
in ITISA to Brookfield Power, a wholly-owned subsidiary of
Brookfield Asset Management Inc., for a purchase price of
approximately $288 million, plus the assumption of
approximately $60 million in debt, subject to regulatory
approvals and other closing conditions. NRG anticipates
completion of the sale transactions during the first half 2008
as discussed in Item 15 Note 3,
Discontinued Operations, Business Acquisitions and
Dispositions.
|
59
The following table summarizes NRGs thermal facilities as
of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
Ownership
|
|
|
|
Name and Location of Facility
|
|
Thermal Energy Purchaser
|
|
Interest
|
|
|
Generating Capacity
|
|
NRG Energy Center Minneapolis, Minnesota
|
|
Approx. 100 steam customers and 50 chilled water customers
|
|
|
100.0
|
|
|
Steam: 1,203 MMBtu/hr. (353 MWt) Chilled Water: 42,630
tons (150 MWt)
|
NRG Energy Center San Francisco, California
|
|
Approx. 170 steam customers
|
|
|
100.0
|
|
|
Steam: 454 MMBtu/Hr. (133 MWt)
|
NRG Energy Center Harrisburg, Pennsylvania
|
|
Approx. 230 steam customers and 3 chilled water customers
|
|
|
100.0
|
|
|
Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400
tons (8 MWt)
|
NRG Energy Center Pittsburgh, Pennsylvania
|
|
Approx. 25 steam and 25 chilled water customers
|
|
|
100.0
|
|
|
Steam: 266 MMBtu/hr. (78 MWt) Chilled water: 12,920
tons (45 MWt)
|
NRG Energy Center San Diego, California
|
|
Approx. 20 chilled water customers
|
|
|
100.0
|
|
|
Chilled water: 7,425 tons (26 MWt)
|
Camas Power Boiler Camas, Washington
|
|
Georgia-Pacific Corp.
|
|
|
100.0
|
|
|
Steam: 200 MMBtu/hr. (59 MWt)
|
NRG Energy Center Dover, Delaware
|
|
Kraft Foods Inc.
|
|
|
100.0
|
|
|
Steam: 190 MMBtu/hr. (56 MWt)
|
Paxton Creek Cogeneration, Harrisburg, Pennsylvania
|
|
PJM
|
|
|
100.0
|
|
|
12 MW Natural Gas
|
Dover Cogeneration, Delaware
|
|
PJM
|
|
|
100.0
|
|
|
104 MW Natural Gas/Coal
|
Other
Properties
In addition, NRG owns several real property and facilities
relating to its generation assets, other vacant real property
unrelated to the Companys generation assets, interest in a
construction project, and properties not used for operational
purposes. NRG believes it has satisfactory title to its plants
and facilities in accordance with standards generally accepted
in the electric power industry, subject to exceptions that, in
the Companys opinion, would not have a material adverse
effect on the use or value of its portfolio.
NRG leases its corporate offices at 211 Carnegie Center,
Princeton, New Jersey 08540 and various other office space.
60
|
|
Item 3
|
Legal
Proceedings
|
Natural Gas
Anti-Trust Cases I,II,III & IV,
California Judicial Council Coordination Proceeding Nos.
4221, 4224, 4226 and 4228, San Diego County Superior Court,
California. The cases consolidated in this proceeding are as
follows:
ABAG Publicly Owned Energy Resources v. Sempra
Energy, et al., Alameda County Superior Court, Case
No. RG04186098, (filed November 10, 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 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);
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);
Pabco Building Products v. Dynegy et al.,
San Diego Superior Court, Case No. GIC 856187,
(filed November 22, 2005); The Board of
Trustees of California State University v. Dynegy et al.,
San Diego Superior Court, Case No. GIC 856188,
(filed November 22, 2005).
The defendants in all of the above referenced cases include WCP
and various Dynegy entities. NRG 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.
Defendants motion to dismiss was denied by the Court on
June 22, 2005, and the cases are in discovery. Dynegy is
defending WCP pursuant to an indemnification agreement. In
October 2007 Dynegy reached a tentative agreement with
plaintiffs to settle these cases. Such settlement requires court
approval and proceedings seeking court approval are ongoing. If
such settlement was approved, WCP would pay no funds towards
that settlement as Dynegy is defending and indemnifying WCP.
California Electricity and Related Litigation
Indemnification In the above cases relating
to natural gas, Dynegys counsel is defending WCP
and/or its
subsidiaries and will be the responsible party for any loss.
There are no further cases relating to electricity, but should
any such new cases arise, Dynegys counsel would represent
it and WCP
and/or its
subsidiaries with Dynegy and WCP each responsible for half of
the costs and each party responsible for half of any loss.
Public Utilities Commission of the State of California et
al. v. Federal Energy Regulatory Commission, Nos.
03-74246 and
03-74207,
FERC Nos. EL
02-60-000,
EL 02-60,
and EL 02-62
(filed December 19, 2006) The
U.S. Court of Appeals for the Ninth Circuit reversed FERC
and remanded the case to FERC for further proceedings consistent
with the decision. This matter concerns, among other contracts
and other defendants, the California Department of Water
Resources, or CDWR, and its wholesale power contract with
subsidiaries of WCP. The case originated with a February 2002
complaint filed by the State of California alleging that many
parties, including WCP subsidiaries, overcharged the State. For
WCP, the alleged overcharges totaled approximately
$940 million for 2001 and 2002. With respect to WCP, the
complaint demanded that FERC abrogate the CDWR contract and
sought refunds associated with revenues collected under the
contract. In 2003, FERC rejected this demand, denied rehearing,
and the case was appealed to the Ninth Circuit where oral
argument was held December 8, 2004. The Ninth Circuit held
that in FERCs review of the contracts at issue, FERC could
not rely on the Mobile-Sierra standard presumption of just and
reasonable rates, as such contracts were not reviewed by FERC
with full knowledge of the then-existing market conditions. On
May 3, 2007, WCP and the other defendants filed separate
petitions for certiorari seeking review by the U.S. Supreme
Court and on September 25, 2007, the Court agreed to
61
hear two of the filed petitions. Although WCPs petition
was not selected for review, the Courts ultimate decision
with respect to the other defendants petitions will apply
equally to WCP. Briefs on behalf of the petitioners, the United
States, and friends of the Court were filed in November 2007.
Oral argument took place on February 19, 2008, with a
decision expected by the end of the year. At this time, while
NRG cannot predict with certainty whether WCP will be required
to make refunds for rates collected under the CDWR contract or
estimate the range of any such possible refunds, a
reconsideration of the CDWR contract by FERC with a resulting
order mandating significant refunds could have a material
adverse impact on NRGs financial condition, results of
operations, and statement of cash flows. As part of the 2006
acquisition of Dynegys share of the WCP assets, WCP and
NRG assumed responsibility for any risk of loss arising from
this case unless any such loss is deemed to have resulted from
certain acts of gross negligence or willful misconduct on the
part of Dynegy, in which case any such loss would be shared
equally by WCP and Dynegy.
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 took ownership of the
facilities. CL&P began billing NRG for station service
power and delivery services provided to the facilities and NRG
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 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. In August 2003, the parties
agreed to submit the dispute to binding arbitration. In July and
August 2006, the parties submitted their respective statements
to the three member arbitration panel. On September 11,
2007, the parties argued the dispute before a three judge
arbitration panel. On February 19, 2008, the parties
executed a settlement agreement ending the arbitration. A
component of the settlement requires approval from ISO-NE.
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 sought to recover damages less
payments received through the date of judgment, as well as
additional amounts for electric service provided to the Dunkirk
Plant. NiMo claimed 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. On
October 8, 2002, a Stipulation and Order was entered,
staying this action pending resolution by FERC of the disputes
in this matter.
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., Federal Energy Regulatory
Commission Docket No. EL
03-27-000
(filed November 26, 2002)
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. On
April 22, 2005, FERC denied NiMos motion for
rehearing and on October 23, 2006, the U.S. Court of
Appeals for the D.C. Circuit denied rehearing. On April 30,
2007, the U.S. Supreme Court denied NiMos request for
review of the D.C. Circuit decision thus ending further avenues
to appeal FERCs ruling in this matter. NRG believes it is
adequately reserved.
Spring Creek Coal Company v. NRG Texas LP, NRG South
Texas Power LP, NRG Texas Power LLC, NRG Texas LLC,, and NRG
Energy, Inc. Case
No. 2:07-cv-00168-CAB,
U.S. District Court for the District of Wyoming-Cheyenne
Division (filed July 30, 2007, amended
compliant filed December 3, 2007)
The complaint alleges multiple breaches
in 2007 of a 1978 coal supply agreement as amended by a later
1987 agreement, which plaintiff alleges is a take or
pay contract. Plaintiff is seeking damages of
approximately $18 million. Certain of the defendants filed
a motion to dismiss for lack of personal jurisdiction and
certain other defendants filed a motion to
62
dismiss for lack of a case in controversy. The court will hear
oral argument on these and other motions on July 11, 2008.
The trial has been scheduled to begin on September 8, 2008.
Native Village of Kivalina and City of Kivalina v.
ExxonMobil Corporation, et. al, U.S. District Court for the
Northern District of California (filed February 26,
2008) Numerous electric generating
companies and oil and gas companies have been named as
defendants in this complaint, which has been filed but not yet
served on NRG. Damages of up to $400 million have been
asserted. The complaint alleges that the carbon dioxide
emissions of defendants contribute to global climate change
which has harmed the plaintiffs. The complaint is filed on
behalf of an Alaskan town made up of native tribes and seeks
damages associated with those tribes having to relocate from the
northern coast of Alaska, purportedly because of the effects of
global warming.
Additional Litigation In addition to
the foregoing, NRG is party to other litigation or 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
NRGs plan of reorganization, NRG 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, as such claims are resolved, the
claimants are paid from the reserve on the same basis as if they
had been paid out in the bankruptcy. To the extent the aggregate
amount required to be paid on the disputed claims exceeds the
amount remaining in the funded claims reserve, NRG will be
obligated to provide additional cash and common stock to satisfy
the claims. Any excess funds in the disputed claims reserve will
be reallocated to the creditor pool for the pro rata benefit of
all allowed claims. The contributed common stock and cash in the
reserves are held by an escrow agent to complete the
distribution and settlement process. Since NRG has surrendered
control over the common stock and cash provided to the disputed
claims reserve, NRG recognized the issuance of the common stock
as of December 6, 2003, and removed the cash amounts from
the Companys balance sheets. Similarly, NRG removed the
obligations relevant to the claims from the balance sheets when
the common stock was issued and cash contributed.
On April 3, 2006, the Company made a supplemental
distribution to creditors under the Companys
Chapter 11 bankruptcy plan totaling $25 million in
cash and 5,082,000 shares of common stock. As of
February 7, 2008, the reserve held approximately
$10 million in cash and approximately 1,317,138 shares
of common stock. NRG believes the cash and stock together
represent sufficient funds to satisfy all remaining disputed
claims.
|
|
Item 4
|
Submission
of Matters to a Vote of Security Holders
|
None.
63
PART II
|
|
Item 5
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Market
Information and Holders
NRGs authorized capital stock consists of
500,000,000 shares of NRG common stock and
10,000,000 shares of preferred stock. A total of
16,000,000 shares of the Companys common stock are
available for issuance under NRGs Long-Term Incentive
Plan. NRG has also filed with the Secretary of State of Delaware
a Certificate of Designation for each of the following shares of
the Companys preferred stock: (i) 4% Redeemable
Perpetual Preferred Stock, (ii) 3.625% Convertible
Perpetual Preferred Stock, and (iii) 5.75% Mandatory
Convertible Preferred Stock.
On April 25, 2007, NRGs Board of Directors approved a
two-for-one stock split of the Companys outstanding shares
of common stock which was effected through a stock dividend. The
stock split entitled each stockholder of record at the close of
business on May 22, 2007 to receive one additional share
for every outstanding share of common stock held. The additional
shares resulting from the stock split were distributed by the
Companys transfer agent on May 31, 2007. All share
and per share amounts within this
Form 10-K
retroactively reflect the effect of the stock split.
NRGs common stock is listed on the New York Stock Exchange
and has been assigned the symbol: NRG. NRG has submitted to the
New York Stock Exchange its annual certificate from its Chief
Executive Officer certifying that he is not aware of any
violation by the Company of New York Stock Exchange corporate
governance listing standards. The high and low sales prices, as
well as the closing price for the Companys common stock on
a per share basis for 2007 and 2006 are set forth below:
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Fourth
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Third
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Second
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First
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Fourth
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Third
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Second
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First
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Common Stock
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Quarter
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|
Quarter
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|
Quarter
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|
Quarter
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|
Quarter
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|
|
Quarter
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|
Quarter
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|
|
Quarter
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Price
|
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2007
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
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2006
|
|
|
2006
|
|
|
2006
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2006
|
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High
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$
|
47.19
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$
|
45.08
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|
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$
|
45.93
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$
|
37.10
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$
|
29.74
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$
|
25.58
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$
|
26.31
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$
|
24.73
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Low
|
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|
38.79
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|
|
|
34.76
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|
|
|
35.98
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$
|
27.22
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|
|
22.14
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22.13
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21.22
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|
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20.90
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Closing
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$
|
43.34
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|
|
$
|
42.29
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|
|
$
|
41.57
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|
|
$
|
36.02
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|
$
|
28.00
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|
|
$
|
22.65
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$
|
24.09
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$
|
22.61
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|
NRG had 236,734,929 shares outstanding as of
December 31, 2007, and as of February 25, 2008, there
were 236,442,274 shares outstanding. As of February 25,
2008, there were approximately 58,900 common stockholders of
record.
Dividends
NRG has not declared or paid dividends on its common stock and
the amount available for dividends is currently limited by the
Companys senior secured credit agreements and high yield
note indentures.
Repurchase
of equity securities
NRGs repurchases of equity securities for the year ended
December 31, 2007, were as follows:
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Total Number
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of Shares
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Purchased as
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Dollar Value of
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Part of Publicly
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Shares that may be
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Total Number of
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Average Price
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Announced Plans
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Purchased Under the
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For the Year Ended December 31, 2007
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Shares Purchased
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Paid per Share
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or Programs
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Plans or Programs
|
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First quarter
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3,000,000
|
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$
|
34.38
|
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3,000,000
|
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$
|
165,160,714
|
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Second quarter
|
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2,669,200
|
|
|
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42.16
|
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2,669,200
|
|
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52,613,935
|
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Third quarter
|
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1,337,500
|
|
|
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39.38
|
|
|
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1,337,500
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Fourth quarter
|
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2,037,700
|
|
|
|
41.82
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|
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|
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|
|
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Total for 2007
|
|
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9,044,400
|
|
|
$
|
39.09
|
|
|
|
7,006,700
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64
On November 3, 2006, as part of Phase II of the
Companys Capital Allocation Program discussed in
Item 15 Note 13, Capital Structure,
NRG announced an increase to the share repurchase program to a
$500 million stock buyback. As originally announced on
August 1, 2006, Phase II was only to be a
$250 million stock buyback. NRG completed Phase II
during the third quarter 2007.
As part of the Companys ongoing Capital Allocation
Program, the Company initiated its 2008 program in December
2007. The Company repurchased 2,037,700 shares of NRG
common stock during that month in the open market for
approximately $85 million. In January 2008, the Company
repurchased an additional 344,000 shares of NRG common
stock on the open market for approximately $15 million.
Securities
Authorized for Issuance under Equity Compensation
Plans
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(c)
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Number of Securities
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(a)
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Remaining Available
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Number of Securities
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(b)
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for Future Issuance
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to be Issued Upon
|
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Weighted-Average Exercise
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Under Compensation
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Exercise of
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Price of Outstanding
|
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Plans (Excluding
|
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Outstanding Options,
|
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Options, Warrants and
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Securities Reflected
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Plan Category
|
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Warrants and Rights
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Rights
|
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in Column(a)
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Equity compensation plans approved by security holders
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7,180,589
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$
|
19.98
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7,941,758
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(a)
|
Equity compensation plans not approved by security holders
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N/A
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Total
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7,180,589
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$
|
19.98
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7,941,758
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(a)
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(a)
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NRG Energy, Inc.s Long-Term
Incentive Plan, or the LTIP, became effective upon the
Companys emergence from bankruptcy. The LTIP was
subsequently approved by the Companys stockholders on
August 4, 2004 and was amended on April 28, 2006 to
increase the number of shares available for issuance to
16,000,000, on a post-split basis, and again on December 8,
2006 to make technical and administrative changes. The LTIP
provides for grants of stock options, stock appreciation rights,
restricted stock, performance units, deferred stock units and
dividend equivalent rights. NRGs directors, officers and
employees, as well as other individuals performing services for,
or to whom an offer of employment has been extended by the
Company, are eligible to receive grants under the LTIP. The
purpose of the LTIP is to promote the Companys long-term
growth and profitability by providing these individuals with
incentives to maximize stockholder value and otherwise
contribute to the Companys success and to enable the
Company to attract, retain and reward the best available persons
for positions of responsibility. The Compensation Committee of
the Board of Directors administers the LTIP. There were
7,941,758 and 8,602,978 shares of common stock remaining
available for grants of awards under NRGs LTIP as of
December 31, 2007 and 2006, respectively.
|
65
Stock
Performance Graph
The performance graph below compares NRGs cumulative total
shareholder return on the Companys common stock for the
period January 2, 2004, through December 31, 2007 with
the cumulative total return of the Standard &
Poors 500 Composite Stock Price Index, or S&P 500,
and the Philadelphia Utility Sector Index, or UTY. Upon the
Companys emergence from bankruptcy on December 5,
2003 until March 24, 2004 NRGs common stock traded on
the Over-The-Counter Bulletin Board. On March 25,
2004, NRGs common stock commenced trading on the New York
Stock Exchange under the symbol NRG.
The performance graph shown below is being provided as furnished
and compares each period assuming that $100 was invested on
January 2, 2004 in each of the common stock of NRG, the
stocks included in the S&P 500 and the stocks included in
the UTY, and that all dividends were reinvested.
Comparison
of Cumulative Total Return
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Jan-2004
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Dec-2004
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Dec-2005
|
|
|
Dec-2006
|
|
|
Dec-2007
|
NRG Energy, Inc.
|
|
|
$
|
100.00
|
|
|
|
$
|
160.58
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|
|
|
$
|
209.89
|
|
|
|
$
|
249.49
|
|
|
|
$
|
386.10
|
|
S&P 500
|
|
|
|
100.00
|
|
|
|
|
111.22
|
|
|
|
|
116.68
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|
|
|
|
135.11
|
|
|
|
|
142.53
|
|
UTY
|
|
|
$
|
100.00
|
|
|
|
$
|
126.23
|
|
|
|
$
|
149.50
|
|
|
|
$
|
179.67
|
|
|
|
$
|
213.76
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66
|
|
Item 6
|
Selected
Financial Data
|
The following table presents NRGs historical 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 3, Discontinued
Operations, 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 Item 7, Managements Discussion
and Analysis of Financial Condition and Results of Operations.
Due to the adoption of Fresh Start reporting as of
December 5, 2003, Reorganized NRGs 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.
In addition, on April 25, 2007, NRGs Board of
Directors approved a two-for-one stock split of the
Companys outstanding shares of common stock which was
effected through a stock dividend. The stock split entitled each
stockholder of record at the close of business on May 22,
2007 to receive one additional share for every outstanding share
of common stock held. The additional shares resulting from the
stock split were distributed by the Companys transfer
agent on May 31, 2007. All share and per share amounts
within this
Form 10-K
retroactively reflect the effect of the stock split.
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|
|
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|
|
Reorganized NRG
|
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|
Predecessor Company
|
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|
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|
|
|
|
|
|
|
December 6
|
|
|
January 1
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
December 5,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2003
|
|
|
|
(In millions except ratio and per share data)
|
|
|
Statement of income data:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
$
|
2,080
|
|
|
$
|
120
|
|
|
$
|
1,570
|
|
Total operating costs and expenses
|
|
|
5,060
|
|
|
|
4,720
|
|
|
|
2,290
|
|
|
|
1,848
|
|
|
|
109
|
|
|
|
(1,671
|
)
|
Income from continuing operations, net
|
|
|
569
|
|
|
|
543
|
|
|
|
68
|
|
|
|
157
|
|
|
|
12
|
|
|
|
3,180
|
|
Income/(loss) from discontinued operations, net
|
|
|
17
|
|
|
|
78
|
|
|
|
16
|
|
|
|
29
|
|
|
|
(1
|
)
|
|
|
(414
|
)
|
Net income
|
|
|
586
|
|
|
|
621
|
|
|
|
84
|
|
|
|
186
|
|
|
|
11
|
|
|
|
2,766
|
|
Common share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic shares outstanding average
|
|
|
240
|
|
|
|
258
|
|
|
|
169
|
|
|
|
199
|
|
|
|
200
|
|
|
|
|
|
Diluted shares outstanding average
|
|
|
288
|
|
|
|
301
|
|
|
|
171
|
|
|
|
201
|
|
|
|
200
|
|
|
|
|
|
Shares outstanding end of year
|
|
|
237
|
|
|
|
245
|
|
|
|
161
|
|
|
|
174
|
|
|
|
200
|
|
|
|
|
|
Per share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations basic
|
|
|
2.14
|
|
|
|
1.90
|
|
|
|
0.28
|
|
|
|
0.78
|
|
|
|
0.06
|
|
|
|
|
|
Income from continuing operations diluted
|
|
|
1.95
|
|
|
|
1.78
|
|
|
|
0.28
|
|
|
|
0.78
|
|
|
|
0.06
|
|
|
|
|
|
Net income basic
|
|
|
2.21
|
|
|
|
2.21
|
|
|
|
0.38
|
|
|
|
0.93
|
|
|
|
0.06
|
|
|
|
|
|
Net income diluted
|
|
|
2.01
|
|
|
|
2.04
|
|
|
|
0.38
|
|
|
|
0.93
|
|
|
|
0.06
|
|
|
|
|
|
Book value
|
|
|
19.48
|
|
|
|
19.48
|
|
|
|
11.31
|
|
|
|
13.14
|
|
|
|
12.19
|
|
|
|
|
|
Business metrics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations
|
|
|
1,517
|
|
|
|
408
|
|
|
|
68
|
|
|
|
645
|
|
|
|
(589
|
)
|
|
|
238
|
|
Liquidity position
|
|
$
|
2,715
|
|
|
$
|
2,227
|
|
|
$
|
758
|
|
|
$
|
1,600
|
|
|
$
|
1,545
|
|
|
|
N/A
|
|
Ratio of earnings to fixed charges
|
|
|
2.28
|
|
|
|
2.38
|
|
|
|
1.48
|
|
|
|
1.93
|
|
|
|
1.76
|
|
|
|
11.92
|
|
Ratio of earnings to fixed charges and preference dividends
|
|
|
2.03
|
|
|
|
2.09
|
|
|
|
1.30
|
|
|
|
1.92
|
|
|
|
1.76
|
|
|
|
11.92
|
|
Return on equity
|
|
|
10.65
|
|
|
|
10.98
|
|
|
|
3.77
|
|
|
|
6.91
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Ratio of debt to total capitalization
|
|
|
55.70
|
|
|
|
57.38
|
|
|
|
44.91
|
|
|
|
44.57
|
|
|
|
56.14
|
|
|
|
N/A
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
3,562
|
|
|
$
|
3,083
|
|
|
$
|
2,197
|
|
|
$
|
2,119
|
|
|
$
|
2,183
|
|
|
|
N/A
|
|
Current liabilities
|
|
|
2,277
|
|
|
|
2,032
|
|
|
|
1,357
|
|
|
|
1,090
|
|
|
|
2,096
|
|
|
|
N/A
|
|
Property, plant and equipment, net
|
|
|
11,320
|
|
|
|
11,546
|
|
|
|
2,559
|
|
|
|
2,639
|
|
|
|
3,271
|
|
|
|
N/A
|
|
Total assets
|
|
|
19,274
|
|
|
|
19,436
|
|
|
|
7,467
|
|
|
|
7,906
|
|
|
|
9,336
|
|
|
|
N/A
|
|
Long-term debt, including current maturities and capital leases
|
|
|
8,361
|
|
|
|
8,726
|
|
|
|
2,456
|
|
|
|
3,220
|
|
|
|
3,648
|
|
|
|
N/A
|
|
Total stockholders equity
|
|
$
|
5,504
|
|
|
$
|
5,658
|
|
|
$
|
2,231
|
|
|
$
|
2,692
|
|
|
$
|
2,437
|
|
|
|
N/A
|
|
N/A not applicable
67
The following table provides the details of NRGs operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reorganized NRG
|
|
|
Predecessor Company
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 6
|
|
|
January 1
|
|
|
|
Year Ended December 31,
|
|
|
December 31,
|
|
|
December 5,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2003
|
|
|
|
(In millions except ratio and per share data)
|
|
|
Energy
|
|
$
|
4,265
|
|
|
$
|
3,155
|
|
|
$
|
1,840
|
|
|
$
|
1,181
|
|
|
$
|
52
|
|
|
$
|
769
|
|
Capacity
|
|
|
1,196
|
|
|
|
1,516
|
|
|
|
563
|
|
|
|
612
|
|
|
|
37
|
|
|
|
566
|
|
Risk management activities
|
|
|
4
|
|
|
|
124
|
|
|
|
(292
|
)
|
|
|
61
|
|
|
|
|
|
|
|
19
|
|
Contract amortization
|
|
|
242
|
|
|
|
628
|
|
|
|
9
|
|
|
|
(6
|
)
|
|
|
13
|
|
|
|
|
|
Thermal
|
|
|
125
|
|
|
|
124
|
|
|
|
124
|
|
|
|
112
|
|
|
|
9
|
|
|
|
24
|
|
Hedge Reset
|
|
|
|
|
|
|
(129
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
157
|
|
|
|
167
|
|
|
|
156
|
|
|
|
120
|
|
|
|
9
|
|
|
|
192
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
$
|
2,080
|
|
|
$
|
120
|
|
|
$
|
1,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue consists of revenues received from third parties
for sales in the day-ahead and real-time markets, as well as
bilateral sales. Beginning in 2006, energy revenues also
included revenues from the settlement of financial instruments
that qualify for cash flow hedge accounting treatment.
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 revenue includes revenue received under
tolling arrangements, which entitle third parties to dispatch
NRGs facilities and assume title to the electrical
generation produced from that facility.
Risk management activities are comprised of fair value changes
of financial instruments that have yet to be settled as well as
ineffectiveness on financial transactions accorded cash flow
hedge accounting treatment. It also includes the settlement of
all derivative transactions that do not qualify for cash flow
hedge accounting treatment. Prior to 2006, risk management
activities included the settlement of financial instruments that
qualified for cash flow hedge accounting treatment.
Thermal 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. It also includes the sale of
high-pressure steam produced and delivered to industrial
customers that is used as part of an industrial process.
Contract amortization revenues consists of acquired power
contracts, gas swaps, and certain power sales agreements assumed
at Fresh Start related to the sale of electric capacity and
energy in future periods, which are amortized into revenue over
the term of the underlying contracts based on actual generation
or contracted volumes.
Hedge Reset is the impact from the net settlement of long-term
power contracts and gas swaps by negotiating prices to current
market. This transaction was completed in November 2006. Also
see Item 15 Note 5, Accounting for
Derivatives and Hedging Activities, to the Consolidated
Financial Statements for a further discussion.
Other revenue primarily consists of operations and maintenance
fees, or O&M fees, sale of natural gas and emission
allowances, and revenue from ancillary services. O&M fees
consist of revenues received from providing certain
unconsolidated affiliates with services under long-term
operating agreements. Ancillary services are comprised of the
sale of energy-related products associated with the generation
of electrical energy such as spinning reserves, reactive power
and other similar products.
68
|
|
Item 7
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
In this discussion and analysis, the Company discusses and
explains the financial condition and the results of operations
for NRG for the year ended December 31, 2007, that will
include the points below:
|
|
|
|
|
Factors which affect NRGs business;
|
|
|
|
NRGs earnings and costs in the periods presented;
|
|
|
|
Changes in earnings and costs between periods;
|
|
|
|
Impact of these factors on NRGs overall financial
condition;
|
|
|
|
A discussion of new and ongoing initiatives that may affect
NRGs future results of operations and financial condition;
|
|
|
|
Expected future expenditures for capital projects; and
|
|
|
|
Expected sources of cash for future operations and capital
expenditures.
|
As you read this discussion and analysis, refer to NRGs
Consolidated Statements of Operations, which present the results
of the Companys operations for the years ended
December 31, 2007, 2006 and 2005. The Company analyzes and
explains the differences between the periods in the specific
line items of NRGs Consolidated Statements of Operations.
This discussion and analysis has been organized as follows:
|
|
|
|
|
Business strategy;
|
|
|
|
Business environment in which NRG operates including how
regulation, weather, and other factors affect the business;
|
|
|
|
Significant events that are important to understanding the
results of operations and financial condition;
|
|
|
|
Results of operations including an overview of the
Companys results, followed by a more detailed review of
those results by operating segment;
|
|
|
|
Financial condition addressing its credit ratings, sources and
uses of cash, capital resources and requirements, commitments,
and off-balance sheet arrangements; and
|
|
|
|
Critical accounting policies which are most important to both
the portrayal of the Companys financial condition and
results of operations, and which require managements most
difficult, subjective or complex judgment.
|
Executive
Summary
Overview
NRG Energy, Inc., or NRG or the Company, is a wholesale power
generation company with a significant presence in major
competitive power markets in the United States. NRG is engaged
in the ownership, development, construction and operation of
power generation facilities, the transacting in and trading of
fuel and transportation services, and the trading of energy,
capacity and related products in the United States and select
international markets. As of December 31, 2007, NRG had a
total global portfolio of 191 active operating generation units
at 49 power generation plants, with an aggregate generation
capacity of approximately 24,115 MW and approximately
740 MW under construction which includes partnership
interests. Within the United States, NRG has one of the largest
and most diversified power generation portfolios in terms of
geography, fuel-type and dispatch levels, with approximately
22,880 MW of generation capacity in 175 active generating
units at 43 plants. These power generation facilities are
primarily located in Texas (approximately 10,805 MW), the
Northeast (approximately 6,980 MW), South Central
(approximately 2,850 MW), and West (approximately
2,130 MW) regions of the United States, with approximately
115 MW of additional generation capacity from the
Companys thermal assets. NRGs principal domestic
power plants consist of a mix of natural gas-, coal-, oil-fired
and nuclear facilities, representing approximately 46%, 33%, 16%
and 5% of the Companys total domestic generation capacity,
respectively. In addition, 15% of NRGs domestic generating
facilities have dual or multiple fuel capacity, which allows
plants to
69
dispatch with the lowest cost fuel option. NRGs domestic
generation facilities consist of baseload, intermediate and
peaking power generation facilities, the ranking of which is
referred to as Merit Order, and include thermal energy
production plants. The sale of capacity and power from baseload
generation facilities accounts for the majority of the
Companys revenues and provides a stable source of cash
flow. In addition, NRGs generation portfolio provides the
Company with opportunities to capture additional revenues by
selling power during periods of peak demand, offering capacity
or similar products to retail electric providers and others, and
providing ancillary services to support system reliability.
Business
Strategy
NRGs strategy is to optimize the value of the
Companys generation assets while using its asset base as a
platform for growth and enhanced financial performance which can
be sustained and expanded upon in the years to come. NRG plans
to maintain and enhance the Companys position as a leading
wholesale power generation company in the United States in a
cost-effective and risk-mitigating manner in order to serve the
bulk power requirements of NRGs existing customer base and
other entities that offer load or otherwise consume wholesale
electricity products and services in bulk. NRGs strategy
includes the following principles:
Increase value from existing assets NRG has a
highly diversified portfolio of power generation assets in terms
of region, fuel-type and dispatch levels. Through the
FORNRG initiative, NRG will continue to focus on
extracting value from its portfolio by improving plant
performance, reducing costs and harnessing the Companys
advantages of scale in the procurement of fuels and other
commodities, parts and services, and in doing so improving the
Companys return on invested capital, or ROIC.
Reduce the volatility of the Companys cash flows
through asset-based commodity hedging activities
NRG will continue to execute asset-based risk
management, hedging, marketing and trading strategies within
well-defined risk and liquidity guidelines in order to manage
the value of the Companys physical and contractual assets.
The Companys marketing and hedging philosophy is centered
on generating stable returns from its portfolio of baseload
power generation assets while preserving an ability to
capitalize on strong spot market conditions and to capture the
extrinsic value of the Companys intermediate and peaking
facilities and portions of its baseload fleet. NRG believes that
it can successfully execute this strategy by (i) leveraging
its expertise in marketing power and ancillary services,
(ii) its knowledge of markets, (iii) its balanced
financial structure and (iv) its diverse portfolio of power
generation assets.
Pursue additional growth opportunities at existing
sites NRG is favorably positioned to pursue
growth opportunities through expansion of its existing
generating capacity and development of new generating capacity
at its existing facilities. NRG intends to invest in its
existing assets through plant improvements, repowerings,
brownfield development and site expansions to meet anticipated
requirements for additional capacity in NRGs core markets.
Through the RepoweringNRG initiative, NRG will continue
to develop, construct and operate new and enhanced power
generation facilities at its existing sites, with an emphasis on
new baseload capacity that is supported by long-term power sales
agreements and financed with limited or non-recourse project
financing. NRG expects that these efforts will provide one or
more of the following benefits: improved heat rates; lower
delivered costs; expanded electricity production capability; an
improved ability to dispatch economically across the Merit
Order; increased technological and fuel diversity; and reduced
environmental impacts, including facilities that either have
near zero GHG, emissions or can be equipped to capture and
sequester GHG emissions.
Reduce carbon intensity of portfolio while taking advantage
of carbon-driven business opportunities NRG
continues to actively pursue investments in new generating
facilities and technologies that will be highly efficient and
will employ no and low carbon technologies to limit
CO2
emissions and other air emission. Through the
RepoweringNRG and econrg initiatives, NRG is focused on
the development of low or no GHG emitting energy generating
sources, such as nuclear, wind, clean coal and gas,
and the employment of post-combustion capture technologies,
which represents significant commercial opportunities.
Maintain financial strength and flexibility
NRG remains focused on cash flow and maintaining appropriate
levels of liquidity, debt and equity in order to ensure
continued access to capital for investment, to enhance
risk-adjusted returns and to provide flexibility in executing
NRGs business strategy. NRG will continue to focus on
maintaining operational and financial controls designed to
ensure that the Companys financial position remains
70
strong. At the same time, the Companys ongoing capital
allocation objective includes scheduled repayment of debt based
on the amount of cash flow by the Company each year, as well as
an annual return of capital to shareholders, targeted at an
average rate of 3% of market capitalization, of approximately
$250 million to $300 million per year.
Pursue strategic acquisitions and divestures
NRG will continue to pursue selective acquisitions, joint
ventures and divestitures to enhance its asset mix and
competitive position in the Companys core markets. NRG
intends to concentrate on opportunities that present attractive
risk-adjusted returns. NRG will also opportunistically pursue
other strategic transactions, including mergers, acquisitions or
divestitures.
Business
Environment
General Industry Emerging trends impacting
the power industry include (a) increased regulatory and
political scrutiny, (b) financial credit market disruptions
triggered by sub-prime investment losses which may have, in
part, contributed to current recessionary pressures, and
(c) the development of power capacity markets intended to
induce new investment in order to address tightening reserve
margins. The industry dynamics and external influences that will
affect the Company and the power generation industry in 2008 and
for the medium term include:
Carbon At the national level and at various
regional and state levels, policies are under development to
regulate GHG emissions, including
CO2,
the most common pollutant, thereby effectively putting a cost on
such emissions in order to create financial incentive to reduce
them. It is almost certain that GHG regulatory schemes will
encompass power plants, with the impact on the Companys
financial performance depending on a number of factors,
including the overall level of GHG reductions required under any
such regulation, the price and availability of offsets, and the
extent to which NRG would be entitled to receive GHG emissions
allowances without having to purchase them in an auction or on
the open market. While the passing and timing of legislation
remains uncertain, the Company expects that the impact of such
legislation on the Companys financial performance, as such
legislation is currently proposed, to have a minimal impact
through the next decade. Thereafter, the impact would depend on
the level of success of the Companys multifold strategy,
which includes (a) shaping public policy with the objective
being constructive and effective federal GHG regulatory policy,
and (b) pursuing its RepoweringNRG and econrg
programs. The Companys multifold strategy is discussed in
greater detail in Item 1, Business under Carbon
Update.
Financial Credit Market Availability and Domestic
Recessionary Pressures. Triggered largely by the
decay in sub-prime credit markets, the cost of credit has
sharply increased while credit availability has declined.
Capital intensive generators rely on the credit markets for
liquidity and for the financing of power generation investments.
Concurrently, economic indicators are pointing towards a
potential slowdown in the United States economy. A sharp
downturn in U.S. housing, the tighter credit conditions,
and disappointing employment numbers, amongst other data have
highlighted the risk of economic recession. Historically, an
economic recession results in lower power demand and power
prices. If an economic recession does occur in the near term it
is unlikely to have a material impact on the Company due to the
hedged position of its portfolio.
Consolidation Over the long-term, industry
consolidation is expected to occur, with mergers and
acquisitions activity in the power generation sector likely to
involve utility-merchant or merchant-merchant combinations.
There may also be interest by foreign power companies,
particularly European utilities, in the American power
generation sector. However, for the near-term, and particularly
in the coming year, given the current financial market
environment along with the uncertainty surrounding domestic
carbon legislation, consolidation is less likely.
Infrastructure Development In response to
record peak power demand, tightening reserve margins, and
volatile natural gas prices, the power generation industry has
announced significant expansion plans for both transmission and
generation. In addition to traditional gas-fired capacity, much
of the new generation announced would be from non-gas fuel
sources, including nuclear and renewable sources. During 2007,
18 gigawatts of previously announced pulverized coal generation
projects were canceled due to increasing public and political
concern regarding carbon emissions. The Energy Policy Act of
2005 created financial incentives for non-traditional baseload
generation, such as advance nuclear and clean coal
technologies in order to reduce reliance on the more traditional
pulverized coal technologies. Depending on the timing and
location of this new construction, as well as
71
the construction activity in the oil and petrochemical sectors,
access to experienced engineers, skilled operators, and
maintenance workers could impact the timing and costs of these
projects.
Market Developments A number of the markets
NRG serves are currently undergoing changes. NE-ISO held its
first auction in February 2008 for 2010 capacity commitments as
part of its FCM, while in California, MRTU is scheduled to go
into effect on April 1, 2008. PJM completed its first RPM
auctions during 2007. The primary objective of these market
re-designs are to provide timely and accurate market signals to
encourage new investment in transmission and new generation in
the locations where the new investment is needed. In addition to
these capacity market developments, in December 2008, ERCOT is
expected to fully implement the Texas Nodal
Protocols, which will revise the wholesale market design
to incorporate locational marginal pricing, replacing the
existing zonal wholesale market design. The ERCOT market design
is expected to reduce local transmission congestion costs, with
impacts on pricing uncertain at this time.
Competition
Wholesale power generation is a capital-intensive,
commodity-driven business with numerous industry participants.
NRG competes on the basis of the location of its plants and
owning multiple plants in its regions, which increases the
stability and reliability of its energy supply. Wholesale power
generation is basically a local business that is currently
highly fragmented relative to other commodity industries and
diverse in terms of industry structure. As such, there is a wide
variation in terms of the capabilities, resources, nature and
identity of the companies NRG competes against depending on the
market.
Weather
Weather conditions in the different regions of the United States
influence the financial results of NRGs businesses.
Weather conditions can affect the supply and demand for
electricity and fuels. Changes in energy supply and demand may
impact the price of these energy commodities in both the spot
and forward markets, which may affect the Companys results
in any given period. Typically, demand for and the price of
electricity is higher in the summer and the winter seasons, when
temperatures are more extreme. The demand for and price of
natural gas and oil are higher in the winter. However, all
regions of North America typically do not experience extreme
weather conditions at the same time, thus NRG is typically not
exposed to the effects of extreme weather in all parts of its
business at once.
Other
Factors
A number of other factors significantly influence the level and
volatility of prices for energy commodities and related
derivative products for NRGs business. These factors
include:
|
|
|
|
|
seasonal daily and hourly changes in demand;
|
|
|
|
extreme peak demands;
|
|
|
|
available supply resources;
|
|
|
|
transportation and transmission availability and reliability
within and between regions;
|
|
|
|
location of NRGs generating facilities relative to the
location of its load-serving opportunities;
|
|
|
|
procedures used to maintain the integrity of the physical
electricity system during extreme conditions; and
|
|
|
|
changes in the nature and extent of federal and state
regulations.
|
These factors can affect energy commodity and derivative prices
in different ways and to different degrees. These effects may
vary throughout the country as a result of regional differences
in:
|
|
|
|
|
weather conditions;
|
|
|
|
market liquidity;
|
72
|
|
|
|
|
capability and reliability of the physical electricity and gas
systems;
|
|
|
|
local transportation systems; and
|
|
|
|
the nature and extent of electricity deregulation.
|
Stock
Split
On April 25, 2007, NRGs Board of Directors approved a
two-for-one stock split of the Companys outstanding shares
of common stock which was effected through a stock dividend. The
stock split entitled each stockholder of record at the close of
business on May 22, 2007 to receive one additional share
for every outstanding share of common stock held. The additional
shares resulting from the stock split were distributed by the
Companys transfer agent on May 31, 2007. All share
and per share amounts within this
Form 10-K
retroactively reflect the effect of the stock split.
Environmental
Matters, Regulatory Matters and Legal Proceedings
NRG discusses details of its other environmental matters in
Item 15 Note 23, Environmental
Matters, to its Consolidated Financial Statements and
Item 1, Business Environmental Matters,
section. NRG discusses details of its regulatory matters in
Item 15 Note 22, Regulatory
Matters, to its Consolidated Financial Statements and
Item 1, Business Environmental Matters,
section. NRG discusses details of its legal proceedings in
Item 15 Note 21, Commitments and
Contingencies, to its Consolidated Financial Statements.
Some of this information is about costs that may be material to
the Companys financial results.
Impact
of inflation on NRGs results
Unless discussed specifically in the relevant segment, for the
years ended December 31, 2007, 2006 and 2005, the impact of
inflation and changing prices (due to changes in exchange rates)
on NRGs revenues and income from continuing operations was
immaterial.
Capital
Allocation Strategy
NRGs capital allocation philosophy includes reinvestment
in its core facilities, maintenance of prudent debt levels and
interest coverage, the regular return of capital to shareholders
and investment in repowering opportunities. Each of these
components are described further as follows:
|
|
|
|
|
Reinvestment in existing assets Opportunities to
invest in the existing business, including maintenance and
environmental capital expenditures that improve operational
performance, ensure compliance with environmental laws and
regulations, and expansion projects.
|
|
|
|
Management of debt levels The Company uses several
metrics to measure the efficiency of its capital structure and
debt balances, including the Companys targeted net debt to
total capital ratio range of 45% to 60% and certain cash flow
and interest coverage ratios. The Company intends in the normal
course of business to continue to manage its debt levels towards
the lower end of the range and may, from time to time, pay down
its debt balances for a variety of reasons.
|
|
|
|
Return of capital to shareholders The Companys
debt instruments include restrictions on the amount of capital
that can be returned to shareholders. The Company has in the
past returned capital to shareholders while maintaining
compliance with existing debt agreements and indentures. The
Company expects to regularly return capital to shareholders
through opportunistic share repurchases, while exploring other
prospects to increase its flexibility under restrictive debt
covenants.
|
|
|
|
Repowering, econrg and new build opportunities The
Company intends to pursue repowering initiatives that enhance
and diversify its portfolio and provide a targeted economic
return to the Company.
|
73
Significant
events during the year ended December 31, 2007
Results
of Operations
|
|
|
|
|
Impact of Hedge Reset in November 2006, the
Company reset legacy Texas hedges which resulted in an increase
in energy revenue of $449 million as the periods
average contract prices increased by approximately $13 per MWh
as compared to the 2006 average contract prices.
|
|
|
|
Development costs NRG incurred
$101 million in net development costs primarily due to
required engineering studies to obtain the Combined Construction
and Operating License Application, or COLA, as well as
development costs for other RepoweringNRG projects. On
September 24, 2007, NRG filed a COLA with the NRC to build
and operate two new nuclear units at the STP site. Effective
October 29, 2007, the City of San Antonio agreed to
partner with NRG in the development and ownership of these new
units, to reimburse NRG for a pro rata share of certain project
costs NRG had incurred, and to pay a pro rata share of future
development costs. NRG was reimbursed $42 million for costs
incurred to develop STP 3 and 4 through October 31, 2007;
$39 million of the total $42 million was recorded as a
reduction to development costs.
|
|
|
|
Acquisition of Texas and WCP the inclusion of
a full year of activity for the Texas region and WCP in 2007,
contributed to an increase in operating income of approximately
$76 million, compared to 2006.
|
|
|
|
New capacity markets the introduction of the
Locational Forward Reserve Market, or LFRM, the Reliability
Pricing Model market, or RPM, and transition capacity payment
markets, increased capacity revenues in the Northeast region by
$78 million.
|
|
|
|
Refinancing expense the Company recognized a
$35 million write-off of previously deferred financing cost
due to the refinancing of the Companys Senior Credit
Facility.
|
|
|
|
Interest expense the increase in debt due to
the acquisition of Texas Genco LLC, Hedge Reset transaction and
the Capital Allocation Program increased interest expense by
approximately $99 million.
|
|
|
|
Sale of ITISA on December 18, 2007, NRG
entered into a sale and purchase agreement to sell its 100%
interest in Tosli, which holds all of NRGs interest in
ITISA, to Brookfield Asset Management Inc. for the purchase
price of $288 million, plus the assumption of approximately
$60 million in debt. NRG anticipates the completion of the
sale transaction during the first half of 2008. As discussed in
Note 3 Discontinued Operations, Business
Acquisitions and Dispositions the activities of Tosli and
ITISA have been classified in discontinued operations.
|
Other
|
|
|
|
|
STP Repowerings The NRC docketed the
Companys COLA on November 30, 2007, signaling the
beginning of their comprehensive and detailed review process.
The Company expects to achieve commercial operation for Unit 3
approximately 48 months after issuance of the COLA, and
commercial operation for Unit 4 approximately 12 months
thereafter.
|
|
|
|
Cedar Bayou Generating Station on
August 1, 2007, NRG and a partner entered into definitive
agreements pursuant to which the two parties will jointly
develop, construct, operate and own, on a
50/50
undivided interest basis, a new 550 MW combined cycle
natural gas turbine generating plant at NRGs Cedar Bayou
Generating Station in Chambers County, Texas. In exchange for a
50% undivided interest in certain tangible and intangible assets
and rights to use facilities owned by NRG, the partner agreed to
pay NRG $45 million during a
24-month
period.
|
|
|
|
Long Beach on August 1, 2007, the
Company successfully completed and commissioned the repowering
of 260 MW of new gas-fired generating capacity at its Long
Beach Generating Station. This project is supported by a
10-year PPA.
|
74
Consolidated
Results of Operations
2007
compared to 2006
The following table provides selected financial information for
NRG Energy, Inc., for the years ended December 31, 2007 and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
4,265
|
|
|
$
|
3,155
|
|
|
|
35
|
%
|
Capacity revenue
|
|
|
1,196
|
|
|
|
1,516
|
|
|
|
(21
|
)
|
Risk management activities
|
|
|
4
|
|
|
|
124
|
|
|
|
N/A
|
|
Contract amortization
|
|
|
242
|
|
|
|
628
|
|
|
|
(61
|
)
|
Thermal revenue
|
|
|
125
|
|
|
|
124
|
|
|
|
1
|
|
Hedge Reset
|
|
|
|
|
|
|
(129
|
)
|
|
|
N/A
|
|
Other revenues
|
|
|
157
|
|
|
|
167
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
5,989
|
|
|
|
5,585
|
|
|
|
7
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,378
|
|
|
|
3,265
|
|
|
|
3
|
|
Depreciation and amortization
|
|
|
658
|
|
|
|
590
|
|
|
|
12
|
|
General and administrative
|
|
|
309
|
|
|
|
276
|
|
|
|
12
|
|
Development costs
|
|
|
101
|
|
|
|
36
|
|
|
|
181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,446
|
|
|
|
4,167
|
|
|
|
7
|
|
Gain on sale of assets
|
|
|
17
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
1,560
|
|
|
|
1,418
|
|
|
|
10
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
54
|
|
|
|
60
|
|
|
|
(10
|
)
|
Gains on sales of equity method investments
|
|
|
1
|
|
|
|
8
|
|
|
|
(88
|
)
|
Other income, net
|
|
|
55
|
|
|
|
156
|
|
|
|
(65
|
)
|
Refinancing expenses
|
|
|
(35
|
)
|
|
|
(187
|
)
|
|
|
(81
|
)
|
Interest expense
|
|
|
(689
|
)
|
|
|
(590
|
)
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(614
|
)
|
|
|
(553
|
)
|
|
|
11
|
|
Income from Continuing Operations before income tax
expense
|
|
|
946
|
|
|
|
865
|
|
|
|
9
|
|
Income tax expense
|
|
|
377
|
|
|
|
322
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
569
|
|
|
|
543
|
|
|
|
5
|
|
Income from discontinued operations, net of income tax expense
|
|
|
17
|
|
|
|
78
|
|
|
|
(78
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
586
|
|
|
$
|
621
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMbtu)
|
|
|
7.12
|
|
|
|
6.99
|
|
|
|
2
|
%
|
N/A-Not applicable
75
Operating
Revenues
Operating revenues increased by $404 million for the year
ended December 31, 2007, compared to 2006. This was due to:
|
|
|
|
|
Energy revenues energy revenues increased by
$1.1 billion for the year ended December 31, 2007,
compared to 2006:
|
|
|
|
|
|
Texas energy revenues increased by
$972 million of which $217 million was due to the
inclusion of twelve months activity in 2007 compared to eleven
months in 2006. Of the remaining $755 million increase,
$449 million was due to the Hedge Reset transaction which
resulted in higher 2007 average contracted prices of
approximately $13 per MWh. In addition, revenues from
8.8 million MWh of generation moved from capacity revenue
to energy revenue. Prior to the Acquisition, PUCT regulations
required that Texas sell 15% of its capacity by auction at
reduced rates. In March 2006, the PUCT accepted NRGs
request to no longer participate in these auctions and that
capacity is now being sold in the merchant market. These
favorable results were partially offset by lower sales from the
regions natural gas-fired units due to a cooler summer
which resulted in lower generation of approximately
2.7 million MWh.
|
|
|
|
Northeast energy revenues increased by
approximately $138 million, of which $61 million was
due to a 6% increase in generation, primarily driven by
increases at the regions Arthur Kill, Oswego and Indian
River plants. The Arthur Kill plant increased generation by 448
thousand MWh due to transmission constraints around New York
City, the Oswego plants generation increased by 127
thousand MWh due to a colder winter during 2007 compared to
2006, and the Indian River plants generation increased by
418 thousand MWh due to stronger pricing and fewer outages in
the second half of 2007 compared to the second half of 2006.
|
|
|
|
South Central energy revenues increased by
approximately $70 million, due to a new contract which
increased contract sales volume by approximately
1.3 million MWh and energy revenues by $69 million.
Following a contractual fuel adjustment charge, energy revenues
increased by $11 million from the regions cooperative
customers. This was offset by a $12 million decrease in
merchant energy revenue.
|
|
|
|
West energy revenues decreased by
approximately $72 million, excluding the first quarter
2007, due to the tolling agreement at the Encina plant that has
resulted in the receipt of fixed monthly capacity payment in
return for the right to schedule and dispatch from the plant.
The Encina tolling agreement replaced an RMR agreement under
which the plant was called upon to generate and earn energy
revenues for such dispatch.
|
|
|
|
|
|
Capacity revenues capacity revenues decreased
by $320 million for the year ended December 31, 2007,
compared to 2006, due to a decrease in Texas capacity revenues
that were partially offset by increases in capacity revenues in
the Northeast, South Central and West regions:
|
|
|
|
|
|
Texas capacity revenues decreased by
$486 million due to a reduction of capacity auction sales
mandated by the PUCT in prior years as previously discussed.
|
|
|
|
Northeast capacity revenues increased by
$81 million of which $39 million of the increase was
from the regions NEPOOL assets and $36 million was
from the regions PJM assets. The NEPOOL assets benefited
from the new LFRM market and transition capacity market, both
introduced in the fourth quarter 2006. Capacity revenues
increased by $24 million from the LFRM market and
$18 million from transition capacity payments, which was
offset by a $3 million reduction in capacity payments due
to the expiration of the Devon plants RMR agreement on
December 31, 2006. On June 1, 2007, the new RPM
capacity market became effective in PJM increasing capacity
revenues by $36 million as compared to 2006.
|
|
|
|
South Central capacity revenues increased by
approximately $22 million. Of this increase,
$15 million was due to higher billing rates as a result of
the regions market setting new summer peaks hit in 2006
and 2007, $6 million was due to higher contractual
transmission pass-though costs to the regions cooperative
customers and $3 million was due to improved market
conditions at the regions Rockford plants. In
|
76
August 2007, the region set a new system peak of 2,123 MW
which will continue to impact capacity revenue in the first half
of 2008.
|
|
|
|
|
West capacity revenues increased by
approximately $54 million, of which $26 million was
related to the inclusion of the first quarter 2007 compared to
2006. New tolling agreements at the regions Encina and
Long Beach plants accounted for the remaining difference, with
the Encina facility contributing approximately $15 million
and the newly-repowered Long Beach facility contributing
approximately $13 million.
|
|
|
|
|
|
Contract amortization revenues from contract
amortization decreased by $386 million for the year ended
December 31, 2007, compared to 2006, as a result of the
November 2006 Hedge Reset transaction, which resulted in a
write-off of a large portion of the Companys out-of-market
power contracts during the fourth quarter 2006.
|
|
|
|
Other revenues other revenues decreased by
$10 million for the year ended December 31, 2007,
compared to 2006 due to:
|
|
|
|
|
|
Sale of emission allowances net sales of
SO2
emission allowances decreased by approximately $33 million.
In 2006, we sold emissions in lieu of generation due to an
unseasonably warm first quarter. Since that time the average
market price for
SO2
allowances decreased by 28%.
|
|
|
|
Physical gas sales decreased by
$7 million due to the lower sales of excess natural gas.
|
|
|
|
Ancillary revenues ancillary services revenue
increased by approximately $27 million due to a change in
strategy to actively provide ancillary services in the Texas
region which increased revenues by $33 million. This was
partially offset by a $4 million reduction in ancillary
services in the Northeast region due to higher transmission
costs following transmission constraints in the New York City
area.
|
|
|
|
|
|
Risk management activities gains/losses from
risk management activities include all derivative activity that
do not qualify for hedge accounting as well as the ineffective
portion associated with hedged transactions. Such gains were
$4 million for the year ended December 31, 2007. The
breakdown of changes by region are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Net gains on settled positions, or financial revenues
|
|
$
|
33
|
|
|
$
|
43
|
|
|
$
|
5
|
|
|
$
|
81
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
(83
|
)
|
|
|
(45
|
)
|
|
|
|
|
|
|
(128
|
)
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
(1
|
)
|
|
|
(12
|
)
|
|
|
(19
|
)
|
|
|
(32
|
)
|
Net unrealized gains on open positions related to economic hedges
|
|
|
19
|
|
|
|
15
|
|
|
|
|
|
|
|
34
|
|
Net unrealized gains/(losses) on open positions related to
trading activity
|
|
|
(1
|
)
|
|
|
26
|
|
|
|
24
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results
|
|
|
(66
|
)
|
|
|
(16
|
)
|
|
|
5
|
|
|
|
(77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gains/(losses)
|
|
$
|
(33
|
)
|
|
$
|
27
|
|
|
$
|
10
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities that did not qualify for hedge
accounting treatment resulted in a total derivative gain of
approximately $4 million for the year ended
December 31, 2007 compared to a $124 million gain for
the year ended December 31, 2006. NRGs 2007
derivative gain was comprised of $77 million mark-to-market
losses and $81 million in settled gains, or financial
revenue. Of the $77 million of mark-to-market losses,
$128 million represents the reversal of mark-to-market
gains previously recognized on economic hedges and
$32 million from the reversal of mark-to-market gains
previously recognized on trading activity. Both of these losses
ultimately settled as financial revenues during 2007. The
$34 million gain from economic hedge positions was
comprised of a
77
$20 million increase in the value of forward sales of
electricity and fuel due to favorable power and gas prices and a
$14 million gain from hedge accounting ineffectiveness.
This ineffectiveness was primarily related to gas swaps and
collars in the Texas region due to a change in the correlation
between natural gas and power prices. NRG also recognized a
$49 million unrealized gain associated with the
Companys trading activity.
Since these hedging activities are intended to mitigate the risk
of commodity price movements on revenues and cost of energy
sold, the changes in such results should not be viewed in
isolation, but rather taken together with the effects of pricing
and cost changes on energy revenues. In late 2006 and during the
course of 2007, NRG hedged a portion of the Companys 2007
and 2008 generation. Since that time, the settled and forward
prices of electricity and natural gas have decreased, resulting
in the recognition of unrealized mark-to-market forward gains
and the settlement of realized positions at a gain. In 2006, NRG
recognized forward mark-to-market gains as forward prices of
electricity decreased relative to its positions forward; settled
loss positions were driven by the out-of-market gas swaps
acquired with the Texas Genco purchase.
Cost
of Operations
Cost of operations for the year ended December 31, 2007,
increased by $113 million compared to 2006, but as a
percentage of revenues it was 56% for 2007 compared to 58% for
2006.
|
|
|
|
|
Cost of energy cost of energy decreased by
approximately $24 million, to $2,428 million, for the
year ended December 31, 2007, compared to 2006, and as a
percentage of revenue it decreased from 44% for the year ended
December 31, 2006, to 41% for the year ended
December 31, 2007. This decrease was due to:
|
|
|
|
|
|
Texas decreased by $95 million for the
year ended December 31, 2007, compared to 2006. This
included an additional months expense of $96 million
in 2007, without which cost of energy would have decreased by
$191 million. This decrease was due to a reduction in
natural gas expense and fuel contract amortization, partially
offset by increased ancillary service expense.
|
|
|
|
|
|
Fuel expense and purchased power expense
Natural gas expense decreased by $170 million, which
excludes January 2007 natural gas expense of $27 million.
This was due to a decrease of 2.7 million MWh in gas-fired
generation as a result of cooler summer weather, coupled with
greater economic purchases from ERCOT and increased baseload
generation. Despite higher coal-fired generation at the
regions W.A. Parish and Limestone plants, the
regions coal expenses, excluding January 2007, decreased
by $13 million due to a 9% reduction in average contracted
coal prices.
|
|
|
|
Fuel contract amortization decreased by
approximately $43 million, excluding January 2007, due to
declining forward fuel price curves below the contracted prices
used at Acquisition.
|
|
|
|
Purchased ancillary service expense increased
by approximately $34 million due to favorable market prices
in purchasing this service in the market compared to providing
the service from internal resources.
|
|
|
|
|
|
Northeast cost of energy increased by
$26 million primarily due to $30 million in higher
natural gas costs related to increased generation at the
regions Arthur Kill plant due to its locational advantage
to New York City following transmission constraints during the
last three quarters of 2007.
|
|
|
|
South Central Cost of energy increased by
$104 million due to increases in purchased energy, coal
costs and transmission costs.
|
|
|
|
|
|
Purchased energy increased by approximately
$69 million due to increased market purchases following
increased cooperative load requirements and planned maintenance
at the regions Big Cajun II facility.
|
|
|
|
Coal costs increased by approximately
$17 million, of which $11 million was related to a 9%
increase in coal prices and $7 million due to higher coal
transportation costs.
|
|
|
|
Transmission costs increased by approximately
$16 million of which $6 million was due to contractual
increases related to network transmission service.
Point-to-point transmission costs also increased by
$10 million reflecting more off-system sales.
|
78
|
|
|
|
|
West Cost of energy decreased by
approximately $76 million, excluding the first quarter
2007, due to new tolling agreement entered into at the Encina
plant in 2007, which requires the counterparty to supply their
own fuel. Under the previous arrangement in 2006, the plant
supplied the fuel.
|
|
|
|
|
|
Other operating costs Other operating costs
which includes operations and maintenance expenses, or O&M,
increased by $137 million, to $950 million, for the
year ended December 31, 2007, compared to 2006. This
increase was due to:
|
|
|
|
|
|
Texas other operating costs increased by
$75 million, after excluding January 2007 expense of
$39 million, other operating costs increased by
$36 million. This $36 million increase was due to
$25 million in higher O&M expense as a result of
increased maintenance associated with planned outages and fuel
handling at the W.A. Parish facility and $10 million in
higher property tax expenses following an increased valuation
after the Acquisition.
|
|
|
|
Northeast other operating costs increased by
$18 million due to increased staffing costs and higher
maintenance costs.
|
|
|
|
South Central other operating costs
increased by approximately $28 million, $19 million of
which was due to increased maintenance expense primarily related
to planned outages. Additionally, the region disposed of
$4 million in assets in conjunction with the outage.
|
|
|
|
Acquisition of WCP these results include
$15 million of WCP expenses that were not included in the
Companys results in 2006.
|
Depreciation
and Amortization
NRGs depreciation and amortization expense for the year
ended December 31, 2007, increased by $68 million
compared to 2006. This increase was due to:
|
|
|
|
|
Texas acquisition the inclusion of Texas
results for twelve months in 2007 compared to eleven months in
2006 resulted in an increase of approximately $38 million.
|
|
|
|
Impact of new environmental legislation due
to new and more restrictive environmental legislation, the
useful life of certain pollution control equipment has been
reduced. The Company accelerated depreciation on certain
equipment in its Northeast region to reflect the remaining
useful life, resulting in increased depreciation of
approximately $13 million.
|
General
and Administrative
NRGs G&A costs for the year ended December 31,
2007, increased by $33 million compared to 2006, and as a
percentage of revenues was 5% in both 2007 and 2006. This
increase was due to:
|
|
|
|
|
Texas and WCP acquisitions the inclusion
of Texas results for twelve months in 2007 compared to eleven
months in 2006 and the consolidation of WCP for the last three
quarters of 2006 resulted in an increase of approximately
$9 million.
|
|
|
|
Wage and benefit costs due to the
expansion of the Company, including RepoweringNRG
initiatives, wages and related benefits costs resulted in a
$28 million increase in G&A. Additionally, information
technology and other office services to support this expansion
increased by $8 million.
|
|
|
|
Franchise tax the Companys
Louisiana state franchise tax increased by approximately
$6 million. This was because the states franchise tax
is assessed based on the Companys total debt and equity
that increased significantly following the acquisition of Texas
Genco LLC.
|
|
|
|
Non-recurring expenses during 2006 for
the year ended December 31, 2006, G&A included
non-recurring fees of $20 million of which $6 million
were related to the unsolicited takeover attempt by Mirant
Corporation and $14 million associated with the Texas
integration efforts.
|
79
Development
Costs
NRGs development costs for the year ended
December 31, 2007, increased by $65 million. These
costs were due to the Companys RepoweringNRG
projects:
|
|
|
|
|
Texas on September 24, 2007, NRG filed a
COLA with the NRC to build and operate two new nuclear units at
the STP site. During the period, NRG incurred $91 million
in development costs related to STP units 3 and 4 project in
2007. These development costs were reduced by a $39 million
reimbursement related to a partnership agreement signed during
the fourth quarter 2007.
|
|
|
|
Wind projects approximately $13 million
in development costs related to wind projects primarily in Texas.
|
|
|
|
Other project approximately $4 million
in development costs related to other RepoweringNRG
projects in the West region.
|
Gain
on Sale of Assets
NRGs net gain on sale of assets for the year ended
December 31, 2007, was approximately $17 million. On
January 3, 2007, NRG completed the sale of the
Companys Red Bluff and Chowchilla II power plants
resulting in a pre-tax gain of approximately $18 million.
Equity
in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates for
the year ended December 31, 2007, decreased by
$6 million compared to 2006. This decrease was due to the
sale of multiple equity investments from which the Company
earned $8 million for the year ended December 31, 2006.
Other
Income, Net
NRGs other income for the year ended December 31,
2007, decreased by $101 million compared to 2006. This
decrease was due to the non-cash settlement during the first
quarter 2006 where NRG recorded $67 million of other income
associated with a settlement with an equipment manufacturer
related to turbine purchase agreements entered into in 1999 and
2001. The settlement resulted in the reversal of accounts
payable totaling $35 million resulting from the discharge
of the previously recorded liability, and an adjustment to write
up the value of the equipment received to its fair value,
resulting in income of approximately $32 million.
Additionally, in 2006, other income was favorably impacted by a
$13 million non-cash gain associated with the discharge of
liabilities upon dissolution of an inactive legal entity and a
$5 million non-cash gain due to a favorable settlement with
respect to post closing adjustments on the acquisition of the
Companys western New York plants.
During 2007, the Company recorded an $11 million impairment
charge in the fourth quarter related to an investment in
commercial paper reducing its carrying value to approximately
$32 million. The Company earned $10 million less in
interest income in 2007 compared to 2006, due to lower average
cash balances.
Interest
Expense
NRGs interest expense for the year ended December 31,
2007, increased by $99 million compared to 2006. This
increase was due to:
|
|
|
|
|
Refinancing for the acquisition of Texas Genco LLC in
February 2006 the Company significantly
increased its corporate debt facilities from approximately
$2 billion as of December 31, 2005, to approximately
$7 billion as of February 2, 2006. This increased
interest expense by approximately $12 million compared to
2006.
|
|
|
|
Increase of $1.1 billion in debt for Hedge
Reset the Company issued $1.1 billion
in Senior Notes due 2017 in November 2006 related to the Hedge
Reset, which increased interest expense by approximately
$72 million.
|
80
|
|
|
|
|
Capital Allocation Program the Company
issued a total of $330 million of debt to fund Phase I
of the Capital Allocation Program during the second half of
2006. This increased interest expense by $20 million
compared to 2006.
|
In the first quarter 2006, NRG entered into interest rate swaps
with the objective of fixing the interest rate on a portion of
NRGs Senior Credit Facility. These swaps were designated
as cash flow hedges under SFAS 133, and the impact
associated with ineffectiveness was immaterial to NRG financial
results. For the year ended December 31, 2007, NRG had a
deferred loss of $31 million in other comprehensive income
compared to deferred gains of $16 million in 2006.
Refinancing
Expense
Refinancing expense decreased by $152 million for the year
ended December 31, 2007, compared to 2006, due to higher
expense for the refinancing of the Companys corporate debt
for the acquisition of Texas Genco LLC on February 2, 2006,
compared to the refinancing of the Companys Senior Credit
Facility during 2007.
On June 8, 2007, NRG completed a $4.4 billion
refinancing of the Companys Senior Credit Facility
previously announced on May 2, 2007. The transaction
resulted in a 0.25% reduction on the spread that the Company
pays on its term loan and Synthetic Letter of Credit facility, a
$200 million reduction in the Synthetic Letter of Credit
Facility to $1.3 billion, and various amendments to provide
improved flexibility, efficiency for returning capital to
shareholders, asset repowering and investment opportunities. The
pricing on the Companys term loan and Synthetic Letter of
Credit are also subject to further reductions upon the
achievement of certain financial ratios. The refinancing
resulted in a charge of approximately $35 million to the
Companys results of operations that were primarily related
to the write-off of deferred financing costs as the lenders for
approximately 45% of the Term B loan either exited the financing
or reduced their holdings and were replaced by other
institutions.
Income
Tax Expense
Income tax expense increased by $55 million for the year
ended December 31, 2007, compared to 2006. The effective
tax rate was 39.9% and 37.2% for the year ended
December 31, 2007 and 2006, respectively.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions
|
|
|
|
except otherwise stated)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
946
|
|
|
$
|
865
|
|
Tax at 35%
|
|
|
331
|
|
|
|
303
|
|
State taxes, net of federal benefit
|
|
|
46
|
|
|
|
34
|
|
Foreign operations
|
|
|
(13
|
)
|
|
|
(21
|
)
|
Subpart F taxable income
|
|
|
|
|
|
|
11
|
|
Valuation allowance, including change in state effective rate
|
|
|
6
|
|
|
|
(10
|
)
|
Change in state effective tax rate
|
|
|
|
|
|
|
21
|
|
Claimant reserve settlements
|
|
|
|
|
|
|
(28
|
)
|
Change in local German effective tax rates
|
|
|
(29
|
)
|
|
|
|
|
Foreign dividends
|
|
|
26
|
|
|
|
1
|
|
Non-deductible interest
|
|
|
10
|
|
|
|
3
|
|
Permanent differences, reserves, other
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
377
|
|
|
$
|
322
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
39.9
|
%
|
|
|
37.2
|
%
|
81
The increase in income tax expense was primarily due to:
|
|
|
|
|
Increase in profits income before tax
increased by $81 million, with a corresponding increase of
approximately $32 million in income tax expense.
|
|
|
|
Permanent differences the Companys
effective tax rate differs from the US statutory rate of 35% due
to:
|
|
|
|
|
|
Change in German tax rate due to a reduction
in the German statutory and resulting effective tax rate, income
tax expense benefited by $29 million for the year-ended
2007.
|
|
|
|
Taxable dividends from foreign subsidiaries
in January 2007, the Company transferred the
proceeds from the sale of its Flinders assets to the
U.S. creating additional income tax expense of
approximately $25 million.
|
|
|
|
Lower tax rates in foreign jurisdictions
lower income tax rates at the Companys
foreign locations resulted in additional income tax expense
during 2007 compared to 2006 of $8 million.
|
|
|
|
Non-deductible interest interest expense from
the stock buybacks from Phase I of the Companys Capital
Allocation Program were non-deductible for income tax purposes,
thus increasing income tax expense by approximately
$7 million.
|
|
|
|
Change in state effective tax rate the state
effective tax rate remains unchanged for 2007. This resulted in
a net decrease in income tax expense of approximately
$5 million as compared to 2006, after taking into account
the movement in valuation allowance as a result of the change in
rate from 2005 to 2006.
|
|
|
|
Subpart F taxable income a dividend was
declared and paid in 2007 by NRGenerating International B.V. As
result of this dividend, there was no Subpart F income compared
to 2006. This resulted in a decrease to income tax expense of
approximately $11 million.
|
|
|
|
Disputed claims reserve During 2007 as
compared to 2006, the Company made no distribution from its
disputed claims reserve, this increased income tax expense by
approximately $28 million.
|
The effective income tax rate may vary from period to period
depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances
in accordance with SFAS 109. These factors and others,
including the Companys history of pre-tax earnings and
losses, are taken into account in assessing the ability to
realize deferred tax assets.
Income
from Discontinued Operations, Net of Income Tax
Expense
NRG classifies as discontinued operations the income from
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. For the years
ended December 31, 2007 and 2006, NRG recorded income from
discontinued operations, net of income tax expense of
$17 million and $78 million, respectively.
Discontinued operations for the year ended December 31,
2007 were comprised of the results of ITISA. Discontinued
operations for the year ended December 31, 2006 were
comprised of the results of ITISA, Flinders, Audrain and
Resource Recovery. NRG closed on the sale of Flinders during the
third quarter 2006 and recognized an after-tax gain of
approximately $60 million from the sale.
82
2006
compared to 2005
The following table provides selected financial information for
NRG Energy, Inc., for the years ended December 31, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change %
|
|
|
|
(In millions
|
|
|
|
|
|
|
except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
3,155
|
|
|
$
|
1,840
|
|
|
|
71
|
%
|
Capacity revenue
|
|
|
1,516
|
|
|
|
563
|
|
|
|
169
|
|
Risk management activities
|
|
|
124
|
|
|
|
(292
|
)
|
|
|
NA
|
|
Contract amortization
|
|
|
628
|
|
|
|
9
|
|
|
|
NA
|
|
Thermal revenue
|
|
|
124
|
|
|
|
124
|
|
|
|
|
|
Hedge Reset
|
|
|
(129
|
)
|
|
|
|
|
|
|
NA
|
|
Other revenues
|
|
|
167
|
|
|
|
156
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
5,585
|
|
|
|
2,400
|
|
|
|
133
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,265
|
|
|
|
1,829
|
|
|
|
79
|
|
Depreciation and amortization
|
|
|
590
|
|
|
|
158
|
|
|
|
273
|
|
General and administrative
|
|
|
276
|
|
|
|
176
|
|
|
|
57
|
|
Development costs
|
|
|
36
|
|
|
|
|
|
|
|
NA
|
|
Other charges
|
|
|
|
|
|
|
12
|
|
|
|
NA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,167
|
|
|
|
2,175
|
|
|
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
1,418
|
|
|
|
225
|
|
|
|
530
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
60
|
|
|
|
104
|
|
|
|
(42
|
)
|
Write downs and gains/(losses) on sales of equity method
investments
|
|
|
8
|
|
|
|
(31
|
)
|
|
|
NA
|
|
Other income, net
|
|
|
156
|
|
|
|
54
|
|
|
|
189
|
|
Refinancing expenses
|
|
|
(187
|
)
|
|
|
(65
|
)
|
|
|
188
|
|
Interest expense
|
|
|
(590
|
)
|
|
|
(177
|
)
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(553
|
)
|
|
|
(115
|
)
|
|
|
381
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations before income tax
expense
|
|
|
865
|
|
|
|
110
|
|
|
|
686
|
|
Income tax expense
|
|
|
322
|
|
|
|
42
|
|
|
|
667
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
543
|
|
|
|
68
|
|
|
|
699
|
|
Income from discontinued operations, net of income tax expense
|
|
|
78
|
|
|
|
16
|
|
|
|
388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
621
|
|
|
$
|
84
|
|
|
|
639
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMbtu)
|
|
|
6.99
|
|
|
|
8.89
|
|
|
|
(21
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
N/A Not applicable
83
For the benefit of the following discussions, the table below
represents the results of NRG excluding the impact of the
Companys Texas region, the Hedge Reset and WCP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total excluding
|
|
|
2005
|
|
|
|
Consolidated
|
|
|
Texas Region
|
|
|
WCP
|
|
|
Texas Region/WCP
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
|
Energy revenue
|
|
$
|
3,155
|
|
|
$
|
1,726
|
|
|
$
|
72
|
|
|
$
|
1,357
|
|
|
$
|
1,840
|
|
Capacity revenue
|
|
|
1,516
|
|
|
|
849
|
|
|
|
64
|
|
|
|
603
|
|
|
|
563
|
|
Risk management activities
|
|
|
124
|
|
|
|
(30
|
)
|
|
|
|
|
|
|
154
|
|
|
|
(292
|
)
|
Contract amortization
|
|
|
628
|
|
|
|
609
|
|
|
|
|
|
|
|
19
|
|
|
|
9
|
|
Thermal revenue
|
|
|
124
|
|
|
|
|
|
|
|
|
|
|
|
124
|
|
|
|
124
|
|
Hedge Reset
|
|
|
(129
|
)
|
|
|
(129
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
167
|
|
|
|
63
|
|
|
|
5
|
|
|
|
99
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating revenues
|
|
|
5,585
|
|
|
|
3,088
|
|
|
|
141
|
|
|
|
2,356
|
|
|
|
2,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,265
|
|
|
|
1,669
|
|
|
|
112
|
|
|
|
1,484
|
|
|
|
1,829
|
|
Depreciation and amortization
|
|
|
590
|
|
|
|
413
|
|
|
|
2
|
|
|
|
175
|
|
|
|
158
|
|
General and administrative
|
|
|
276
|
|
|
|
111
|
|
|
|
6
|
|
|
|
159
|
|
|
|
176
|
|
Development costs
|
|
|
36
|
|
|
|
14
|
|
|
|
4
|
|
|
|
18
|
|
|
|
|
|
Other charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,167
|
|
|
|
2,207
|
|
|
|
124
|
|
|
|
1,836
|
|
|
|
2,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
1,418
|
|
|
$
|
881
|
|
|
$
|
17
|
|
|
$
|
520
|
|
|
$
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues increased by $3,185 million for the year
ended December 31, 2006, compared to 2005. However,
excluding the Companys Texas region, the Hedge Reset
transaction and WCP, total operating revenues decreased by
approximately $44 million.
|
|
|
|
|
Energy revenues energy revenues
increased by $1,315 million for the year ended December 31,
2006, compared to 2005 with 50% contracted in 2006 compared to
13% in 2005. Excluding the Texas region and WCP, energy revenues
decreased by approximately $483 million or 26%.
|
|
|
|
|
|
Texas The acquisitions of Texas Genco LLC now
referred to as the Companys Texas region, contributed
$3,088 million to operating revenues including
$1,726 million of energy revenues.
|
|
|
|
West The acquisition of Dynegys 50%
interest in WCP contributed $72 million to total energy
revenues.
|
|
|
|
Northeast generation demand for the Northeast
regions intermediate and peaking plants declined by 54%,
accompanied by a 19% to 23% year over year decline in power
prices in the Northeast regions three major markets.
|
|
|
|
|
|
Capacity revenues capacity revenues were
$1,516 million for the year ended December 31, 2006
compared to $563 million for the year ended
December 31, 2005, an increase of $953 million. This
was due to:
|
|
|
|
|
|
Texas the acquisitions of Texas Genco LLC now
referred to as the Companys Texas region, contributed
$3,088 million to operating revenues including
$849 million of capacity revenues.
|
|
|
|
West The acquisition of Dynegys 50%
interest in WCP contributed $64 million to total capacity
revenues.
|
|
|
|
Northeast Higher capacity prices for the New
York Rest of State market, led to a $30 million increase in
the Northeast regions 2006 capacity revenues.
|
84
|
|
|
|
|
South Central The regions capacity
revenues also grew by $9 million as pricing increased due
to increased peak demand.
|
Hedge Reset In November 2006, NRG
executed a series of transactions designed to both extend and
strengthen the Companys baseload hedging positions and to
enable further optimization of the Companys ongoing
Capital Allocation Program. It involved net settling legacy
Texas region long-term power contracts and gas swaps by
negotiating prices to current market levels with certain
counterparties. This resulted in the accelerated amortization of
approximately $1,073 million of out-of-market power
contracts and $145 million of gas swaps derivative
liability offset by a payment of approximately
$1,347 million to the counterparties, for a net reduction
of approximately $129 million in the Companys total
operating revenues. In addition, as part of NRGs Hedge
Reset transactions, the Company recorded $6 million of
costs related to the transaction.
Risk Management Activity The following table
shows NRGs risk management activities that do not qualify
for hedge accounting treatment for the year ended
December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Net losses on settled positions, or financial revenues
|
|
$
|
(152
|
)
|
|
$
|
(10
|
)
|
|
$
|
(6
|
)
|
|
$
|
(3
|
)
|
|
$
|
(171
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized losses on settled
positions related to economic hedges
|
|
|
|
|
|
|
115
|
|
|
|
1
|
|
|
|
|
|
|
|
116
|
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
|
|
|
|
(25
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
(26
|
)
|
Net unrealized gains on open positions related to economic hedges
|
|
|
122
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
Net unrealized gains on open positions related to trading
activity
|
|
|
|
|
|
|
14
|
|
|
|
19
|
|
|
|
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results
|
|
|
122
|
|
|
|
154
|
|
|
|
19
|
|
|
|
|
|
|
|
295
|
|
Total derivative gains/(losses)
|
|
$
|
(30
|
)
|
|
$
|
144
|
|
|
$
|
13
|
|
|
$
|
(3
|
)
|
|
$
|
124
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities that do not qualify for hedge
accounting treatment resulted in a total derivative gain of
approximately $124 million for the year ended
December 31, 2006 compared to a $292 million loss for
the year ended December 31, 2005. These losses were
comprised of $171 million in settled financial revenue
losses and $295 million of mark-to-market gains. The
$171 million loss in financial revenues represents the
settled value for financial instruments that do not qualify for
hedge accounting treatment and were primarily related to
$152 million in losses of gas swaps acquired with the
purchase of Texas Genco LLC. Of the $295 million in
mark-to-market gains, $172 million represents the change in
the fair value of forward sales of electricity and fuel,
including $28 million of hedge accounting ineffectiveness
related to hedge contracts in the Companys Texas region
due to a decline in the correlation between natural gas and
power prices. In addition, $90 million of the
$295 million mark-to-market gains represents the reversal
of mark-to-market losses, which ultimately settled as financial
revenues. NRG also recognized a $33 million unrealized gain
associated with the Companys trading activity.
Since NRGs risk management activities are intended to
mitigate the risk of commodity price movements on revenues and
cost of energy sold, the changes in these results should not be
viewed in isolation, but rather taken together with the effects
of pricing and cost changes on energy revenues (which are
recorded net of financial instrument hedges that qualify for
hedge accounting treatment). In late 2005 and during the course
of 2006, NRG hedged a portion of the Companys 2007
generation. After entering into those transactions the forward
prices of electricity decreased, mainly due to mild weather for
much of the year in the Northeast region and the downward trend
in natural gas prices in 2006. While settled prices also
decreased, the Companys 2007 settled loss position was
driven by the out-of-market gas swaps acquired with the Texas
Genco purchase. In 2005, forward mark-to-market losses and the
settlement of positions at losses was related to the
run-up in
natural gas prices which occurred in the wake of hurricane
Katrina and Rita resulting in the recognition of mark-to-market
forward sales as gains.
85
Cost
of Operations
Cost of operations includes cost of energy, operating and
maintenance expenses, and non-income tax expenses. For the year
ended December 31, 2006, cost of operations was
$3,265 million or 58% of total operating revenues compared
to $1,829 million, or 76%, of total operating revenues for
2005, an increase of $1,436 million. This increase in
absolute terms, but decrease in relative percentage terms, was
primarily due to the acquisition of the Companys Texas
region which incurred costs of $1,669 million. Cost of
energy which includes fuels, purchased power, and cost contract
amortization increased from $1,427 million for 2005 to
$2,452 million in 2006. The increase of $1,025 million
was primarily due to:
|
|
|
|
|
Texas The acquisitions of Texas Genco
LLC now referred to as the Companys Texas region,
increased cost of energy by approximately $1,276 million.
|
|
|
|
West The acquisition of Dynegys
50% interest in WCP increased cost of energy by approximately
$79 million.
|
This was partially offset by lower cost of energy in the:
|
|
|
|
|
Northeast cost of energy decreased by
$254 million, due to $143 million lower oil costs and
$101 million in lower gas fuel costs as a result of lower
generation from oil- and gas-fired assets of approximately 70%
and 45%, respectively.
|
|
|
|
South Central cost of energy decreased
by $66 million in 2006, as higher coal plant availability
and increased utilization of the regions tolling
agreements reduced the need to purchase energy to support
contract load requirements.
|
Other operating costs increased in 2006 by $411 million to
$813 million, $393 million related to the acquisition
of the Companys Texas region and $33 million for WCP.
Excluding the impact of NRG Texas and WCP, other operating costs
were $15 million lower than last year primarily due to
lower operating and maintenance costs, which benefited in the
second quarter 2006 from an accrual reversal of $18 million
related to a favorable court decision in a station service
dispute at NRGs Western New York plants. In addition, as
part of NRGs Hedge Reset transactions, the Company
recorded $6 million of costs related to the transaction.
Depreciation
and Amortization
NRGs annual depreciation and amortization expense for 2006
and 2005 was $590 million and $158 million,
respectively. The Texas regions depreciation and
amortization comprised $413 million of the
$432 million year-over-year increase.
General
and Administrative
|
|
|
|
|
NRGs G&A costs for 2006 were $276 million
compared to $176 million in the previous year. Corporate
costs represented $143 million, or 3% of 2006 total
operating revenues and $112 million, or 5% of the
Companys 2005 total operating revenues. Excluding WCP and
the Companys Texas region G&A was lower by
$17 million, despite having been adversely impacted by
$6 million of costs associated with the unsolicited
acquisition offer by Mirant Corporation and approximately
$14 million of NRG Texas integration costs.
|
Development
Costs
NRG incurred approximately $36 million in development
expenses in 2006 to support its RepoweringNRG program.
Equity
in Earnings of Unconsolidated Affiliates
Equity earnings from NRGs investments in unconsolidated
affiliates were $60 million for the year ended
December 31, 2006, compared to $104 million for the
year ended December 31, 2005, a decline of approximately
42%. The decline in earnings was primarily due to:
86
|
|
|
|
|
Purchase of remaining 50% interest in
WCP NRGs purchase of the remaining
50% interest in WCP accounted for $21 million of the
decline, as the results of WCP were fully consolidated as of
March 31, 2006. As part of that transaction, NRG sold its
50% interest in the Rocky Road investment, which accounted for
$7 million of the decline in total equity earnings.
|
|
|
|
Sale of Non-Core Assets NRGs
Enfield investment, which was sold on April 1, 2005, earned
$16 million during 2005. Sales of other equity investments
in 2006 included James River, Cadillac and certain Latin
American power funds.
|
This was partially offset by a $4 million improvement in
equity income from the Companys MIBRAG investment which
experienced improved results compared to 2005 as a result of
fewer customer outages.
Write
Downs and Gains/(Losses) on Sales of Equity Method
Investments
During 2006, NRG continued to divest of its non-core assets by
selling the Companys interests in James River and
Cadillac, as well as interests in certain Latin American power
funds for a pre-tax loss of $6 million, a pre-tax gain of
$11 million and a pre-tax gain of $3 million,
respectively.
For the year ended December 31, 2005, NRG recorded a
$31 million loss due to the sale and impairment of certain
equity investments. On April 1, 2005, NRG sold its 25%
interest in Enfield, resulting in net pre-tax proceeds of
$65 million and a pre-tax gain of $12 million. In
2005, NRG also sold its interest in Kendall and recorded a
pre-tax gain of approximately $4 million. These gains on
sales were offset by approximately $47 million in
impairment charges recorded last year. In December 2005, NRG
executed an agreement with Dynegy to sell the Companys 50%
interest in Rocky Road LLC in conjunction with NRGs
purchase of Dynegys 50% interest in WCP. Based on the
terms of the transaction which valued the Companys
investment in Rocky Road at $45 million, NRG impaired its
interest in Rocky Road by writing down the value of the
investment by approximately $20 million. The sale of Rocky
Road closed on March 31, 2006. In 2005, NRG also recorded
an impairment of $27 million on its investment in the
Saguaro power plant. With the expiration of the plants
long-term gas supply contract, the Saguaro power plant became
exposed to the risk of fluctuating natural gas prices beginning
in the second half of 2005, triggering a permanent write down of
NRGs investment value in Saguaro.
Other
Income, Net
Other income increased by $102 million for the year ended
December 31, 2006 to $156 million compared to the same
period in 2005. Other income in 2006 was favorably impacted by
$67 million of income associated with a non-cash settlement
with an equipment manufacturer related to turbine purchase
agreements entered into in 1999 and 2001, a $13 million
non-cash gain associated with the discharge of liabilities upon
dissolution of an inactive legal entity, and $5 million
from the favorable settlement with respect to post closing
adjustments on the acquisition of the Companys western New
York plants in 1998 and 1999. Other income was also favorably
impacted in 2006 by $25 million of higher interest income
related to higher levels of cash and more efficient management
of cash balances.
Refinancing
Expenses
Refinancing expenses incurred in 2006 and 2005 were
$187 million and $65 million, respectively. In the
first quarter 2006, this was due to:
|
|
|
|
|
Refinancing for the acquisition of Texas Genco
LLC NRG partially financed the acquisition
of Texas Genco LLC through borrowings under new debt facilities
and repaid and terminated previous debt facilities. As a result
of this financing, the Company incurred $178 million of
refinancing expenses: $127 million was related to the
premium paid to NRGs previous debt holders,
$34 million for the amortization of the remaining balance
of a bridge loan commitment entered into on September 30,
2005, and $31 million related to write-offs of deferred
financing costs associated with NRGs previous debt, and a
credit of $14 million related to a debt premium write-off.
|
|
|
|
Redemption of Second Priority Notes In
2005, NRG redeemed and purchased a total of approximately
$645 million of the Companys second priority notes.
As a result of the redemption and purchases, NRG
|
87
incurred approximately $54 million in premiums and
write-offs of deferred financing costs. NRG also incurred an
additional $11 million in refinancing fees during the
fourth quarter of 2005 related to the amortization of a bridge
loan commitment fee that the Company paid related to acquisition
financing.
Interest
Expense
Interest expense for the year ended December 31, 2006 was
$590 million compared to $177 million for the year
ended December 31, 2005. The increase in interest expense
was primarily due to:
|
|
|
|
|
Financing for the acquisition of Texas Genco
LLC interest on new debt issued to finance
the acquisition of Texas Genco LLC. See Item 15
Note 3, Discontinued Operations, Business
Acquisitions and Dispositions, and Note 11, Debt and
Capital Leases, to the consolidated financial statements for
a further discussion of the acquisition and the related
financing. As part of the refinancing, NRG replaced its previous
senior secured term loan with a new $3.575 billion senior
secured term loan. In addition, NRG retired $1.1 billion of
its 8% second priority notes and issued $3.6 billion in
senior unsecured notes with a weighted average interest rate of
7.33%.
|
In the first quarter 2006, NRG entered into interest rate swaps
with the objective of fixing the interest rate on a portion of
the Companys new Senior Credit Facility. These swaps were
designated as cash flow hedges under FAS 133, and any
impact associated with ineffectiveness was immaterial to
NRGs financial results. For the year ended
December 31, 2006, NRG had deferred gains of
$16 million in other comprehensive income associated with
these swaps. See also Item 15 Note 11,
Debt and Capital Leases, to the consolidated financial
statements for a further discussion on these interest rate
swaps. In addition, NRG designated an existing fixed-to-floating
interest rate swap, previously as a hedge of NRGs 8%
second priority notes, into a fair value hedge of the Senior
Notes, which NRG closed on February 2, 2006.
Income
Tax Expense
Income tax expense increased by $280 million for the year
ended December 31, 2006, compared to 2005. The effective
tax rate was 37.2% and 38.2% for the year ended
December 31, 2006 and 2005, respectively.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions except otherwise stated)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
865
|
|
|
$
|
110
|
|
Tax at 35%
|
|
|
303
|
|
|
|
39
|
|
State taxes, net of federal benefit
|
|
|
34
|
|
|
|
(1
|
)
|
Foreign operations
|
|
|
(21
|
)
|
|
|
(18
|
)
|
2005 Section 965 taxable dividend
|
|
|
|
|
|
|
5
|
|
Subpart F taxable income
|
|
|
11
|
|
|
|
19
|
|
Valuation allowance, including change in state effective rate
|
|
|
(10
|
)
|
|
|
22
|
|
Change in state effective tax rate
|
|
|
21
|
|
|
|
(22
|
)
|
Claimant reserve settlements
|
|
|
(28
|
)
|
|
|
|
|
Foreign dividends
|
|
|
1
|
|
|
|
|
|
Non-deductible interest
|
|
|
3
|
|
|
|
|
|
Permanent differences, reserves, other
|
|
|
8
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
322
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
37.2
|
%
|
|
|
38.2
|
%
|
The increase in income tax expense was primarily due to an
increase in income.
|
|
|
|
|
Increase in profits income before tax
increased by $755 million, with a corresponding increase of
approximately $299 million in tax expense.
|
88
|
|
|
|
|
Permanent differences the Companys
effective tax rate differs from the US statutory rate of 35% due
to:
|
|
|
|
|
|
Change in state effective tax rate the state
effective tax rate was changed which resulted in a net increase
to income tax expense of approximately $11 million, as
compared to 2005, inclusive of the movement in valuation
allowance resulting from the change in state effective tax rate.
|
|
|
|
Disputed claims reserve during 2006, the
Company made distributions from its disputed claims reserve
decreasing 2006 income tax expense by approximately
$28 million.
|
The effective income tax rate may vary from period to period
depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances
in accordance with SFAS 109. These factors and others,
including the Companys history of pre-tax earnings and
losses, are taken into account in assessing the ability to
realize deferred tax assets.
Income
from Discontinued Operations, Net of Income Tax
Expense
NRG classifies as discontinued operations the income from
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. For the years
ended December 31, 2006 and 2005, NRG recorded income from
discontinued operations, net of income tax expense of
$78 million and $16 million, respectively.
Discontinued operations for the year ended December 31,
2006 were comprised of the results of ITISA, Flinders, Audrain
and Resource Recovery. Discontinued operations for 2005
consisted of the results of ITISA, Flinders, Audrain, Resource
Recovery, Northbrook New York LLC, Northbrook Energy LLC and NRG
McClain LLC. NRG closed on the sale of Flinders during the third
quarter 2006 and recognized an after-tax gain of approximately
$60 million from the sale. Discontinued operations for the
full year 2005 included an $11 million gain on the
disposition of NRGs Northbrook New York and Northbrook
Energy operations.
89
Results
of Operations Regional Discussions
Texas
Region
The following table provides selected financial information for
the Texas region for the year ended December 31, 2007, and
the period ended December 31, 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006(b)
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
2,698
|
|
|
$
|
1,726
|
|
|
|
56
|
%
|
Capacity revenue
|
|
|
363
|
|
|
|
849
|
|
|
|
(57
|
)
|
Risk management activities
|
|
|
(33
|
)
|
|
|
(30
|
)
|
|
|
10
|
|
Contract amortization
|
|
|
219
|
|
|
|
609
|
|
|
|
(64
|
)
|
Hedge Reset
|
|
|
|
|
|
|
(129
|
)
|
|
|
N/A
|
|
Other revenues
|
|
|
40
|
|
|
|
63
|
|
|
|
(37
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
3,287
|
|
|
|
3,088
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
1,181
|
|
|
|
1,276
|
|
|
|
(7
|
)
|
Depreciation and amortization
|
|
|
469
|
|
|
|
413
|
|
|
|
14
|
|
Other operating expenses
|
|
|
668
|
|
|
|
518
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
969
|
|
|
$
|
881
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
49,220
|
|
|
|
46,361
|
|
|
|
6
|
|
MWh generated (in thousands)
|
|
|
47,779
|
|
|
|
44,910
|
|
|
|
6
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
62.00
|
|
|
$
|
63.07
|
|
|
|
(2
|
)
|
Cooling Degree Days, or
CDDs(a)
|
|
|
2,707
|
|
|
|
3,108
|
|
|
|
(13
|
)
|
CDDs 30 year rolling average
|
|
|
2,647
|
|
|
|
2,647
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
1,949
|
|
|
|
1,533
|
|
|
|
27
|
%
|
HDDs 30 year rolling average
|
|
|
1,997
|
|
|
|
1,997
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
|
(b)
|
|
For the period February 2,
2006 to December 31, 2006 only.
|
Operating
Income
For the year ended December 31, 2007, operating income
increased by $88 million compared to 2006, however
excluding January 2007 results, operating income increased by
$21 million. The primary drivers were:
|
|
|
|
|
Energy Revenues for eleven months of 2007
compared to the same period in 2006 were up by
$755 million, $449 million of which was due to the
Hedge Reset transaction, as the average price of the underlying
power contracts increased by $13 per MWh compared to average
contract prices prior to the hedge reset. The balance of the
increase in energy revenues was due to the sale of additional
output as energy rather than under PUCT mandated capacity
auctions.
|
90
This favorable result was offset by:
|
|
|
|
|
Capacity Revenues reduction in capacity
auction sales reduced capacity revenues by approximately
$517 million, excluding January 2007.
|
|
|
|
Contract Amortization the Hedge Reset
transaction decreased contract amortization by approximately
$498 million, excluding January 2007.
|
|
|
|
Gas-fired Generation lower natural gas-fired
generation of approximately 2.7 million MWh, for the
comparable eleven month period in 2007, was a result of cooler
summer weather coupled with increased economic purchases of
energy and ancillary services from ERCOT. Lower sales revenue
for the eleven months was offset by natural lower natural gas
fuel costs of $170 million and cash flow economic hedge
improvements.
|
|
|
|
Development Costs increased by
$44 million in 2007 compared to 2006 largely due to the
development of STP nuclear units 3 and 4 project, including
$2 million of expenses in January 2007. The
$44 million increase also includes $39 million in
reimbursements from a partnership agreement signed in the fourth
quarter 2007.
|
Operating
Revenues
Total operating revenues from the Texas region increased by
$199 million during the year ended December 31, 2007,
compared to 2006. Excluding January 2007, operating revenues
decreased by $56 million. This decrease was due to:
|
|
|
|
|
Energy revenues energy revenues increased by
$972 million of which $217 million was due to the
inclusion of twelve months activity in 2007 compared to eleven
months in 2006. Of the remaining $755 million increase,
$449 million was due to the Hedge Reset transaction which
resulted in higher 2007 average contracted prices of
approximately $13 per MWh. In addition, revenues from
8.8 million MWh of generation moved from capacity revenue
to energy revenue. Prior to the Acquisition, PUCT regulations
required that NRG Texas sell 15% of its capacity by auction at
reduced rates. In March 2006, the PUCT accepted NRGs
request to no longer participate in these auctions and that
capacity is now being sold in the merchant market. These
favorable results were partially offset by lower sales from
natural gas-fired units due to a cooler summer which resulted in
lower natural gas-fired generation of approximately
2.7 million MWh.
|
|
|
|
Other revenues the regions other
revenues decreased by $27 million for the eleven months of
2007 compared to 2006. This was due to a decrease in
intercompany emission allowance sales of $40 million and a
$19 million decrease in physical gas sales. This
$59 million decrease was offset by a $33 million
increase in ancillary services revenue due to a change in
strategy to more actively provide ancillary services in the
Texas region.
|
|
|
|
Capacity revenues capacity revenues decreased
by $517 million, excluding $31 million incurred in
January 2007. This decrease was due to the reduction of capacity
auction sales mandated by the PUCT in prior years as described
above.
|
|
|
|
Contract amortization revenues from contract
amortization excluding January 2007 decreased by
$405 million primarily due to the write-off of
out-of-market power contracts during the fourth quarter 2006
related to the Hedge Reset transaction.
|
Risk management activities The Texas region
recorded a total of $33 million in derivative losses for
the year ended December 31, 2007, compared to a
$30 million loss for the year ended December 31, 2006.
The Texas regions 2007 derivative loss was comprised of
$66 million of mark-to-market losses and $33 million
in settled gains, or financial revenue. Of the $66 million
of mark-to-market losses, $83 million represents the
reversal of mark-to-market gains previously recognized on
economic hedges and $1 million from the reversal of
mark-to-market gains previously recognized on trading activity.
Both of these losses ultimately settled as financial revenues
during 2007. The $19 million gain from economic hedge
positions was comprised of an $8 million increase in the
value of forward sales of electricity and fuel due to favorable
power and natural gas prices and a $11 million gain
91
from hedge accounting ineffectiveness. This ineffectiveness was
primarily related to gas swaps and collars due to a change in
the correlation between natural gas and power prices.
Cost
of Energy
Cost of energy for the Texas region decreased by
$95 million for the year ended December 31, 2007,
compared to 2006. This included an additional months
expense for January 2007 of $96 million, without which cost
of energy would have decreased by $191 million. This was
due to:
|
|
|
|
|
Fuel expense natural gas expense decreased by
$170 million, excluding the January 2007 expense of
$27 million, due to a decrease of 2.7 million MWh in
natural gas-fired generation as a result of cooler summer
weather, coupled with greater economic purchases of energy and
ancillary services from ERCOT and increased baseload generation.
Coal expenses, excluding January 2007, decreased by
$13 million due to an 9% reduction in average contracted
coal prices in 2007, despite a 1.1 million MWh increase in
coal-fired generation at the regions W.A. Parish and
Limestone plants.
|
|
|
|
Purchased ancillary service increased by
approximately $34 million due to the favorable market
prices in purchasing this service in the market compared to
providing the service from internal resources causing an
associated decrease in natural gas expense.
|
|
|
|
Fuel contract Amortization decreased by
approximately $43 million, excluding January 2007, due to
declining forward fuel price curves below the contracted prices
used at acquisition in February 2006.
|
Other
Operating Expenses
Other operating expenses for the Texas region increased by
$150 million for the year ended December 31, 2007
compared to 2006. This included an additional months
expense for January 2007, of $53 million, without which
other operating expenses would have increased by
$97 million. This was due to:
|
|
|
|
|
Development costs on September 24, 2007,
NRG filed a COLA with the NRC. The Company incurred
$91 million in development costs related to STP nuclear
unit 3 and 4 project in 2007, including $2 million in
January 2007, compared to development costs of $14 million
in 2006. Of the $91 million incurred this year,
$39 million was reimbursed through a partnership agreement
in the fourth quarter 2007. Fossil development costs was
$6 million in 2007.
|
|
|
|
Plant O&M expense increased by
$25 million, excluding January 2007, due to increased
maintenance associated with planned outages and fuel handling at
W.A. Parish, increased maintenance related to higher utilization
in 2006 of the regions natural gas fleet, and retirement
of older assets.
|
|
|
|
Corporate allocations were higher by
approximately $16 million.
|
|
|
|
Property tax expense increased by
approximately $10 million related to the Texas acquisition.
|
92
Northeast
Region
2007
compared to 2006
The following table provides selected financial information for
the Northeast region for the years ended December 31, 2007
and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
1,104
|
|
|
$
|
966
|
|
|
|
14
|
%
|
Capacity revenue
|
|
|
402
|
|
|
|
321
|
|
|
|
25
|
|
Risk management activities
|
|
|
27
|
|
|
|
144
|
|
|
|
(81
|
)
|
Other revenues
|
|
|
72
|
|
|
|
112
|
|
|
|
(36
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,605
|
|
|
|
1,543
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
641
|
|
|
|
615
|
|
|
|
4
|
|
Depreciation and amortization
|
|
|
102
|
|
|
|
89
|
|
|
|
15
|
|
Other operating expenses
|
|
|
404
|
|
|
|
378
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
458
|
|
|
$
|
461
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
14,163
|
|
|
|
13,309
|
|
|
|
6
|
|
MWh generated (in thousands)
|
|
|
14,163
|
|
|
|
13,309
|
|
|
|
6
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
76.37
|
|
|
$
|
67.73
|
|
|
|
13
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
702
|
|
|
|
653
|
|
|
|
8
|
|
CDDs 30 year rolling average
|
|
|
537
|
|
|
|
537
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
6,074
|
|
|
|
5,417
|
|
|
|
12
|
%
|
HDDs 30 year rolling average
|
|
|
6,261
|
|
|
|
6,261
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income decreased by $3 million for the year ended
December 31, 2007, compared to 2006, due to:
|
|
|
|
|
Cost of energy increased by approximately
$26 million due to a 6% increase in generation at the
regions coal and natural gas-fired plants.
|
|
|
|
Other operating expenses increased by
$26 million primarily due to increased maintenance and
staffing costs combined with higher property tax.
|
|
|
|
Depreciation increased by $13 million
reflecting the additional depreciation expense following the
reduction in estimated useful lives of certain components of the
regions power plants as a result of new environmental
regulation.
|
|
|
|
Offset by higher operating revenues of
approximately $62 million due to increased generation,
favorable pricing and the favorable impact from new capacity
markets. This was partially offset by lower gains in the
regions risk management activities and lower sales of
emission allowances due to a 28% reduction in market prices.
|
93
Operating
Revenues
Operating revenues increased by $62 million for the year
ended December 31, 2007, compared to 2006, due to:
|
|
|
|
|
Energy revenues increased by approximately
$138 million, of which $61 million was due to
increased generation, and $88 million due to a 9% increase
in average realized market prices partially offset by an
$11 million reduction in contracted bilateral energy
revenues.
|
|
|
|
|
|
Generation increased by 6%, primarily driven
by increases at the regions Arthur Kill, Oswego and Indian
River plants. The Arthur Kill plant increased generation by 448
thousand MWh due to transmission constraints around New York
City, the Oswego plants generation increased by 127
thousand MWh due to a colder winter during 2007 compared to
2006, and Indian River plants generation increased by 418
thousand MWh due to stronger pricing and fewer outages.
|
|
|
|
Price on average, realized prices in the
Northeast increased by 9% due to a mix of higher priced New York
City generation coupled with improved economic energy hedge
trading resulting in a $37 million increase in energy
revenues.
|
|
|
|
|
|
Capacity revenues increased by
$81 million, of which $39 million was from the
regions NEPOOL assets, $36 million from the
regions PJM assets and $6 million from the
regions New York Rest of State assets.
|
|
|
|
|
|
NEPOOL The regions NEPOOL assets
benefited from the new LFRM market and transition capacity
market, both of which were introduced in the fourth quarter
2006. Capacity revenues increased by $24 million from the
LFRM market and $18 million from transition capacity
payments, which were partially offset by a $3 million
reduction due to the expiration of an RMR agreement for the
regions Devon plant on December 31, 2006 and by RMR
payments from the regions Norwalk plant which began in the
third quarter 2007.
|
|
|
|
PJM On June 1, 2007, the new RPM
capacity market became effective in PJM increasing capacity
revenues by approximately $36 million.
|
|
|
|
NYISO New York Rest of State capacity prices
increased by 75% as load requirement growth increased demand for
capacity. This was coupled with the impact from the new capacity
markets in NEPOOL which reduced exported supply into the New
York market that further improved the supply/demand dynamics.
|
These were partially offset by:
|
|
|
|
|
Risk management activities The Northeast
region recorded $27 million in derivative gain for the year
ended December 31, 2007 compared to a $144 million
gain for the year ended December 31, 2006. The
regions 2007 derivative gain was comprised of
$16 million of mark-to-market losses and $43 million
in settled gains, or financial revenue. Of the $16 million
of mark-to-market losses, $45 million represents the
reversal of mark-to-market gains previously recognized on
economic hedges and $12 million from the reversal of
mark-to-market gains previously recognized on trading activity.
Both of these losses ultimately settled as financial revenues
during 2007. The region also recognized a $15 million
unrealized gain from economic hedge positions which was
comprised primarily of a $13 million increase in the value
of forward sales of electricity and fuel due to favorable power
and gas prices. The region also recognized a $26 million
unrealized gain associated with the Companys trading
activity. The $144 million derivative gain for the year
ended December 31, 2006 was comprised of a
$154 million unrealized mark-to-market gain and
$10 million in settled losses. Most of these unrealized
gains reversed out in 2007.
|
|
|
|
Other revenues decreased by $40 million,
of which approximately $48 million was due to reduced
activity in the trading of emission allowances following both an
increase in generation and a 28% decrease in market prices. This
decrease was partially offset by an $11 million increase in
physical gas sales to third parties due to favorable trading
opportunities in the market.
|
94
Cost
of Energy
|
|
|
|
|
Cost of energy increased by $26 million for the year ended
December 31, 2007, compared to 2006, primarily due to
$30 million in higher natural gas costs related to
increased generation at the regions Arthur Kill plant due
to its locational advantage to New York City following
transmission constraints during the last three quarters of 2007.
|
Other
Operating Expenses
Other operating expenses increased by $26 million for the
year ended December 31, 2007, compared to 2006, due to:
|
|
|
|
|
Plant O&M spending of $15 million
due to increased plant staffing costs of $7 million,
increased maintenance costs of $6 million and increased
environmental remediation costs of $2 million.
|
|
|
|
Property tax increased by approximately
$3 million due to a favorable tax decision in 2006 related
to NYC assets of $10 million partially offset by a tax law
change the same year that resulted in a reduction of property
tax receivable of $5 million in 2006 and a $2 million
reduction in property taxes at the New England plants in 2007.
|
|
|
|
Regional G&A expenditures Regional
staffing and benefits increased by $3 million primarily
related to the regions RepoweringNRG development
efforts while corporate allocations increased by $5 million.
|
2006
compared to 2005
The following table provides selected financial information for
the Northeast region for the years ended December 31, 2006
and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
966
|
|
|
$
|
1,444
|
|
|
|
(33
|
)%
|
Capacity revenue
|
|
|
321
|
|
|
|
291
|
|
|
|
10
|
|
Risk management activities
|
|
|
144
|
|
|
|
(285
|
)
|
|
|
N/A
|
|
Other revenues
|
|
|
112
|
|
|
|
104
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,543
|
|
|
|
1,554
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
615
|
|
|
|
869
|
|
|
|
(29
|
)
|
Depreciation and amortization
|
|
|
89
|
|
|
|
74
|
|
|
|
20
|
|
Other operating expenses
|
|
$
|
378
|
|
|
$
|
393
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
461
|
|
|
|
218
|
|
|
|
111
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
13,309
|
|
|
|
16,246
|
|
|
|
(18
|
)
|
MWh generated (in thousands)
|
|
|
13,309
|
|
|
|
16,246
|
|
|
|
(18
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
67.73
|
|
|
$
|
91.98
|
|
|
|
(26
|
)
|
Cooling Degree Days, or
CDDs(a)
|
|
|
653
|
|
|
|
801
|
|
|
|
(18
|
)
|
CDDs 30 year rolling average
|
|
|
537
|
|
|
|
537
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
5,417
|
|
|
|
6,162
|
|
|
|
(12
|
)%
|
HDDs 30 year rolling average
|
|
|
6,261
|
|
|
|
6,261
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean
|
95
|
|
|
|
|
temperature for a particular day is
below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a
period of time are calculated by adding the CDDs/HDDs for each
day during the period.
|
Operating
Income
For the year ended December 31, 2006, operating income for
the Northeast region was $461 million, compared to
$218 million for the same period in 2005, an increase of
$243 million. This was due to:
|
|
|
|
|
Risk management activities of
$144 million in mark-to-market gains from risk management
activities, compared to a $285 million loss for the year
ended December 31, 2005. The favorable gain from risk
management activities was largely due to weak forward power
prices, which resulted in substantial unrealized gains in the
regions forward positions for the year ended
December 31, 2006. In 2005, forward mark-to-market losses
and settlement of positions at losses was related to the
run-up in
natural gas prices which occurred in the wake of hurricanes
Katrina and Rita.
|
|
|
|
Natural gas costs mild weather reduced demand
for natural gas, with average prices falling as much as 22% year
over year. Falling natural gas prices reduced annual average
power prices in the New York, NEPOOL and PJM markets by 23%, 20%
and 19%, respectively.
|
This was partially offset by:
|
|
|
|
|
Generation mild weather also led to an 18%
decline in power generation for the Companys Northeast
region to 13.3 million MWh in 2006, compared to
16.2 million MWh in 2005. Generation from the regions
oil-fired assets declined by nearly 2 million MWh,
representing 66% of the overall Northeast regions
generation decrease. Half of this decline was attributable to
the regions Western New York plants, which had more run
time in 2005 due to that years cold January winter.
|
Total
Operating Revenues
Total operating revenues from NRGs Northeast region
totaled $1,543 million for the year ended December 31,
2006, compared to $1,554 million for the same period in
2005, a decrease of $11 million.
|
|
|
|
|
Energy revenues decreased by
$478 million to $966 million due to lower generation
from the regions Oswego plant and lower realized price
from generation from the regions baseload coal plants
which reduced energy revenues by $318 million. In addition,
the region had $23 million of adjustments in 2005 relating
to prior year NYISO settlements and a $6 million reversal
of a reserve due to a favorable court decision regarding
spinning reserve payments.
|
|
|
|
Capacity revenues increased to
$321 million, compared to $291 million for the same
period in 2005. Of this increase, $28 million was due to
higher capacity revenues in the New York State market. New York
capacity revenues outside of New York City drove the increase in
2006, as increased demand for capacity, coupled with a decline
in imports of capacity into the market, pushed clearing prices
higher. Capacity prices were also favorably impacted in the
regions New England market by $16 million due to the
new LFRM market and the new transition capacity market. The
Northeast region also earned $9 million more in RMR
payments in 2006 with the approval of new RMR agreements. These
were partially offset by $23 million of reserve reversals
in 2005 following the settlement of prior year RMR agreements.
|
|
|
|
Other revenues which include emission
allowance sales, natural gas sales, and expense recovery
revenues, totaled $112 million for the year ended
December 31, 2006, compared to $104 million in the
same period in 2005, an increase of $8 million. This
increase was primarily related to $17 million in higher
emission allowance sales as the Company sold emission allowances
in lieu of generation during the first quarter 2006. Higher
emission allowance revenues were partially offset by lower gas
sales of $2 million, lower ancillary revenues of
$3 million and lack of cost recovery revenues of
$5 million related to the 2005 RMR agreements.
|
|
|
|
Risk management activity The total derivative
gain for the year was $144 million, comprised of
$10 million in financial revenue losses and
$154 million of unrealized mark-to-market gains. The
$10 million loss of financial revenues represents the
settled value for the year of all financial instruments,
|
96
including financial swaps and options on power. Of the
$154 million of mark-to-market gains, $50 million
represented the fair value of forward sales of electricity and
fuel transactions to support the regions physical asset
position, with $14 million of mark-to-market losses related
to trading activity. In addition, $90 million represented
the reversal of mark-to-market losses, which ultimately settled
as financial revenues. In 2005, the total derivative loss was
$285 million, comprised of $132 million in financial
revenue losses and $153 million mark-to-market losses.
Cost
of Energy
|
|
|
|
|
Cost of energy decreased by $254 million
to $615 million for the year ended December 31, 2006
due to 18% lower generation from the regions generation
assets which resulted in a $143 million decrease in oil
fuel costs, as lower oil-fired generation accounted for 66% of
the total decline in generation volume. Gas fuel costs for the
Northeast region decreased by $101 million. Coal costs
increased by $11 million, despite slightly lower
generation, primarily due to higher rail transportation costs.
Emission allowance amortization costs declined in 2006 by
$18 million, primarily due to lower generation, which
resulted in lower consumption of emission allowances.
|
Other
Operating Expenses
Other operating expenses for the Northeast region were
$378 million for the year ended December 31, 2006, a
decrease of $15 million compared to the same period in
2005. This was due to:
|
|
|
|
|
Plant utilities decreased by
$20 million. This was primarily due to a
favorable court decision in the second quarter 2006 that allowed
the Northeast region to reverse into earnings $18 million
of previously accrued station power expense.
|
|
|
|
Insurance costs decreased by $8 million
due to favorable renewals.
|
|
|
|
Corporate allocations decreased by
$14 million due to the inclusion of the Texas region in our
allocation methodology.
|
Offsetting these decreases were:
|
|
|
|
|
Maintenance expense increased by
$15 million in 2006 primarily due to more extensive boiler
tube work at the regions Dunkirk and Arthur Kill plants to
reduce forced outage hours, additional turbine maintenance and
oil tank repair costs at the regions Oswego facility.
|
|
|
|
Development costs increased by
$8 million to advance the regions
RepoweringNRG efforts.
|
97
South
Central Region
2007
compared to 2006
The following table provides selected financial information for
the South Central region for the years ended December 31,
2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
404
|
|
|
$
|
334
|
|
|
|
21
|
%
|
Capacity revenue
|
|
|
221
|
|
|
|
199
|
|
|
|
11
|
|
Risk management activities
|
|
|
10
|
|
|
|
13
|
|
|
|
(23
|
)
|
Contract amortization
|
|
|
23
|
|
|
|
19
|
|
|
|
21
|
|
Other revenues
|
|
|
|
|
|
|
5
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
658
|
|
|
|
570
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
412
|
|
|
|
308
|
|
|
|
34
|
|
Depreciation and amortization
|
|
|
68
|
|
|
|
68
|
|
|
|
|
|
Other operating expenses
|
|
|
121
|
|
|
|
89
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
57
|
|
|
$
|
105
|
|
|
|
(46
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
12,452
|
|
|
|
11,845
|
|
|
|
5
|
|
MWh generated (in thousands)
|
|
|
10,930
|
|
|
|
11,036
|
|
|
|
(1
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
59.62
|
|
|
$
|
56.18
|
|
|
|
6
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
1,963
|
|
|
|
1,797
|
|
|
|
9
|
|
CDDs 30 year rolling average
|
|
|
1,547
|
|
|
|
1,547
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,236
|
|
|
|
3,169
|
|
|
|
2
|
%
|
HDDs 30 year rolling average
|
|
|
3,604
|
|
|
|
3,604
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income for the region declined by $48 million for
the year ended December 31, 2007, compared to 2006, due to
higher operating expenses, despite a 1% decrease in generation
at the regions Big Cajun II plant.
Operating
Revenues
Operating revenues increased by $88 million for the year
ended December 31, 2007, compared to 2006, due to:
|
|
|
|
|
Energy revenues increased by approximately
$70 million due to a new contract which contributed
$69 million in contract energy revenues, increasing
contract sales volume by approximately 1.3 million MWh. A
contractual change in the fuel adjustment charge for the
regions cooperative customers increased energy revenues by
an additional $11 million. This was offset by a
$12 million decrease in merchant energy revenue as a result
of satisfying increasing load requirement from the new contract.
|
98
|
|
|
|
|
Capacity revenues increased by approximately
$22 million, of which $15 million was due to higher
rates as a result of the region setting new summer peaks in 2006
and 2007; the new system peak of 2,123 MW set in August
2007 will continue to impact capacity revenue in the first half
of 2008. Higher network transmission costs, which are passed
through to the regions cooperative customers, also
increased capacity revenues by $6 million. Improved market
conditions in PJM resulted in an increase of $3 million in
merchant capacity revenue from the Rockford plants.
|
Cost
of Energy
Cost of energy increased by $104 million for the year ended
December 31, 2007, compared to 2006, due to:
|
|
|
|
|
Purchased energy increased by approximately
$69 million as planned and maintenance outage hours at the
regions Big Cajun II facility increased by
1,209 hours, primarily due to the planned turbine/generator
outage at the Big Cajun II Unit 3 facility in the fourth
quarter 2007. These increases were offset by a drop of $2.53/MWh
in realized purchased power prices.
|
|
|
|
Coal costs increased by approximately
$17 million, of which approximately $11 million was
due to a 9% increase in coal prices and $7 million due to
higher coal transportation costs.
|
|
|
|
Transmission costs increased by approximately
$16 million. Network transmission costs, which are
passed-through to the regions cooperative customers,
increased by $6 million due to load growth and increased
utilization of the Entergy transmission system. Point-to-point
transmission costs to support off-system sales increased by
$10 million.
|
Other
Operating Expenses
Other operating expenses increased by approximately
$32 million for the year ended December 31, 2007,
compared to 2006, due to:
|
|
|
|
|
Maintenance expense increased by
approximately $19 million as the scope of work on planned
outages were more extensive in 2007. The Big Cajun II Unit
3 facility incurred a major planned outage in the fourth quarter
2007, during which the generator was rewound, turbine controls
were replaced with a modern digital control system, and the
turbine steam path was replaced with a high-efficiency design.
Asset disposals in conjunction with the outage added
$4 million.
|
|
|
|
Franchise tax Louisiana state franchise tax
increased by approximately $6 million due to an increased
assessment based on the Companys total debt and equity.
The Companys total debt and equity increased significantly
following the acquisition of Texas Genco LLC.
|
99
2006
compared to 2005
The following table provides selected financial information for
the South Central region for the years ended December 31,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
334
|
|
|
$
|
339
|
|
|
|
(1
|
)%
|
Capacity revenue
|
|
|
199
|
|
|
|
190
|
|
|
|
5
|
|
Risk management activities
|
|
|
13
|
|
|
|
(2
|
)
|
|
|
N/A
|
|
Contract amortization
|
|
|
19
|
|
|
|
9
|
|
|
|
111
|
|
Other revenues
|
|
|
5
|
|
|
|
24
|
|
|
|
(79
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
570
|
|
|
|
560
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
308
|
|
|
|
374
|
|
|
|
(18
|
)
|
Depreciation and amortization
|
|
|
68
|
|
|
|
67
|
|
|
|
1
|
|
Other operating expenses
|
|
|
89
|
|
|
|
111
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
105
|
|
|
$
|
8
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
11,845
|
|
|
|
11,771
|
|
|
|
1
|
|
MWh generated (in thousands)
|
|
|
11,036
|
|
|
|
10,009
|
|
|
|
10
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
56.18
|
|
|
$
|
69.96
|
|
|
|
(20
|
)
|
Cooling Degree Days, or
CDDs(a)
|
|
|
1,797
|
|
|
|
1,811
|
|
|
|
(1
|
)
|
CDDs 30 year rolling average
|
|
|
1,547
|
|
|
|
1,547
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,169
|
|
|
|
3,366
|
|
|
|
(6
|
)%
|
HDDs 30 year rolling average
|
|
|
3,604
|
|
|
|
3,604
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
The South Central region realized operating income of
$105 million for the year ended December 31, 2006
compared to operating income of $8 million for the same
period in 2005, an increase of $97 million. This was due to:
|
|
|
|
|
Better plant availability due to lower
planned and forced outages in 2006, which resulted in 11% higher
coal generation in 2006 than 2005. The Big Cajun II
facility achieved an EFOR of 3.13% in 2006 compared to 6.56% in
2005, resulting in 907 fewer forced outage hours in 2006.
|
|
|
|
Lower outages In addition, the Big
Cajun II coal units experienced 826 less planned outage
hours in 2006 than in 2005. The forced outages in 2005 occurred
primarily during the peak summer months when contract load is
highest, requiring increased energy purchases than in 2006.
These fewer planned outages in 2006 also resulted in
$12 million of lower major maintenance expense, which
benefited operating income.
|
|
|
|
Favorable price spreads allowed for resale of
power received from the regions tolling agreements,
providing additional margins.
|
100
Total
Operating Revenues
Operating revenues increased by $10 million in 2006
compared to 2005. This was due to:
|
|
|
|
|
Energy revenues increased sales to the
regions contract customers were offset by lower sales in
the merchant market.
|
|
|
|
Capacity revenues were $9 million higher
for the year ended December 31, 2006 than in the same
period for 2005, as the peak of 2011 MW set by the
regions cooperative customers in August 2006 impacted
capacity revenue in the latter half of 2006.
|
|
|
|
Risk management activities The region
recognized $13 million from risk management activities in
2006.
|
|
|
|
Contract amortization increased by
$10 million due to increased megawatt hour sales to
contract customers and the expiration of the Rockford contract
in 2005.
|
|
|
|
Other revenues decreased by $19 million
from 2005 levels, primarily due to $23 million in lower gas
sales relating to the regions tolling agreements.
|
Cost
of Energy
Cost of energy for the South Central region was
$308 million for the year ended December 31, 2006,
compared to $374 million for the same period in 2005, a
decrease of $66 million. This was due to:
|
|
|
|
|
Lower purchased power the cost of purchased
power, including the costs of the regions tolling
agreements, was $74 million in 2006, a decrease of
$71 million from 2005. This decrease was primarily due to
fewer forced outages at the regions baseload coal plants
in 2006 and the impact of netting energy purchases and resale. A
drop in average purchased power prices by $9/MWh from 2005 to
2006 also contributed to the reduction in purchased power costs.
As a result of improved plant availability, energy purchased by
the South Central region to support load contracts dropped 16%.
The South Central region increased its use of generation from
tolled facilities in 2006; tolled combined cycle plants
contributed 1,451,758 MWh to the regions energy
resources in 2006 compared to 474,386 MWh in 2005. The
tolling agreements further contributed to the regions
results as the spread between gas costs and energy costs widened
in the summer of 2006.
|
This was partially offset by:
|
|
|
|
|
Transmission costs increased by
$7 million due to a combination of contractual increases in
network transmission rates and higher peaks in 2006.
|
|
|
|
Coal costs increased by $25 million,
reflecting contractual increases in coal commodity costs and
higher plant availability in 2006.
|
Other
Operating Expenses
Other operating expenses for the South Central region for the
year ended December 31, 2006 was $89 million, a
reduction of $22 million compared to the year ended
December 31, 2005. The reduction was primarily due to lower
major maintenance costs, which dropped by $12 million due
to fewer planned outages at the regions coal plant in 2006
and lower insurance costs, which were $3 million less in
2006 due to lower premiums.
101
West
Region
2007
compared to 2006
The following table provides selected financial information for
the West region for the years ended December 31, 2007, and
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
4
|
|
|
$
|
75
|
|
|
|
(95
|
)%
|
Capacity revenue
|
|
|
122
|
|
|
|
68
|
|
|
|
79
|
|
Risk management activities
|
|
|
|
|
|
|
(3
|
)
|
|
|
N/A
|
|
Other revenues
|
|
|
1
|
|
|
|
6
|
|
|
|
(83
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
127
|
|
|
|
146
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
5
|
|
|
|
80
|
|
|
|
(94
|
)
|
Depreciation and amortization
|
|
|
3
|
|
|
|
3
|
|
|
|
|
|
Other operating expenses
|
|
|
80
|
|
|
|
55
|
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
39
|
|
|
$
|
8
|
|
|
|
388
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
1,246
|
|
|
|
1,901
|
|
|
|
(34
|
)
|
MWh generated (in thousands)
|
|
|
1,246
|
|
|
|
1,901
|
|
|
|
(34
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
66.52
|
|
|
$
|
61.54
|
|
|
|
8
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
785
|
|
|
|
926
|
|
|
|
(15
|
)
|
CDDs 30 year rolling average
|
|
|
704
|
|
|
|
704
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,048
|
|
|
|
3,001
|
|
|
|
2
|
%
|
HDDs 30 year rolling average
|
|
|
3,228
|
|
|
|
3,228
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income increased by $31 million for the year
ended December 31, 2007, compared to 2006. Excluding the
consolidation of WCPs results following the acquisition of
Dynegys 50% interest on March 31, 2006, operating
income increased by $24 million, due to:
|
|
|
|
|
Capacity revenues increased by approximately
$28 million, excluding the first quarter 2007, due to new
tolling agreements at the regions Encina and Long Beach
plants:
|
|
|
|
|
|
Encina In January 2007, NRG signed a new
tolling agreement for the regions Encina plant which
contributed $15 million in capacity revenues for the year
ended December 31, 2007.
|
|
|
|
Long Beach On August 1, 2007, NRG
successfully completed the repowering of a 260 MW natural
gas-fueled generating plant at its Long Beach generating
facility, which contributed approximately $13 million in
capacity revenues for the year ended December 31, 2007.
|
102
|
|
|
|
|
Cost of energy decreased by $76 million,
excluding the first quarter 2007, due to the new tolling
agreement entered into at the Encina plant in 2007, which
required the counterparty to supply their own fuel. Under the
previous arrangement in 2006, the plant supplied the fuel.
|
This increase was offset by:
|
|
|
|
|
Energy revenues decreased by approximately
$72 million, excluding the first quarter 2007, primarily
due to the tolling agreement at the Encina plant that has
resulted in the receipt of fixed monthly capacity payment in
return for the right to schedule and dispatch from the plant.
The Encina tolling agreement replaced the RMR agreement under
which the plant was called upon to generate revenues for such
dispatch.
|
|
|
|
O&M expense increased by approximately
$6 million, excluding the first quarter 2007, primarily due
to increases in labor costs, major maintenance and auxiliary
power.
|
|
|
|
Development expenses increased by
$4 million, reflecting RepoweringNRG initiatives at
the regions El Segundo and Encina sites.
|
|
|
|
Other revenues decreased ancillary service
revenue of $3 million at the Encina plant due to the new
tolling agreement that consigns ancillary service revenue to the
counterparty in exchange for a fixed monthly capacity payment.
|
2006
compared to 2005
The following table provides selected financial information for
the West region for the years ended December 31, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
75
|
|
|
$
|
1
|
|
|
|
N/A
|
|
Capacity revenue
|
|
|
68
|
|
|
|
|
|
|
|
N/A
|
|
Risk management activities
|
|
|
(3
|
)
|
|
|
|
|
|
|
N/A
|
|
Other revenues
|
|
|
6
|
|
|
|
3
|
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
146
|
|
|
|
4
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
80
|
|
|
|
1
|
|
|
|
N/A
|
|
Depreciation and amortization
|
|
|
3
|
|
|
|
1
|
|
|
|
200
|
|
Other operating expenses
|
|
|
55
|
|
|
|
8
|
|
|
|
588
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(loss)
|
|
$
|
8
|
|
|
$
|
(6
|
)
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
1,901
|
|
|
|
6
|
|
|
|
N/A
|
|
MWh generated (in thousands)
|
|
|
1,901
|
|
|
|
6
|
|
|
|
N/A
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
61.54
|
|
|
$
|
71.06
|
|
|
|
(13
|
)
|
Cooling Degree Days, or CDDs(a)
|
|
|
926
|
|
|
|
775
|
|
|
|
19
|
|
CDDs 30 year rolling average
|
|
|
704
|
|
|
|
704
|
|
|
|
|
|
Heating Degree Days, or HDDs(a)
|
|
|
3,001
|
|
|
|
2,842
|
|
|
|
6
|
%
|
HDDs 30 year rolling average
|
|
|
3,228
|
|
|
|
3,228
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
103
Operating
Income
For the year ended December 31, 2006, operating income for
the West region was approximately $8 million, compared to a
loss of $6 million for the year ended December 31,
2005. The 2006 gain in operating income was primarily due to
NRGs acquisition of Dynegys 50% interest of WCP. The
California high-voltage power grid handled an all time record
peak demand on July 24, 2006 at 50,270 MW, with the
previous record peak demand of 45,431 MW set on
July 20, 2005.
Total
Operating Revenues
Total operating revenues for the year ended December 31,
2006 were $146 million, comprised of $75 million in
energy revenues, of which 39% were contracted, and
$68 million in capacity revenues. This compares to
$4 million in operating revenues, comprised of
$1 million in energy revenues and $3 million in other
revenues for the year ended December 31, 2005.
Cost
of Energy
Cost of energy for the year ended December 31, 2006, was
approximately $80 million, consisting primarily of gas
costs. For the year ended December 31, 2005, cost of energy
for the West region was $1 million.
Other
Operating Expenses
Operating expenses for the West region for the year ended
December 31, 2006 were $55 million, or 38% of the
regions total operating revenues. These costs included
$32 million in operating and maintenance costs, of which
$10 million was related to normal maintenance expenses
associated with outage work. The region also incurred
approximately $19 million in G&A expenses, of which
$4 million was related to development costs associated with
the Companys RepoweringNRG program and
approximately $3 million in corporate allocations. The
increase was primarily due to the consolidation of WCP,
development spending, and NRG cost allocations. This compares to
$8 million for the year ended December 31, 2005.
Liquidity
and Capital Resources
Liquidity
Position
As of December 31, 2007 and 2006, NRGs liquidity was
approximately $2.7 billion and $2.2 billion,
respectively, comprised of the following:
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
1,132
|
|
|
$
|
795
|
|
Restricted cash
|
|
|
29
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
Total cash
|
|
|
1,161
|
|
|
|
839
|
|
|
|
|
|
|
|
|
|
|
Synthetic letter of credit availability
|
|
|
557
|
|
|
|
533
|
|
Revolver credit facility availability
|
|
|
997
|
|
|
|
855
|
|
|
|
|
|
|
|
|
|
|
Total liquidity
|
|
$
|
2,715
|
|
|
$
|
2,227
|
|
|
|
|
|
|
|
|
|
|
Management believes that these amounts and cash flows from
operations will be adequate to finance operating and maintenance
capital expenditures, to fund dividends to NRGs preferred
shareholders and other liquidity commitments. Management
continues to regularly monitor the companys ability to
finance the needs of its operating, financing and investing
activity in a manner consistent with its intention to maintain a
steady debt to capital ratio in the range of
45-60%.
Credit
Ratings
Credit-rating agencies rate a firms public debt
securities. These ratings are utilized by the debt markets in
evaluating a firms credit risk. Ratings influence the
price paid to issue new debt securities by indicating to the
104
market the Companys ability to pay principal, interest,
and preferred dividends. Rating agencies evaluate a firms
industry, cash flow, leverage, liquidity, and hedge profile,
among other factors, in their credit analysis of a firms
credit risk.
The following table summarizes the credit ratings for NRG
Energy, Inc., its term loan and its senior notes as of
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
S&P
|
|
|
Moodys
|
|
|
Fitch
|
|
|
NRG Energy, Inc.
|
|
|
B+
|
|
|
|
Ba3
|
|
|
|
B
|
|
7.375% Senior Notes, due 2016, 2017
|
|
|
B
|
|
|
|
B1
|
|
|
|
B+
|
|
7.25% Senior Notes due 2014
|
|
|
B
|
|
|
|
B1
|
|
|
|
B+
|
|
Term Loan
|
|
|
BB
|
|
|
|
Ba1
|
|
|
|
BB
|
|
SOURCES
OF FUNDS
The principal sources of liquidity for NRGs future
operating and capital expenditures are expected to be derived
from new and existing financing arrangements, asset sales,
existing cash on hand and cash flows from operations.
Financing
Arrangements
Senior Credit Facility Amendment
On June 8, 2007, NRG completed a $4.4 billion
refinancing of the Companys then existing Senior Credit
Facility which comprised a senior first priority secured term
loan, or the Term Loan Facility, a $1.0 billion senior
first priority secured revolving credit facility, or the
Revolving Credit Facility, and a senior first priority secured
synthetic letter of credit facility, or the Letter of Credit
Facility. The refinancing resulted in a 0.25% reduction on the
spread that the Company pays on its Term B loan and Synthetic
Letter of Credit Facility, a $200 million reduction in the
Synthetic Letter of Credit Facility to $1.3 billion, and
various amendments to provide improved flexibility, efficiency
for returning capital to shareholders, asset repowering and
investment opportunities. The pricing on the Companys Term
B loan and Synthetic Letters of Credit Facility was also subject
to further reductions upon the achievement of certain financial
ratios. The refinancing resulted in a charge of approximately
$35 million to the Companys results of operations for
the year ended December 31, 2007, which was primarily
related to the write-off of previously deferred financing costs.
On August 6, 2007, NRG entered into an agreement with BNP
Paribas, or BNP, whereby BNP has agreed to be an issuing bank
under the revolver portion of the Companys Senior Credit
Facility. BNP has agreed to issue up to $350 million in
letters of credit under the revolver. In addition, on
January 30, 2008, NRG entered into an agreement with Bank
of America, whereby Bank of America has also agreed to be an
issuing bank under the revolver portion of the Companys
Senior Credit Facility. Bank of America has agreed to issue up
to $250 million of letter of credit under the revolver.
This increases the amount of unfunded letters of credit the
Company can issue under its Revolving Credit Facility to
$900 million. In addition, NRG is permitted to issue
additional letters of credit of up to $100 million under
the Senior Credit Facility through other financial institutions.
On December 31, 2007, the Company used cash on hand to
prepay, without penalty, $300 million of its Term B loan
under the Senior Credit Facility. With this prepayment, the
Company has achieved a 3.5:1 threshold for its corporate
leverage ratio as defined by its credit agreement, which would
result in a 0.25% reduction in the interest rate on both its
Term loan B and Synthetic Letter of Credit Facility which is
expected to result in approximately $8 million in pre-tax
interest savings during 2008. The prepayment will be credited
against the Companys mandatory annual prepayment which is
required in March 2008 under the Senior Credit Facility.
Beginning 2008, NRG must offer a portion of its excess cash flow
(as defined in the Senior Credit Facility) to its first lien
lenders under the Term B loan. The percentage of excess cash
flow offered to these lenders is dependent upon the
Companys consolidated leverage ratio (as defined in the
Senior Credit Facility) at the end of the preceding year. Of the
amount the Company is required to offer, the first lien lenders
must accept 50% while the remaining 50% may either be accepted
or rejected at the lenders option.
105
Based on current credit market conditions the Company expects
that its lenders will accept in full the mandatory offer
required in March 2008, and, as such, the Company has
reclassified approximately $146 million of Term Loan B
maturity from a non-current to a current liability as of
December 31, 2007.
Holdco Credit Facility
During 2007, the Company initiated a capital allocation strategy
that contemplated NRG becoming a wholly owned operating
subsidiary of a newly created holding company, NRG Holdings,
Inc. or Holdco, with the stockholders of NRG becoming
stockholders of Holdco. On June 8, 2007, NRG executed a
Holdco Credit Facility, a delayed-draw credit facility that
expired December 28, 2007, that provided for the funding of
$1 billion in term loan financing to Holdco which was
intended for Holdco to make a capital contribution to NRG in the
amount of $1 billion, to be used to prepay a portion of
NRGs existing Term B loan. As part of the commitment, NRG
agreed to pay a fee equal to 0.5% of the facility for the first
180 days and 0.75% thereafter.
In November 2007, NRG exercised its right to provide its Senior
Note holders with a conditional change of control notice, and
related offer to purchase the Companys Senior Notes at
101% of par, prior to the actual formation of the Holdco
structure. Concurrently, NRG also sought consent from its Senior
Note holders to either waive the change of control or permit
additional restricted payments under the indentures. In December
2007, the conditional tender offers and concurrent consent
solicitations expired with no tendered Senior Notes accepted for
payment and without receipt of the requisite consents to amend
the indentures for the Senior Notes. Consequently, the Company
decided not to move forward and form the Holdco structure.
First and Second Lien Structure
NRG has granted first and second priority liens to certain
counterparties on substantially all of the Companys assets
in the United States in order to secure certain obligations,
which are primarily long-term in nature under certain power sale
agreements and related contracts. NRG uses the first or second
lien structure to reduce the amount of cash collateral and
letters of credit that it would otherwise be required to post
from time to time to support its obligations under these
agreements. Within the first and second lien structure, the
Company can hedge up to 80% of its baseload capacity and 10% of
its non-baseload assets with these counterparties.
As part of NRGs amended and restated credit agreement
signed June 8, 2007, the Company obtained the ability to
move its current second lien counterparty exposure to the first
lien, on a pari passu basis with the Companys existing
first lien lenders. In exchange for moving some second lien
holders to a pari passu basis with the Companys first lien
lenders, the counterparties agreed to relinquish letters of
credit issued by NRG which they held as a part of their
collateral package.
On October 30, 2007, NRG successfully moved certain second
lien holders to a pari passu basis with the Companys first
lien lenders effectively releasing $557 million of letters
of credit. With the movement to the first lien structure, the
Company has significantly reduced its outstanding letter of
credit exposure and thereby increased its liquidity. As of
December 31, 2007, and February 1, 2008, the net
discounted exposure on the agreements and hedges that were
subject to the first and second lien structure were
approximately $425 million and $340 million,
respectively.
In addition, on February 7, 2008, the Company moved an
additional counterparty to the first lien position that resulted
in an additional return of approximately $65 million in
letters of credit.
The following table summarizes the amount of MWs hedged against
the Companys baseload assets and as a percentage relative
to the Companys forecasted baseload capacity under the
first and second lien structure as of February 1, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales Secured by
First and Second Lien
Structure(a)
|
|
2008
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
In
MW(b)
|
|
|
3,283
|
|
|
|
3,811
|
|
|
|
3,050
|
|
|
|
3,264
|
|
|
|
572
|
|
As a percentage of total forecasted baseload capacity
|
|
|
57
|
%
|
|
|
55
|
%
|
|
|
45
|
%
|
|
|
48
|
%
|
|
|
9
|
%
|
|
|
|
(a)
|
|
Equivalent Net Sales include
natural gas swaps converted using a weighted average heat rate
by region.
|
|
(b)
|
|
2008 MW value consists of
March through December positions only.
|
106
Common Stock Finance I Debt Extension
On February 27, 2008, the Company entered into an
arrangement with Credit Suisse that allows the Company, at the
Companys option and subject to customary closing
conditions, to extend the $220 million notes and preferred
interest maturities of CSF I from October 2008 to June 2010. In
addition, the previous settlement date for any share price
appreciation beyond a 20% compound annual growth rate since the
original date of purchase by CSF I, may be extended
30 days to early December 2008. As part of this extension
arrangement, the Company intends to contribute to CSF I
additional collateral in the form of treasury shares to maintain
a blended interest rate of CSF I facility of approximately 7.5%.
The Company expects to implement this extension arrangement by
March 17, 2008.
Asset Sales
ITISA
On December 18, 2007, NRG entered into a sale and purchase
agreement to sell its 100% interest in Tosli, which holds all
NRGs interest in ITISA, to Brookfield Power Inc., a
wholly-owned subsidiary of Brookfield Asset Management Inc., a
Canadian asset management company, focused on property, power
and infrastructure assets, for a purchase price of approximately
$288 million, plus the assumption of approximately
$60 million in debt, subject to purchase price adjustments,
the receipt of regulatory approval and other customary closing
conditions. NRG anticipates completion of the sale transaction
during first half of 2008. As discussed in Note 3,
Discontinued Operations, Business Acquisitions and
Dispositions, the activities of Tosli and ITISA have been
classified as discontinued operations.
USES
OF FUNDS
The Companys requirements for liquidity and capital
resources, other than for operating its facilities, can
generally be categorized by the following: (1) commercial
operations activities; (2) capital expenditures including
RepoweringNRG project deposits; (3) corporate
financial transactions; and (4) debt service obligations.
Commercial Operations
NRGs commercial operations activities require a
significant amount of liquidity and capital resources. These
liquidity requirements are primarily driven by (i) margin
and collateral posted with counterparties; (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, 2007, commercial operations had total cash
collateral outstanding of $85 million, and
$556 million outstanding in letters of credit to third
parties primarily to support its economic hedging activities.
Future liquidity requirements may change based on the
Companys hedging activities and structures, fuel
purchases, and future market conditions, including forward
prices for energy and fuel and market volatility. In addition,
liquidity requirements are dependent on NRGs credit
ratings and general perception of its creditworthiness.
Capital Expenditures
The Companys capital expenditures for the year ended
December 31, 2007, increased by approximately
$260 million, to $481 million, primarily due to
expenditures on RepoweringNRG projects. The following
table
107
summarizes the Companys capital expenditures for the year
ended December 31, 2007, and estimated capital expenditures
for 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
|
|
Environmental
|
|
Repowering
|
|
Total
|
|
|
(In millions)
|
|
Northeast
|
|
$
|
28
|
|
$
|
71
|
|
$
|
7
|
|
$
|
106
|
Texas
|
|
|
143
|
|
|
2
|
|
|
45
|
|
|
190
|
South Central
|
|
|
29
|
|
|
1
|
|
|
|
|
|
30
|
West
|
|
|
4
|
|
|
|
|
|
76
|
|
|
80
|
Wind
|
|
|
|
|
|
|
|
|
69
|
|
|
69
|
Other
|
|
|
6
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
210
|
|
$
|
74
|
|
$
|
197
|
|
$
|
481
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated capital expenditures for 2008
|
|
$
|
234
|
|
$
|
359
|
|
$
|
603
|
|
$
|
1,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Repowering capital expenditures
RepoweringNRG project capital expenditures consisted of
approximately $76 million for the repowered Long Beach
generating station and $67 million in deposits for wind
turbines related to certain wind farms under development. In
addition, the Companys RepoweringNRG capital
expenditures included $7 million for the Cos Cob facility
and $45 million for Cedar Bayou Unit 4.
Major maintenance and environmental capital
expenditures In 2007, the Company initiated a
baghouse project at the Huntley and Dunkirk plants which
increased capital expenditures by approximately
$71 million. Other capital expenditures included
$60 million for STP fuel and maintenance, rotor work of
$18 million for the W.A. Parish facility and
$7 million related to the Limestone unit 2 facility,
$5 million for Indian River unit 4 reheater, Oswego and
Arthur Kill spare transformers of $4 million, LaGen Creole
Station line rebuild of $4 million and Huntley Unit 67
Boiler replacement of $3 million.
The Companys estimated repowering capital expenditures for
2008 primarily consists of approximately $327 million
related to wind farm projects and approximately
$172 million related to STP nuclear units 3 and 4. In
addition, the Company expects to contribute approximately
$83 million in equity towards its joint partnership with BP
Alternative Energy North America for the construction of the
Sherbino Wind Farm project in Texas.
NRG anticipates funding these maintenance capital projects
primarily with funds generated from operating activities. The
Company is also pursuing funding for certain environmental
expenditures in the Northeast through Solid Waste Disposal Bonds
utilizing tax exempt financing, and expects to draw upon such
funds during 2008 and 2009.
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2008
through 2012 to meet NRGs environmental commitments will
be between $1.0 billion and $1.4 billion. These
capital expenditures, in general, are related to installation of
particulate,
SO2,
NOx,
and mercury controls to comply with Clean Air Interstate Rule,
or CAIR, the Clean Air Mercury Rule, or CAMR, and related state
requirements as well as installation of Best Technology
Available under the Phase II 316(b) rule. NRG continues to
explore cost effective alternatives that can achieve desired
results. The range reflects alternative strategies available
with respect to the Companys Indian River plant.
108
The following table summarizes the upper end of the estimated
range for major environmental capital expenditures for the
referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
Northeast
|
|
South Central
|
|
Total
|
|
|
(In millions)
|
|
2008
|
|
$
|
3
|
|
$
|
223
|
|
$
|
133
|
|
$
|
359
|
2009
|
|
|
5
|
|
|
192
|
|
|
211
|
|
|
408
|
2010
|
|
|
24
|
|
|
178
|
|
|
117
|
|
|
319
|
2011
|
|
|
28
|
|
|
112
|
|
|
53
|
|
|
193
|
2012
|
|
|
11
|
|
|
66
|
|
|
15
|
|
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
71
|
|
$
|
771
|
|
$
|
529
|
|
$
|
1,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG plans to reduce the impact of a portion of the above
environmental capital expenditures. NRG has the ability to
monetize a portion of the Companys excess allowances over
the 2008 through 2012 timeframe and still hold sufficient
allowances to operate the fleet with proposed controls through
at least 2020. Second, NRGs current contracts with the
Companys rural electrical customers in the South Central
region allow for recovery of a significant portion of the
capital costs, along with a capital return incurred by complying
with new laws, including interest over the asset life of the
required expenditures. Actual recoveries will depend, among
other things, on the duration of the contracts and the treatment
of these expenditures.
Share Repurchases
For the year ended December 31, 2007, NRG repurchased
9,044,400 shares of the Companys common stock for
approximately $353 million. Of these shares repurchased,
7,006,700 shares of NRG common stock for approximately
$268 million were associated with Phase II of the
Companys previously announced Capital Allocation Program,
which was completed during the third quarter 2007.
In December 2007, the Company initiated its 2008 Capital
Allocation Program with the repurchase of 2,037,700 shares
of NRG common stock for approximately $85 million. This was
followed in January 2008 with the repurchase of
344,000 shares of NRG common stock for approximately
$15 million. In February 2008, the Companys Board of
Directors authorized an additional $200 million in common
share repurchases that would raise the 2008 Capital Allocation
Program to approximately $300 million.
RepoweringNRG Project Deposits
NRG has made non-refundable deposits relating to
RepoweringNRG initiatives totaling approximately
$71 million primarily towards the procurement of wind
turbines. The Company believes that these deposits are necessary
for the timely and successful execution of these projects. The
deposits are in support of expected deliveries of wind turbines
and other equipment totaling approximately $409 million
through 2009. Although NRG is committed to their successful
implementation, the Company may decide not to take delivery of
the equipment and thus terminate the projects. This would result
in the Company expensing the deposits it already has made.
On February 4, 2008, NRG through its wholly owned
subsidiary, Padoma Wind Power LLC, had entered into a
50-50 joint
venture with BP Alternative Energy North America Inc. to build
the first phase of the Sherbino Wind Farm. The Sherbino I Wind
Farm will be a 150-megawatt (MW) wind project, consisting of 50
Vestas 3 MW wind turbine generators, located approximately
40 miles east of Fort Stockton in Pecos County, Texas.
NRG expects to contribute approximately $83 million in
equity to the joint venture in 2008 and has posted a letter of
credit in that amount.
Preferred Stock Dividend Payments
For the year ended December 31, 2007, NRG paid
approximately $28.8 million, $16.8 million and
$9.0 million in dividend payments to holders of the
Companys 5.75%, 4% and 3.625% Preferred Stock.
109
Debt
Service Obligations
On December 31, 2007, the Company used cash on hand to
prepay, without penalty, $300 million of its Term B loan
under the Senior Credit Facility. With this prepayment, the
Company has met a financial ratio by the end of 2007 that would
result in a 0.25% reduction in the interest rate on both its
Term B loan and Synthetic Letter of Credit Facility which is
expected to result in approximately $8 million in pre-tax
interest savings during 2008. This prepayment will be credited
against the Companys mandatory annual prepayment which is
required in March 2008 under the Senior Credit Facility.
As of December 31, 2007, NRG had approximately
$4.7 billion in aggregate principal amount of unsecured
high yield notes or Senior Notes and approximately
$2.8 billion in principal amount outstanding under a Term B
loan and had issued $743 million of letters of credit under
the Companys $1.3 billion Letter of Credit Facility,
leaving $557 million available for future issuances. Under
the Companys $1.0 billion Revolving Facility, as of
December 31, 2007, NRG had issued $3 million in
letters of credit, leaving $997 million available for
borrowings, of which approximately $647 million could be
used to issue additional letters of credit. As of
February 15, 2008, $518 million of undrawn letters of
credit remain available under the funded letter of credit
facility, $897 million of undrawn letters of credit remain
available under the revolving credit facility, and NRG had no
borrowings on the Companys revolving credit facility.
In November 2007 NRG made a payment of $11 million on a
revolving note after Merrill Lynch put the note back to the
Company.
Principal payments on debt and capital leases as of
December 31, 2007 are due in the following periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary/Description
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
Thereafter
|
|
Total
|
|
|
(In millions)
|
|
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.375% Notes due 2017
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
|
|
$
|
1,100
|
|
$
|
1,100
|
7.25% Notes due 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,200
|
|
|
1,200
|
7.375% Notes due 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,400
|
|
|
2,400
|
Term Loan, due 2013
|
|
|
184
|
|
|
31
|
|
|
32
|
|
|
31
|
|
|
31
|
|
|
2,506
|
|
|
2,815
|
CSF Non-Recourse Obligations
|
|
|
190
|
|
|
143
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
NRG Energy Center Minneapolis, due 2013 and 2017
|
|
|
10
|
|
|
11
|
|
|
11
|
|
|
12
|
|
|
13
|
|
|
37
|
|
|
94
|
NRG Peaker Finance Co LLC
|
|
|
13
|
|
|
15
|
|
|
20
|
|
|
21
|
|
|
22
|
|
|
188
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal Debt, Bonds and Notes
|
|
|
397
|
|
|
200
|
|
|
63
|
|
|
64
|
|
|
66
|
|
|
7,431
|
|
|
8,221
|
Capital Lease:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau
|
|
|
75
|
|
|
26
|
|
|
12
|
|
|
6
|
|
|
5
|
|
|
57
|
|
|
181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Payments and Capital Leases
|
|
$
|
472
|
|
$
|
226
|
|
$
|
75
|
|
$
|
70
|
|
$
|
71
|
|
$
|
7,488
|
|
$
|
8,402
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow Discussion
NRG obtains cash from operations, proceeds from the sale of
assets as well as proceeds from the issuance of notes and
preferred stock. NRG uses these funds to finance operations,
make interest payments, repurchase its common stock, service
debt obligations, finance capital expenditures, and meet other
cash and liquidity needs.
110
2007 compared to 2006
The following table reflects the changes in cash flows for the
comparative years; all cash flow categories include the cash
flows from both continuing operations and discontinued
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December
31,
|
|
2007
|
|
|
2006
|
|
|
Change
|
|
|
|
(In millions)
|
|
|
Net cash provided by operating activities
|
|
$
|
1,517
|
|
|
$
|
408
|
|
|
$
|
1,109
|
|
Net cash provided/(used) by investing activities
|
|
|
(327
|
)
|
|
|
(4,176
|
)
|
|
|
3,849
|
|
Net cash provided/(used) by financing activities
|
|
|
(814
|
)
|
|
|
4,053
|
|
|
|
(4,867
|
)
|
Net Cash Provided By Operating Activities
For the year ended December 31, 2007, net cash provided by
operating activities increased by $1.1 billion compared to
the same period in 2006. This was due to:
|
|
|
|
|
Hedge Reset and derivative activity this
increase was primarily due to the write off of power contracts
of $1.1 billion in the fourth quarter of 2006 and a
corresponding $339 million reduction in contract
amortization during 2007 compared to 2006 as a result of the
Hedge Reset transaction. In addition, net income increased
$226 million as a result of adjustments for derivative
activity.
|
|
|
|
Collateral deposits following an upward shift
of the forward price curves, NRGs net collateral deposits
in support of derivative contracts increased by
$125 million for the year ended December 31, 2007,
compared to a decrease of $454 million during the same
period in 2006, a difference of $579 million. As of
December 31, 2007, NRG had net cash collateral deposit of
$85 million.
|
Net Cash
Used in Investing Activities
For the year ended December 31, 2007, net cash used in
investing activities was approximately $3.9 billion less
than the same period in 2006. This reduction in investing
activities was due to:
|
|
|
|
|
Texas acquisition that occurred during the
first quarter 2006. NRG acquired Texas Genco LLC for
approximately $6.2 billion that included the issuance of
common stock at a value of $1.7 billion and a net cash
payment of approximately $4.3 billion;
|
|
|
|
Capital expenditures NRGs capital
expenditures increased by $260 million due to expenditures
of approximately $197 million for RepoweringNRG
projects, primarily related to $76 million for the Long
Beach plant and $67 million in deposits for wind turbines.
In addition, the Company initiated a baghouse project at the
Huntley and Dunkirk plants which also increased capital
expenditures by approximately $71 million.
|
|
|
|
Discontinued Operations and Asset Sales In
2006 NRG received proceeds of $261 million from the sale of
Flinders, Audrain, and Resource Recovery. The sale of the
Companys Red Bluff and Chowchilla plants and equipment
resulted in increased proceeds from asset sales by approximately
$57 million for 2007.
|
Net Cash Provided/(Used) in Financing Activities
For the year ended December 31, 2007, net cash used in
financing activities decreased by approximately
$4.9 billion compared to 2006, due to:
|
|
|
|
|
During the first quarter 2006, NRG acquired Texas Genco LLC. As
part of the acquisition, NRG refinanced the Companys
outstanding debt as well as Texas Genco LLCs outstanding
debt, and also issued new debt, preferred stock and common stock
to fund the acquisition:
|
|
|
|
|
|
Total debt repayments were $4.6 billion
$1.9 billion of NRG debt and $2.7 billion of Texas
Genco LLC debt.
|
|
|
|
Total proceeds from debt issued were
$7.2 billion $3.6 billion from unsecured
notes and $3.6 billion from a senior secured facility,
including a $1.0 billion Revolving Credit Facility, and a
$1.5 billion Synthetic Letter of Credit Facility.
|
111
|
|
|
|
|
Total proceeds from stock issued of approximately
$1.5 billion - net proceeds of $986 million from
issuing approximately 21 million shares of common stock and
net proceeds of $486 million from issuing 2 million
shares of the Companys 5.75% Preferred Stock.
|
|
|
|
|
|
For the year ended December 31, 2007, NRG repurchased
9,049,400 shares of the Companys common stock for
approximately $353 million. For the year ended
December 31, 2006, NRG repurchased 29,601,162 shares for
$732 million. The Company also used cash on hand to repay,
without penalty, $300 million of its Term B loan under the
Senior Credit Facility.
|
NOLs, Deferred Tax Assets and FIN 48
Implications
As of December 31, 2007, the Company had generated total
domestic pretax book income of $860 million which fully
utilized domestic NOL in the amount of $245 million. In
addition, NRG has cumulative foreign NOL carryforwards of
$288 million, of which $72 million will expire
starting in 2011 through 2016 and of which $216 million do
not have an expiration date.
In addition to these amounts, the Company has $683 million
of tax effected unrecognized tax benefits which relate primarily
to net operating losses for tax return purposes but have been
classified as capital loss carryforwards for financial
statements purposes and for which a full valuation allowance has
been established. As a result of the Companys tax
position, and based on current forecasts, future
U.S. domestic income tax payments will be minimal through
mid-year 2009 as these unrecognized tax benefits will be
utilized for tax return purposes.
However, as the position remains uncertain, of the
$683 million of tax effected unrecognized tax benefits, the
Company has recorded a non-current tax liability of
$7 million and may accrue the remaining balance as an
increase to non-current liabilities until final resolution with
the related taxing authority.
On July 6, 2007, the German government passed the Tax
Reform Act of 2008, which reduces the German statutory and
resulting effective tax rates on earnings from approximately 36%
to approximately 27% effective January 1, 2008. Due to this
reduction in the statutory and resulting effective tax rate in
2007, NRG recognized a $29 million tax benefit and as of
December 31, 2007, NRG had a German net deferred tax
liability of approximately $84 million which includes the
impact of this tax rate change.
Off-Balance
Sheet Instruments and Other Contractual Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee
arrangements in the normal course of business to facilitate
commercial transactions with third parties. These arrangements
include financial and performance guarantees, stand-by letters
of credit, debt guarantees, surety bonds and indemnifications.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests
in assets transferred to an unconsolidated entity.
Derivative Instrument obligations
On August 11, 2005, NRG issued 3.625% Preferred Stock that
includes a feature which is considered an embedded derivative
per SFAS 133. Although it is considered an embedded
derivative, it is exempt from derivative accounting as it is
excluded from the scope pursuant to paragraph 11(a) of
SFAS 133. As of December 31, 2007, based on the
Companys stock price, the redemption value of this
embedded derivative was approximately $151 million.
On October 13, 2006, NRG through its unrestricted
wholly-owned subsidiaries NRG Common Stock Fund I and NRG
Common Stock Fund II, issued notes and preferred interests
for the repurchase of NRGs common stock. Included in the
agreement is a feature which is considered an embedded
derivative per SFAS 133. Although it is considered a
derivative, it is exempt from derivative accounting as it is
excluded from the scope pursuant to paragraph 11(a) of
SFAS 133. As of December 31, 2007, based on the
Companys stock price, the redemption value of this
embedded derivative was approximately $87 million.
112
Obligations
Arising Out of a Variable Interest in an Unconsolidated
Entity
Variable interest in Equity investments As of
December 31, 2007, NRG had not entered into any financing
structure that was designed to be off-balance sheet that would
create liquidity, financing or incremental market risk or credit
risk to the Company. However, NRG has several 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. NRGs pro-rata share of non-recourse
debt held by unconsolidated affiliates was approximately
$122 million as of December 31, 2007. This
indebtedness may restrict the ability of these subsidiaries to
issue dividends or distributions to NRG.
Synthetic Letter of Credit Facility and Revolver
Facility Under NRGs amended Senior Credit
Facility which the company entered in to on June 8, 2007,
the Company has a $1.3 billion synthetic Letter of Credit
Facility which is secured by a $1.3 billion cash deposit at
Deutsche Bank AG, New York Branch, the Issuing Bank. This
deposit was funded using proceeds from the Term B loan investors
who participated in the facility syndication. Under the
Synthetic Letter of Credit Facility, NRG is allowed to issue
letters of credit for general corporate purposes including
posting collateral to support the Companys commercial
operations activities. On August 6, 2007, NRG entered into
an agreement with BNP Paribas, or BNP, whereby BNP has agreed to
be an issuing bank under the revolver portion of the
Companys Senior Credit Facility. BNP has agreed to issue
up to $350 million of letters of credit. In addition, on
January 30, 2008, NRG entered into an agreement with Bank
of America, whereby Bank of America has also agreed to be an
issuing bank under the revolver portion of the Companys
Senior Credit Facility. Bank of America has agreed to issue up
to $250 million of letters of credit under the revolver.
This increases the amount of unfunded letters of credit the
Company can issue under its Revolving Credit Facility to
$900 million for ongoing working capital requirements and
for general corporate purposes, including acquisitions that are
permitted under the Senior Credit Facility. In addition, NRG is
permitted to issue additional letters of credit of up
$100 million under the Senior Credit facility through other
financial institutions.
As of December 31, 2007, the Company had issued
$743 million in letters of credit under the Synthetic
Letter of Credit Facility. In addition, as of December 31,
2007, the Company had issued $3 million in letters of
credit under the Revolving Credit Facility. A portion of these
letters of credit supports non-commercial letter of credit
obligations.
Contractual
Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other
commercial commitments that represent prospective cash
requirements in addition to the Companys capital
expenditure programs. The following tables summarize NRGs
contractual obligations and guarantees. For an additional
discussion, see Item 15 Note 11, Debt
and Capital Leases, and Note 21, Commitments and
Contingencies, to the Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
2007
|
|
|
|
|
Under
|
|
|
|
|
|
Over
|
|
|
|
2006
|
Contractual Cash
Obligations
|
|
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
5 Years
|
|
Total
|
|
Total
|
|
|
(In millions)
|
|
Long-term debt (including estimated interest)
|
|
$
|
1,010
|
|
$
|
1,407
|
|
$
|
1,263
|
|
$
|
8,621
|
|
$
|
12,301
|
|
$
|
13,348
|
Capital lease obligations (including estimated interest)
|
|
|
93
|
|
|
66
|
|
|
28
|
|
|
203
|
|
|
390
|
|
|
403
|
Operating leases
|
|
|
40
|
|
|
73
|
|
|
64
|
|
|
243
|
|
|
420
|
|
|
427
|
Fuel purchase and transportation
obligations(a)
|
|
|
1,614
|
|
|
1,059
|
|
|
299
|
|
|
231
|
|
|
3,203
|
|
|
3,646
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual cash obligations
|
|
$
|
2,757
|
|
$
|
2,605
|
|
$
|
1,654
|
|
$
|
9,298
|
|
$
|
16,314
|
|
$
|
17,824
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes only those coal
transportation commitments for 2008 as no other nominations were
made as of December 31, 2007.
|
113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
2007
|
|
|
|
|
Under
|
|
|
|
|
|
Over
|
|
|
|
2006
|
Guarantees
|
|
1 Year
|
|
1-3 Years
|
|
3-5 Years
|
|
5 Years
|
|
Total
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Synthetic letters of credit
|
|
$
|
475
|
|
$
|
268
|
|
$
|
|
|
$
|
|
|
$
|
743
|
|
$
|
967
|
Unfunded standby letters of credit and surety bonds
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
153
|
Asset sales guarantee obligations
|
|
|
13
|
|
|
|
|
|
113
|
|
|
22
|
|
|
148
|
|
|
144
|
Commodity sales guarantee obligations
|
|
|
93
|
|
|
134
|
|
|
|
|
|
564
|
|
|
791
|
|
|
604
|
Other guarantees
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
32
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total guarantees
|
|
$
|
589
|
|
$
|
402
|
|
$
|
113
|
|
$
|
618
|
|
$
|
1,722
|
|
$
|
1,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG has a variety of contractual obligations and other
commercial commitments that represent prospective cash
requirements in addition to the Companys capital
expenditure programs. See Item 15 Note 21,
Commitments and Contingencies, to the Consolidated
Financial Statements for a discussion of commitments and
contingencies that also include contractual obligations and
commercial commitments that occurred during 2007.
Derivative Instruments
NRG may enter into long-term power sales contracts, fuel
purchase contracts and other energy-related financial
instruments to mitigate variability in earnings due to
fluctuations in spot market prices, to hedge fuel requirements
at generation facilities and protect fuel inventories. In
addition, in order to mitigate interest rate risk associated
with the issuance of the Companys variable rate and fixed
rate debt, NRG enters into interest rate swap agreements.
NRGs trading activities include contracts entered into to
profit from market price changes as opposed to hedging an
exposure, and are subject to limits in accordance with the
Companys risk management policy. These contracts are
recognized on the balance sheet at fair value and changes in the
fair value of these derivative financial instruments are
recognized in earnings. These trading activities are a
complement to NRGs energy marketing portfolio.
The tables below disclose the 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, 2007, based on
whether fair values are determined by quoted market prices or
more subjective means; and indicate the maturities of contracts
at December 31, 2007.
Derivative
Activity Gains/(Losses)
|
|
|
|
|
Derivative Activity
Gains/(Losses)
|
|
(In millions)
|
|
|
Fair value of contracts as of December 31, 2006
|
|
$
|
354
|
|
Contracts realized or otherwise settled during the period
|
|
|
(292
|
)
|
Changes in fair value
|
|
|
(554
|
)
|
|
|
|
|
|
Fair value of contracts as of December 31, 2007
|
|
$
|
(492
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of December 31, 2007
|
|
|
|
Maturity
|
|
|
|
|
|
|
|
Maturity
|
|
|
|
|
|
|
Less Than
|
|
Maturity
|
|
|
Maturity
|
|
|
in Excess
|
|
|
Total Fair
|
|
Sources of Fair Value
Gains/(Losses)
|
|
1 Year
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
4-5 Years
|
|
|
Value
|
|
|
|
(In millions)
|
|
|
Prices actively quoted
|
|
$
|
4
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
6
|
|
Prices provided by other external sources
|
|
|
89
|
|
|
(198
|
)
|
|
|
(394
|
)
|
|
|
(22
|
)
|
|
|
(525
|
)
|
Prices provided by models and other valuation methods
|
|
|
23
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
116
|
|
$
|
(194
|
)
|
|
$
|
(392
|
)
|
|
$
|
(22
|
)
|
|
$
|
(492
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
114
Critical
Accounting Policies and Estimates
NRGs discussion and analysis of the financial condition
and results of operations are based upon the consolidated
financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United
States of America. 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 affect the
financial statements and disclosures based on varying
assumptions, which may be appropriate to use. In addition, the
financial and operating environment may also 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, NRG evaluates these estimates, utilizing
historic experience, consultation with experts and other methods
the Company considers reasonable. In any event, actual results
may differ substantially from the Companys estimates. Any
effects on the Companys 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.
NRGs significant accounting policies are summarized in
Item 15 Note 2, Summary of Significant
Accounting Policies, to the Consolidated Financial
Statements. The Company identifies its most critical accounting
policies as those that are the most pervasive and important to
the portrayal of the Companys 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
|
|
Derivative Financial Instruments
|
|
|
|
Assumptions used in valuation techniques
|
|
|
|
|
Assumptions used in forecasting generation
|
|
|
|
|
Market maturity and economic conditions
|
|
|
|
|
Contract interpretation
|
|
|
|
|
Market conditions in the energy industry, especially the effects
of price volatility on contractual commitments
|
|
|
|
|
Regulatory and political environments and requirements
|
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
|
Impairment of Long Lived Assets
|
|
|
|
Recoverability of investment through future operations
|
|
|
|
|
Regulatory and political environments and requirements
|
|
|
|
|
Estimated useful lives of assets
|
|
|
|
|
Environmental obligations and operational limitations
|
115
|
|
|
|
|
Accounting Policy
|
|
|
|
Judgments/Uncertainties
Affecting Application
|
|
|
|
|
|
Estimates of future cash flows
|
|
|
|
|
Estimates of fair value (fresh start)
|
|
|
|
|
Judgment about triggering events
|
Goodwill and Other Intangible Assets
|
|
|
|
Estimated useful lives for finite-lived intangible assets
|
|
|
|
|
Judgment about impairment triggering events
|
|
|
|
|
Estimates of reporting units fair value
|
|
|
|
|
Fair value estimate of certain power sales and fuel contracts
using forward pricing curves as of the closing date over the
life of each contract
|
Contingencies
|
|
|
|
Estimated financial impact of event(s)
|
|
|
|
|
Judgment about likelihood of event(s) occurring
|
Derivative Financial Instruments
The Company follows the guidance of SFAS 133, to account
for derivative financial instruments. SFAS 133 requires the
Company to mark-to-market all derivative instruments on the
balance sheet, and recognize changes in the fair value of
non-hedge derivative instruments immediately in earnings. In
certain cases, NRG may apply hedge accounting to the
Companys derivative instruments. The criteria used to
determine if hedge accounting treatment is appropriate are:
(i) the designation of the hedge to an underlying exposure,
(ii) whether the overall risk is being reduced; and
(iii) if there is a correlation between the fair value of
the derivative instrument and the underlying hedged item.
Changes in the fair value of derivatives instruments accounted
for as hedges are either recognized in earnings as an offset to
the changes in the fair value of the related hedged item, or
deferred and recorded as a component of OCI, and subsequently
recognized in earnings when the hedged transactions occur.
For purposes of measuring the fair value of derivative
instruments, NRG uses quoted exchange prices and broker quotes.
When external prices are not available, NRG uses internal models
to determine the fair value. These internal models include
assumptions of the future prices of energy based on the specific
market in which the energy is being sold, using externally
available forward market pricing curves for all periods possible
under the pricing model. In order to qualify derivatives
instruments for hedged transactions, NRG estimates the
forecasted generation occurring within a specified time period.
Judgments related to the probability of forecasted generation
occurring are based on available baseload capacity, internal
forecasts of sales and generation, and historical physical
delivery on similar contracts. The probability that hedged
forecasted generation will occur by the end of a specified time
period could change the results of operations by requiring
amounts currently classified in OCI to be reclassified into
earnings, creating increased variability in our earnings. These
estimations are considered to be critical accounting estimates.
Certain derivative financial instruments that meet the criteria
for derivative accounting treatment also qualify for a scope
exception to derivative accounting, as they are considered
Normal Purchase and Normal Sales, or NPNS. The availability of
this exception is based upon the assumption that NRG has the
ability and it is probable to deliver or take delivery of the
underlying item. These assumptions are based on available
baseload capacity, internal forecasts of sales and generation,
and historical physical delivery on contracts. Derivatives that
are considered to be NPNS are exempt from derivative accounting
treatment, and are accounted for under accrual accounting. If it
is determined that a transaction designated as NPNS no longer
meets the scope exception due to changes in estimates, the
related contract would be recorded on the balance sheet at fair
value combined with the immediate recognition through earnings.
Income Taxes and Valuation Allowance for Deferred Tax
Assets
As of December 31, 2007, NRG had a valuation allowance of
approximately $539 million. This amount is comprised of
U.S. domestic capital loss carryforwards and
non-depreciable property of approximately $458 million,
116
foreign net operating loss carryforwards of approximately
$80 million and foreign capital loss carryforwards of
approximately $1 million. In assessing the recoverability
of NRGs deferred tax assets, the Company considers whether
it is more likely than not that some portion or all of the
deferred tax assets will be realized. The ultimate realization
of deferred tax assets is dependent upon projected capital gains
and available tax planning strategies.
As of December 31, 2007, NRG had fully utilized
$245 million of cumulative U.S. federal and state net
operating loss for financial reporting purposes. The utilization
of the Companys NOLs depends on several factors, such as
NRGs ability to utilize tax benefits through carryforwards
to future periods, the application of tax statutes and
regulations to transactions.
NRG continues to be under audit for multiple years by taxing
authorities in other jurisdictions. Considerable judgment is
required to determine the tax treatment of a particular item
that involves interpretations of complex tax laws. NRG is
subject to examination by taxing authorities for income tax
returns filed in the U.S. federal jurisdiction and various
state and foreign jurisdictions including major operations
located in Germany, Australia, and Brazil. The Company is no
longer subject to U.S. federal income tax examinations for
years prior to 2002. With few exceptions, state and local income
tax examinations are no longer open for years before 2003. The
Companys significant foreign operations are also no longer
subject to examination by local jurisdictions for years prior to
2000.
Evaluation of Assets for Impairment and Other Than
Temporary Decline in Value
In accordance with SFAS No. 144, Accounting for the
Impairment or Disposal of Long-Lived Assets, or
SFAS 144, NRG evaluates property, plant and equipment and
certain intangible assets for impairment whenever indicators of
impairment exist. Examples of such indicators or events are:
|
|
|
|
|
Significant decrease in the market price of a long-lived asset;
|
|
|
|
Significant adverse change in the manner an asset is being used
or its physical condition;
|
|
|
|
Adverse business climate;
|
|
|
|
Accumulation of costs significantly in excess of the amount
originally expected for the construction or acquisition of an
asset,
|
|
|
|
Current-period loss combined with a history of losses or the
projection of future losses; and
|
|
|
|
Change in the Companys intent about an asset from an
intent to hold to a greater than 50% likelihood that an asset
will be sold or disposed of before the end of its previously
estimated useful life.
|
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 the
Company. Generally, fair value will be determined using
valuation techniques such as the present value of expected
future cash flows. NRG uses its best estimates in making these
evaluations and considers various factors, including forward
price curves for energy, fuel costs, and operating costs.
However, actual future market prices and project costs could
vary from the assumptions used in the Companys estimates,
and the impact of such variations could be material.
For assets to be held and used, if the Company determines that
the undiscounted cash flows from the asset are less than the
carrying amount of the asset, NRG must estimate fair value to
determine the amount of any impairment loss. Assets
held-for-sale are reported at the lower of the carrying amount
or fair value less the cost to sell. The estimation of fair
value under SFAS 144, whether in conjunction with an asset
to be held and used or with an asset held-for-sale, and the
evaluation of asset impairment are, by their nature, subjective.
NRG considers quoted market prices in active markets to the
extent they are available. In the absence of such information,
the Company may consider prices of similar assets, consult with
brokers, or employ other valuation techniques. NRG will also
discount the estimated future cash flows associated with the
asset using a single interest rate representative of the risk
involved with such an investment or employ an expected present
value method that probability-weights a range of possible
outcomes. The use of these methods involves the same inherent
uncertainty of future cash flows as
117
previously discussed with respect to undiscounted cash flows.
Actual future market prices and project costs could vary from
those used in the Companys estimates, and the impact of
such variations could be material.
NRG is also required to evaluate its equity-method and
cost-method investments to determine whether or not they are
impaired. Accounting Principles Board Opinion No. 18,
The Equity Method of Accounting for Investments in Common
Stock, or APB18, provides the accounting requirements for
these investments. The standard for determining whether an
impairment must be recorded under APB 18 is whether the value is
considered an other than a temporary decline in
value. The evaluation and measurement of impairments under APB
18 involves the same uncertainties as described for long-lived
assets that the Company owns directly and accounts for in
accordance with SFAS 144. Similarly, the estimates that NRG
makes with respect to its equity and cost-method investments are
subjective, and the impact of variations in these estimates
could be material. Additionally, if the projects in which the
Company holds these investments recognize an impairment under
the provisions of SFAS 144, NRG would record its
proportionate share of that impairment loss and would evaluate
its investment for an other than temporary decline in value
under APB 18.
For the year ended December 31, 2007, there was a reduction
of $11 million in income from continuing operation due to
an impairment of an investment in commercial paper which has
been subsequently reclassified from cash equivalents to
non-current assets. The Company recorded this impairment as a
reduction to interest income. For the year ended 2006, there was
no reduction in income from continuing operation due to any
impairment. For the year ended December 31, 2005, income
from continuing operations was reduced by $6 million due to
an impairment.
Goodwill and Other Intangible Assets
As part of the acquisition of Texas Genco LLC, NRG recorded
intangible assets and goodwill. The Company applied
SFAS No. 141, Business Combinations, or
SFAS 141, and SFAS No. 142, Goodwill and Other
Intangible Assets, or SFAS 142, to account for these
intangibles. Under these standards, the Company amortizes all
finite-lived intangible assets over their respective estimated
weighted-average useful lives, while goodwill has an indefinite
life and is not amortized. However, goodwill and all intangible
assets not subject to amortization will be tested for
impairments whenever an event occurs that indicates that an
impairment may have occurred, or at a minimum, on an annual
basis. Where necessary, the Companys goodwill
and/or
intangible asset with indefinite lives will be impaired at that
time.
In connection with the Texas Genco acquisition, the Company
recognized the estimated fair value of certain power sale
contracts and fuel contracts acquired. NRG estimated their fair
value using forward pricing curves as of the closing date of the
acquisition over the life of each contract. These contracts had
net negative fair values at the closing date of the acquisition
and were reflected as assumed contracts in the consolidated
balance sheets. Assumed contracts are amortized to revenues and
fuel expense as applicable based on the estimated realization of
the fair value established on the closing date over the
contractual lives.
Contingencies
NRG records a loss contingency when management determines it is
probable that a liability has been incurred and the amount of
the loss can be reasonably estimated. Gain contingencies are not
recorded until management determines it is certain that the
future event will become or does become a reality. Such
determinations are subject to interpretations of current facts
and circumstances, forecasts of future events, and estimates of
the financial impacts of such events. NRG describes in detail
its contingencies in Item 15 Note 21,
Commitments and Contingencies, to the Consolidated
Financial Statements.
Recent Accounting Developments
See Item 15 Note 2, Summary of
Significant Accounting Policies, to the Consolidated
Financial Statements for a discussion of recent accounting
developments.
|
|
Item 7A
|
Quantitative
and Qualitative Disclosures about Market Risk
|
NRG is exposed to several market risks in the Companys
normal business activities. Market risk is the potential loss
that may result from market changes associated with the
Companys merchant power generation or
118
with an existing or forecasted financial or commodity
transaction. The types of market risks the Company is exposed to
are commodity price risk, interest rate risk and currency
exchange risk. In order to manage these risks the Company uses
various fixed-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 fixed-price purchase and sales commitments;
|
|
|
|
Manage and hedge exposure to variable rate debt obligations;
|
|
|
|
Reduce exposure to the volatility of cash market prices; and
|
|
|
|
Hedge fuel requirements for the Companys generating
facilities.
|
Commodity Price Risk
Commodity price risks result from exposures to changes in spot
prices, forward prices, volatility 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; and
|
|
|
|
Changes in the nature and extent of federal and state
regulations.
|
As part of NRGs overall portfolio, NRG manages the
commodity price risk of the Companys merchant generation
operations by entering into various derivative or non-derivative
instruments to hedge the variability in future cash flows from
forecasted sales of electricity and purchases of fuel. These
instruments include forward purchase and sale contracts, futures
and option contracts traded on the New York Mercantile Exchange,
and swaps and options traded in the over-the-counter financial
markets. The portion of forecasted transactions hedged may vary
based upon managements assessment of market, weather,
operation and other factors.
While some of the contracts the Company uses to manage risk
represent commodities or instruments for which prices are
available from external sources, other commodities and certain
contracts are not actively traded and are valued using other
pricing sources and modeling techniques to determine expected
future market prices, contract quantities, or both. NRG uses the
Companys best estimates to determine the fair value of
commodity and derivative contracts held and sold. These
estimates consider various factors, including closing exchange
and over-the-counter price quotations, time value, volatility
factors and credit exposure. However, it is likely that future
market prices could vary from those used in recording
mark-to-market derivative instrument valuation, and such
variations could be material.
NRG measures the sensitivity of the Companys portfolio to
potential changes in market prices using Value at Risk, or VAR.
VAR is a statistical model that attempts to predict risk of loss
based on market price and volatility. Currently, the company
estimates VAR using a Monte Carlo simulation based methodology.
NRGs total portfolio includes mark-to-market and non
mark-to-market energy assets and liabilities.
NRG uses a diversified VAR model to calculate an estimate of the
potential loss in the fair value of the Companys energy
assets and liabilities, which includes generation assets, load
obligations, and bilateral physical and financial transactions.
The key assumptions for the Companys diversified model
include: (1) a lognormal distribution of prices,
(2) one-day
holding period, (3) a 95% confidence interval, (4) a
rolling
36-month
forward looking period, and (5) market implied volatilities
and historical price correlations.
As of December 31, 2007, the VAR for NRGs commodity
portfolio, including generation assets, load obligations and
bilateral physical and financial transactions calculated using
the diversified VAR model was $64 million.
119
The following table summarizes average, maximum and minimum VAR
for NRG for the year ended December 31, 2007 and 2006:
|
|
|
|
|
VAR
|
|
In millions
|
|
|
As of December 31,
2007(b)
|
|
$
|
64
|
|
Average
|
|
|
28
|
|
Maximum
|
|
|
64
|
|
Minimum
|
|
|
14
|
|
|
|
|
|
|
As of December 31, 2006
|
|
$
|
18
|
|
Average(a)
|
|
|
39
|
|
Maximum(a)
|
|
|
67
|
|
Minimum(a)
|
|
|
17
|
|
|
|
|
(a)
|
|
Includes Texas region portfolio
beginning the third quarter 2006.
|
|
(b)
|
|
Prior to December 4, 2007,
NRGs VAR measurement was based on a rolling
24-month
forward looking period
|
Due to the inherent limitations of statistical measures such as
VAR, the evolving nature of the competitive markets for
electricity and related derivatives, and the seasonality of
changes in market prices, the VAR calculation may not capture
the full extent of commodity price exposure. As a result, actual
changes in the fair value of
mark-to-market
energy assets and liabilities could differ from the calculated
VAR, and such changes could have a material impact on the
Companys financial results.
In order to provide additional information for comparative
purposes to NRGs peers, the Company also uses VAR to
estimate the potential loss of derivative financial instruments
that are subject to mark-to-market accounting. These derivative
instruments include transactions that were entered into for both
asset management and trading purposes. The VAR for the
derivative financial instruments calculated using the
diversified VAR model as of December 31, 2007, for the
entire term of these instruments entered into for both asset
management and trading was approximately $17 million.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through the
Companys issuance of fixed rate and variable rate debt.
Exposures to interest rate fluctuations may be mitigated by
entering into derivative instruments known as interest rate
swaps, caps, collars and put or call options. These contracts
reduce exposure to interest rate volatility and result in
primarily fixed rate debt obligations when taking into account
the combination of the variable rate debt and the interest rate
derivative instrument. NRGs risk management policies allow
the Company to reduce interest rate exposure from variable rate
debt obligations.
In January 2006, the Company entered into a series of new
interest rate swaps. These interest rate swaps became effective
on February 15, 2006, and are intended to hedge the risk
associated with floating interest rates. For each of the
interest rate swaps, NRG pays its counterparty the equivalent of
a fixed interest payment on a predetermined notional value, and
NRG receives the equivalent of a floating interest payment based
on a 3-month
LIBOR rate calculated on the same notional value. All interest
rate swap payments by NRG and its counterparties are made
quarterly, and the LIBOR is determined in advance of each
interest period. While the notional value of each of the swaps
does not vary over time, the swaps are designed to mature
sequentially. The total notional amount of these swaps as of
December 31, 2007 was $2.03 billion.
The notional amounts and maturities of each tranche of these
swaps are as follows:
|
|
|
|
|
|
|
|
|
Period of Swap
|
|
Notional Value
|
|
|
Maturity
|
|
|
2 - year
|
|
$
|
140 million
|
|
|
|
March 31, 2008
|
|
3 - year
|
|
$
|
150 million
|
|
|
|
March 31, 2009
|
|
4 - year
|
|
$
|
190 million
|
|
|
|
March 31, 2010
|
|
5 - year
|
|
$
|
1.55 billion
|
|
|
|
March 31, 2011
|
|
As of December 31, 2007, the Company had various interest
rate swap agreements, including those listed above, with
notional amounts totaling approximately $2.7 billion. If
the swaps had been discontinued on December 31, 2007, the
Company would have owed the counter-parties approximately
$69 million. Based on
120
the investment grade rating of the counter-parties, NRG believes
its exposure to credit risk due to nonperformance by
counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject
the Company to the risk of loss associated with movements in
market interest rates. As of December 31, 2007, a
100 basis point change in interest rates would result in a
$16 million change in interest expense on a rolling twelve
month basis.
As of December 31, 2007, the Companys long-term debt
fair value was $8.1 billion and the carrying amount was
$8.4 billion. NRG estimates that a 1% decrease in market
interest rates would have increased the fair value of the
Companys long-term debt by $471 million.
Liquidity Risk
Liquidity risk arises from the general funding needs of
NRGs activities and in the management of the
Companys assets and liabilities. NRGs liquidity
management framework is intended to maximize liquidity access
and minimize funding costs. Through active liquidity management,
the Company seeks to preserve stable, reliable and
cost-effective sources of funding. This enables the Company to
replace maturing obligations when due and fund assets at
appropriate maturities and rates. To accomplish this task,
management uses a variety of liquidity risk measures that take
into consideration market conditions, prevailing interest rates,
liquidity needs, and the desired maturity profile of liabilities.
Based on a sensitivity analysis, a $1 per MWh increase or
decrease in electricity prices across the term of the marginable
contracts would cause a change in margin collateral outstanding
of approximately $15 million as of December 31, 2007.
This analysis uses simplified assumptions and is calculated
based on portfolio composition and margin-related contract
provisions as of December 31, 2007.
Credit Risk
Credit risk relates to the risk of loss resulting from
non-performance or non-payment by counterparties pursuant to the
terms of their contractual obligations. The Company monitors and
manages the credit risk of NRG and its subsidiaries through
credit policies that include (i) an established credit
approval process, (ii) a daily monitoring of counter-party
credit limits, (iii) the use of credit mitigation measures
such as margin, collateral, credit derivatives or prepayment
arrangements, (iv) the use of payment netting agreements,
and (v) the use of master netting agreements that allow for
the netting of positive and negative exposures of various
contracts associated with a single counterparty. Risks
surrounding counterparty performance and credit could ultimately
impact the amount and timing of expected cash flows. The Company
has credit protection within various agreements to call on
additional collateral support if and when necessary. As of
December 31, 2007, NRG held net collateral of approximately
$147 million from counterparties.
A portion of NRGs credit risk is related to transactions
that are recorded in the Companys consolidated Balance
Sheets. These transactions primarily consist of open positions
from the Companys marketing and risk management operation
that are accounted for using mark-to-market accounting, as well
as amounts owed by counterparties for transactions that settled
but have not yet been paid.
The following table highlights the credit quality and the
balance sheet settlement exposures related to these activities
as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure
|
|
|
|
|
|
|
|
|
|
Before
|
|
|
|
|
|
Net
|
|
Credit Exposure
|
|
Collateral
|
|
|
Collateral
|
|
|
Exposure
|
|
|
|
(In millions, except ratios)
|
|
|
Investment grade
|
|
$
|
1,446
|
|
|
$
|
464
|
|
|
$
|
982
|
|
Non-investment grade
|
|
|
39
|
|
|
|
9
|
|
|
|
30
|
|
Not rated
|
|
|
171
|
|
|
|
11
|
|
|
|
160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,656
|
|
|
$
|
484
|
|
|
$
|
1,172
|
|
Investment grade
|
|
|
87
|
%
|
|
|
96
|
%
|
|
|
84
|
%
|
Non-investment grade
|
|
|
2
|
%
|
|
|
2
|
%
|
|
|
3
|
%
|
Not rated
|
|
|
10
|
%
|
|
|
2
|
%
|
|
|
14
|
%
|
121
Additionally, the Company has concentrations of suppliers and
customers among coal suppliers, electric utilities, energy
marketing and trading companies, and regional transmission
operators. These concentrations of counterparties may impact
NRGs overall exposure to credit risk, either positively or
negatively, in that counterparties may be similarly affected by
changes in economic, regulatory and other conditions.
NRGs exposure to significant counterparties greater than
10% of the net exposure of approximately $1.2 billion, was
$923 million as of December 31, 2007. NRG does not
anticipate any material adverse effect on the Companys
financial position or results of operations as a result of
nonperformance by any of NRGs counterparties.
Currency Exchange Risk
NRG may be subject to foreign currency risk as a result of the
Company entering into purchase commitments with foreign vendors
for the purchase of major equipment associated with
RepoweringNRG initiatives. To reduce the risks to such
foreign currency exposure, the Company may enter into
transactions to hedge its foreign currency exposure using
currency options and forward contracts. At December 31,
2007, no foreign currency options and forward contracts were
outstanding. As a result of the Companys limited foreign
currency exposure to date, the effect of foreign currency
fluctuations has not been material to the Companys results
of operations, financial position and cash flows.
The effects of a hypothetical simultaneous 10% appreciation in
the U.S. dollar from year-end 2007 levels against all other
currencies of countries in which the Company has continuing
operations would result in an immaterial impact to NRGs
consolidated statements of operations. However, NRGs
consolidated financial position would also have been negatively
affected by approximately $55 million, due to currency
translation adjustments recorded in OCI.
|
|
Item 8
|
Financial
Statements and Supplementary Data
|
The financial statements and schedules are listed in
Part IV, Item 15 of this
Form 10-K.
Item 9
Changes in and Disagreements with Accountants on Accounting
and Financial Disclosures
None.
|
|
Item 9A
|
Controls
and Procedures
|
Conclusion Regarding the Effectiveness of Disclosure Controls
and Procedures
Under the supervision and with the participation of NRGs
management, including its principal executive officer, principal
financial officer and principal accounting officer, NRG
conducted an evaluation of its disclosure controls and
procedures, as such term is defined in
Rules 13a-15(e)
or 15d-15(e)
of the Securities Exchange Act of 1934, as amended, or the
Exchange Act. Based on this evaluation, the Companys
principal executive officer, principal financial officer and
principal accounting officer concluded that the disclosure
controls and procedures were effective as of the end of the
period covered by this annual report on
Form 10-K.
Managements report on the Companys internal control
over financial reporting and the report of the Companys
independent registered public accounting firm are incorporated
under the caption Managements Report on Internal
Control over Financial Reporting and under the caption
Report of Independent Registered Public Accounting
Firm, of the Companys 2007 Annual Report to
Shareholders.
Changes in Internal Control Over Financial Reporting
There have been no changes in the Companys internal
control over financial reporting (as such term is defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act) during the year ended December 31,
2007 that have materially affected, or are reasonably likely to
materially affect the Companys internal control over
financial reporting.
122
Inherent Limitations Over Internal Controls
NRGs internal control over financial reporting is designed
to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of consolidated
financial statements for external purposes in accordance with
generally accepted accounting principles. The Companys
internal control over financial reporting includes those
policies and procedures that:
|
|
|
|
1.
|
Pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and
dispositions of our assets;
|
|
|
2.
|
Provide reasonable assurance that transactions are recorded as
necessary to permit preparation of consolidated financial
statements in accordance with generally accepted accounting
principles, and that our receipts and expenditures are being
made only in accordance with authorizations of our management
and directors; and
|
|
|
3.
|
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of our
assets that could have a material effect on the consolidated
financial statements.
|
Internal control over financial reporting cannot provide
absolute assurance of achieving financial reporting objectives
because of its inherent limitations, including the possibility
of human error and circumvention by collusion or overriding of
controls. Accordingly, even an effective internal control system
may not prevent or detect material misstatements on a timely
basis. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree
of compliance with the policies or procedures may deteriorate.
|
|
Item 9B
|
Other
Information
|
Management Restructuring Having experienced
significant financial, organizational and operational growth
since emerging from bankruptcy in 2003, NRG will implement
several enhancements to the Companys management structure
in order to better position the Company to capitalize on gains
made already through initiatives such as RepoweringNRG
and FORNRG and to support the future growth of the
Company. These developments, effective as of March 1, are
as follows:
Robert Flexon has been promoted to the newly created position of
Chief Operating Officer. Mr. Flexon will now oversee
NRGs Plant Operations, Commercial Operations,
Environmental Compliance and Risk teams, as well as the
Engineering, Procurement and Construction division. Since March
2004, he has served as the Companys Chief Financial
Officer. Prior to joining NRG, from June 2000 to March 2004,
Mr. Flexon was Vice President, Corporate
Development & Work Process and Vice President,
Business Analysis and Controller of Hercules, Inc.
Clint Freeland, NRGs Treasurer since April 2006, has been
promoted to Chief Financial Officer. Mr. Freeland will now
manage the Companys corporate financial and control
functions including Treasury, Accounting, Tax and Insurance
programs. Mr. Freeland joined NRG in July, 2004 as
Director, Finance, following over 10 years in key financial
roles within the energy sector for such Houston-based companies
as Enron, Coral Energy and ABN AMRO Bank, N.V.
In addition, Kevin Howell has been promoted to NRGs Chief
Administrative Officer. In this position, Mr. Howell will
oversee several critical corporate functions including
Communications, Investor Relations, Human Resources and
Information Technology. Previously, Mr. Howell led
NRGs Commercial Operations group, a position he held since
August 2005. Prior to joining NRG, he served as President of
Dominion Energy Clearinghouse since 2001.
Mauricio Gutierrez will be promoted and will succeed
Mr. Howell as Senior Vice President, Commercial Operations.
Mr. Gutierrez currently serves as Vice President,
Commercial Operations Trading where he is responsible for the
trading operations and will now expand his responsibilities to
include the real time operations, origination and structuring
for the Company. Mr. Gutierrez joined NRG in August 2004.
123
In addition, Carolyn Burke, Vice President and Controller, will
be resigning from the Company effective March 14, 2008.
James Ingoldsby, currently serving as Vice President, Financial
Planning and Analysis, will assume Ms. Burkes
responsibilities in his new position as Vice President and Chief
Accounting Officer effective March 1, 2008. In this role,
Mr. Ingoldsby is responsible for directing NRGs
financial accounting and reporting activities, as well as the
financial planning and analysis function. Since August 2006,
Mr. Ingoldsby served as Vice President, Financial Planning
and Analysis. From May 2004 to July 2006, Mr. Ingoldsby
served as NRGs Vice President and Controller.
Mr. Ingoldsby, who led the Sarbanes-Oxley implementation at
chemical company Hercules, Inc., previously held various
executive positions at GE Betz, formerly BetzDearborn from 1993
to 2003, including serving as Controller, and Director of
Business Analysis and Director of Financial Reporting. He also
held various staff and managerial accounting and auditing
positions at Mack Trucks, Inc. from 1982 to 1993.
Mr. Ingoldsby began his career with Deloitte and Touche.
The compensation arrangements for the Companys named
executive officers, as well as Mr. Freeland, are filed as
Exhibit 10.33 to this
Form 10-K
and incorporated herein by reference.
Amendment to Bylaws On February 26,
2008, the Board of Directors of the Company unanimously approved
an amendment to Article VI, Sections 1 and 2, of
NRGs Amended and Restated Bylaws effective immediately.
The amended provision allows the Board, by resolution, to
provide for uncertificated shares of common stock to be
evidenced by a book-entry system, as well as other conforming
changes. The Board also approved amendments to Article V to
clarify that employees of NRG who serve as officers or directors
of joint ventures are entitled to the same indemnification
rights as officers or directors of wholly-owned NRG
subsidiaries. A complete copy of the Amended and Restated Bylaws
is filed as Exhibit 3.2 to this
Form 10-K
and incorporated herein by reference.
CSF I Extension On February 27, 2008,
NRG Common Stock Finance I LLC, or CSF I, a wholly owned
subsidiary of the Company, entered into an amendment to the Note
Purchase Agreement by and among CSF I, Credit Suisse
International and Credit Suisse Securities (USA) LLC, as agent,
dated August 4, 2006 and an amendment to the Preferred
Interest Agreement by and among CSF I, Credit Suisse
International and Credit Suisse Securities (USA) LLC, as agent,
dated August 4, 2006. The arrangement with Credit Suisse
allows the Company, at the Companys option and subject to
customary closing conditions, to extend the $220 million
notes and preferred interest maturities of CSF I from October
2008 to June 2010. In addition, the previous settlement date for
any share price appreciation beyond a 20% compound annual growth
rate since the original date of purchase by CSF I, may be
extended 30 days to early December 2008. As part of this
extension arrangement, the Company intends to contribute to CSF
I additional collateral in the form of treasury shares to
maintain a blended interest rate of CSF I facility of
approximately 7.5%. The Company expects to implement this
extension arrangement by March 17, 2008.
PART III
|
|
Item 10
|
Directors,
Executive Officers and Corporate Governance
|
NRG Energy, Inc. has adopted a code of ethics entitled NRG
Code of Conduct that applies to directors, officers and
employees, including the chief executive officer and senior
financial officers of NRG Energy, Inc. It may be accessed
through the Corporate Governance section of NRG Energy
Inc.s website
at
http://www.nrgenergy.com/investor/corpgov/.htm.
NRG Energy, Inc. also elects to disclose the information
required by
Form 8-K,
Item 5.05, Amendments to the registrants code
of ethics, or waiver of a provision of the code of ethics,
through the Companys website, and such information will
remain available on this website for at least a
12-month
period. A copy of the NRG Energy, Inc. Code of
Conduct is available in print to any shareholder who
requests it.
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2008 Annual Meeting of
Stockholders to be held May 14, 2008.
|
|
Item 11
|
Executive
Compensation
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2008 Annual Meeting of
Stockholders to be held May 14, 2008.
124
|
|
Item 12
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2008 Annual Meeting of
Stockholders to be held May 14, 2008.
|
|
Item 13
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2008 Annual Meeting of
Stockholders to be held May 14, 2008.
|
|
Item 14
|
Principal
Accountant Fees and Services
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2008 Annual Meeting of
Stockholders to be held May 14, 2008.
PART IV
Item 15 Exhibits
and Financial Statement Schedules
(a)(1)
Financial Statements
The following consolidated financial statements of NRG Energy,
Inc. and related notes thereto, together with the reports
thereon of KPMG LLP are included herein:
Consolidated Statement of Operations Years ended
December 31, 2007, 2006 and 2005
Consolidated Balance Sheet December 31, 2007
and 2006
Consolidated Statement of Cash Flows Years ended
December 31, 2007, 2006 and 2005
Consolidated Statement of Stockholders Equity and
Comprehensive Income/(Loss) Years ended
December 31, 2007, 2006 and 2005
Notes to Consolidated Financial Statements
(a)(2) Financial Statement Schedule
The following Consolidated Financial Statement Schedule of NRG
Energy, Inc. is filed as part of Item 15(d) of this report
and should be read in conjunction with the Consolidated
Financial Statements.
Schedule II Valuation and Qualifying Accounts
All other schedules for which provision is made in the
applicable accounting regulation of the Securities and Exchange
Commission are not required under the related instructions or
are inapplicable, and therefore, have been omitted.
(a)(3) Exhibits: See Exhibit Index
submitted as a separate section of this report.
See Exhibit Index submitted as a separate section of this
report.
125
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
NRG Energy Inc.s management is responsible for
establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f).
Under the supervision and with the participation of the
Companys management, including its principal executive
officer, principal financial officer and principal accounting
officer, the Company conducted an evaluation of the
effectiveness of its internal control over financial reporting
based on the framework in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the
Companys evaluation under the framework in Internal
Control Integrated Framework, the Companys
management concluded that its internal control over financial
reporting was effective as of December 31, 2007.
The effectiveness of the Companys internal control over
financial reporting as of December 31, 2007 has been
audited by KPMG LLP, the Companys independent registered
public accounting firm, as stated in its report which is
included in this
Form 10-K.
126
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited NRG Energy Inc.s internal control over
financial reporting as of December 31, 2007, based on
criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). NRG Energy
Inc.s management is responsible for maintaining effective
internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial
reporting, included in the accompanying Managements Report
on Internal Control over Financial Reporting. Our responsibility
is to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, NRG Energy, Inc. maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2007, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of NRG Energy, Inc. as of
December 31, 2007 and 2006, and the related consolidated
statements of operations, stockholders equity and
comprehensive income/(loss), and cash flows for each of the
years in the three year period ended December 31, 2007, and
our report dated February 28, 2008, expressed an
unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
KPMG LLP
Philadelphia, Pennsylvania
February 28, 2008
127
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
NRG Energy, Inc. and subsidiaries as of December 31, 2007
and 2006, and the related consolidated statements of operations,
stockholders equity and comprehensive income (loss), and
cash flows for each of the years in the three-year period ended
December 31, 2007. In connection with our audits of the
consolidated financial statements, we also have audited
financial statement schedule Schedule II. Valuation
and Qualifying Accounts. These consolidated financial
statements and financial statement schedule are the
responsibility of the Companys management. Our
responsibility is to express an opinion on these consolidated
financial statements and financial statement schedule based on
our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of NRG Energy, Inc. and subsidiaries as of
December 31, 2007 and 2006, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2007, in conformity
with U.S. generally accepted accounting principles. Also in
our opinion, the related financial statement schedule, when
considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly, in all material
respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial
statements, the Company adopted Emerging Issues Task Force Issue
No. 04-6,
Accounting for Stripping Costs Incurred during Production in
the Mining Industry, and Statement of Financial Accounting
Standards (SFAS) No. 123(R), Share Based Payments,
and related interpretations on January 1, 2006. As
discussed in Note 2 to the consolidated financial
statements, the Company also adopted SFAS No. 158,
Employers Accounting for Defined Benefit Pension and
Other Postretirement Plans an amendment of
SFAS No. 87, 88, 106, and 132(R), effective
December 31, 2006. As discussed in Note 2 to the
consolidated financial statements, the Company adopted Financial
Accounting Standards Board Interpretation No. 48,
Accounting for Uncertainty in Income Taxes an
Interpretation of SFAS No. 109, on January 1,
2007.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), NRG
Energy, Inc.s internal control over financial reporting as
of December 31, 2007, based on criteria established in
Internal Control Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO), and our report dated February 28, 2008
expressed an unqualified opinion on the effectiveness of the
Companys internal control over financial reporting.
/s/ KPMG LLP
KPMG LLP
Philadelphia, Pennsylvania
February 28, 2008
128
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
For the
|
|
|
For the
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions except per share amounts)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,378
|
|
|
|
3,265
|
|
|
|
1,829
|
|
Depreciation and amortization
|
|
|
658
|
|
|
|
590
|
|
|
|
158
|
|
General and administrative
|
|
|
309
|
|
|
|
276
|
|
|
|
176
|
|
Development costs
|
|
|
101
|
|
|
|
36
|
|
|
|
|
|
Other charges
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,446
|
|
|
|
4,167
|
|
|
|
2,175
|
|
Gain on sale of assets
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
1,560
|
|
|
|
1,418
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
54
|
|
|
|
60
|
|
|
|
104
|
|
Write downs and gains/(losses) on sales of equity method
investments
|
|
|
1
|
|
|
|
8
|
|
|
|
(31
|
)
|
Other income, net
|
|
|
55
|
|
|
|
156
|
|
|
|
54
|
|
Refinancing expenses
|
|
|
(35
|
)
|
|
|
(187
|
)
|
|
|
(65
|
)
|
Interest expense
|
|
|
(689
|
)
|
|
|
(590
|
)
|
|
|
(177
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(614
|
)
|
|
|
(553
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
946
|
|
|
|
865
|
|
|
|
110
|
|
Income tax expense
|
|
|
377
|
|
|
|
322
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
569
|
|
|
|
543
|
|
|
|
68
|
|
Income from discontinued operations, net of income taxes
|
|
|
17
|
|
|
|
78
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
586
|
|
|
|
621
|
|
|
|
84
|
|
Preference stock dividends
|
|
|
55
|
|
|
|
50
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Available for Common Stockholders
|
|
$
|
531
|
|
|
$
|
571
|
|
|
$
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
basic
|
|
|
240
|
|
|
|
258
|
|
|
|
169
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
2.14
|
|
|
$
|
1.90
|
|
|
$
|
0.28
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
0.07
|
|
|
|
0.31
|
|
|
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Basic
|
|
$
|
2.21
|
|
|
$
|
2.21
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
288
|
|
|
|
301
|
|
|
|
171
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
1.95
|
|
|
$
|
1.78
|
|
|
$
|
0.28
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
0.06
|
|
|
|
0.26
|
|
|
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Diluted
|
|
$
|
2.01
|
|
|
$
|
2.04
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements
129
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,132
|
|
|
$
|
777
|
|
Restricted cash
|
|
|
29
|
|
|
|
41
|
|
Accounts receivable trade, less allowance for
doubtful accounts of $1 and $1
|
|
|
482
|
|
|
|
369
|
|
Current portion of capital lease
|
|
|
30
|
|
|
|
27
|
|
Taxes receivable
|
|
|
58
|
|
|
|
63
|
|
Inventory
|
|
|
451
|
|
|
|
420
|
|
Derivative instruments valuation
|
|
|
1,034
|
|
|
|
1,230
|
|
Deferred income taxes
|
|
|
124
|
|
|
|
|
|
Collateral on deposits in support of energy risk management
activities
|
|
|
85
|
|
|
|
27
|
|
Prepayments and other current assets
|
|
|
86
|
|
|
|
105
|
|
Current assets discontinued operations
|
|
|
51
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
3,562
|
|
|
|
3,083
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
In service
|
|
|
12,678
|
|
|
|
12,433
|
|
Under construction
|
|
|
337
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
13,015
|
|
|
|
12,520
|
|
Less accumulated depreciation
|
|
|
(1,695
|
)
|
|
|
(974
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
11,320
|
|
|
|
11,546
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
425
|
|
|
|
344
|
|
Note receivable affiliates
|
|
|
126
|
|
|
|
114
|
|
Capital lease, less current portion
|
|
|
365
|
|
|
|
365
|
|
Goodwill
|
|
|
1,786
|
|
|
|
1,789
|
|
Intangible assets, net of accumulated amortization of $372 and
$259
|
|
|
873
|
|
|
|
981
|
|
Nuclear decommissioning trust fund
|
|
|
384
|
|
|
|
352
|
|
Derivative instruments valuation
|
|
|
150
|
|
|
|
439
|
|
Other non-current assets
|
|
|
176
|
|
|
|
262
|
|
Intangible assets held-for-sale
|
|
|
14
|
|
|
|
79
|
|
Non-current assets discontinued operations
|
|
|
93
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
4,392
|
|
|
|
4,807
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
19,274
|
|
|
$
|
19,436
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
130
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except share data)
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
466
|
|
|
$
|
123
|
|
Accounts payable trade
|
|
|
381
|
|
|
|
327
|
|
Accounts payable affiliates
|
|
|
3
|
|
|
|
2
|
|
Derivative instruments valuation
|
|
|
917
|
|
|
|
964
|
|
Deferred income taxes
|
|
|
|
|
|
|
164
|
|
Accrued interest expense
|
|
|
185
|
|
|
|
131
|
|
Other accrued expenses
|
|
|
189
|
|
|
|
130
|
|
Other current liabilities
|
|
|
99
|
|
|
|
163
|
|
Current liabilities discontinued operations
|
|
|
37
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
2,277
|
|
|
|
2,032
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
7,895
|
|
|
|
8,603
|
|
Nuclear decommissioning reserve
|
|
|
307
|
|
|
|
289
|
|
Nuclear decommissioning trust liability
|
|
|
326
|
|
|
|
324
|
|
Postretirement and other benefit obligations
|
|
|
263
|
|
|
|
301
|
|
Deferred income taxes
|
|
|
843
|
|
|
|
554
|
|
Derivative instruments valuation
|
|
|
759
|
|
|
|
351
|
|
Out-of-market contracts
|
|
|
628
|
|
|
|
897
|
|
Other non-current liabilities
|
|
|
149
|
|
|
|
116
|
|
Non-current liabilities discontinued operations
|
|
|
76
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
11,246
|
|
|
|
11,499
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
13,523
|
|
|
|
13,531
|
|
|
|
|
|
|
|
|
|
|
3.625% convertible perpetual preferred stock; $0.01 par
value; 250,000 shares issued and outstanding (at
liquidation value of $250, net of issuance costs)
|
|
|
247
|
|
|
|
247
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
4% convertible perpetual preferred stock; $0.01 par value;
420,000 shares issued and outstanding (at liquidation value
of $420, net of issuance costs)
|
|
|
406
|
|
|
|
406
|
|
5.75% convertible perpetual preferred stock; $0.01 par
value, 2,000,000 shares issued and outstanding (at
liquidation value of $500, net of issuance costs)
|
|
|
486
|
|
|
|
486
|
|
Common Stock; $0.01 par value; 500,000,000 shares
authorized; 261,285,529 and 274,248,264 shares issued and
236,734,929 and 244,647,102 outstanding at December 31,
2007 and 2006
|
|
|
3
|
|
|
|
3
|
|
Additional paid-in-capital
|
|
|
4,092
|
|
|
|
4,474
|
|
Retained earnings
|
|
|
1,270
|
|
|
|
739
|
|
Less treasury stock, at cost 24,550,600 and
29,601,162 shares at December 31, 2007 and 2006
|
|
|
(638
|
)
|
|
|
(732
|
)
|
Accumulated other comprehensive (loss)/income
|
|
|
(115
|
)
|
|
|
282
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity
|
|
|
5,504
|
|
|
|
5,658
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
19,274
|
|
|
$
|
19,436
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
131
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENT OF STOCKHOLDERS EQUITY
AND
COMPREHENSIVE INCOME/(LOSS)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Other
|
|
|
Total
|
|
|
|
Serial Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Treasury
|
|
|
Comprehensive
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Shares
|
|
|
Stock
|
|
|
Shares
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Income/(Loss)
|
|
|
Equity
|
|
|
|
(In millions)
|
|
|
Balances at December 31, 2004
|
|
$
|
406
|
|
|
|
0.4
|
|
|
$
|
3
|
|
|
|
174
|
|
|
$
|
2,415
|
|
|
$
|
197
|
|
|
$
|
(405
|
)
|
|
$
|
76
|
|
|
$
|
2,692
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
84
|
|
|
|
|
|
|
|
|
|
|
|
84
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(72
|
)
|
|
|
(72
|
)
|
Unrealized loss on derivatives
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(203
|
)
|
|
|
(203
|
)
|
Minimum pension liability, net of $3 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss for 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(197
|
)
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(258
|
)
|
|
|
|
|
|
|
(258
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2005
|
|
$
|
406
|
|
|
|
0.4
|
|
|
$
|
3
|
|
|
|
161
|
|
|
$
|
2,429
|
|
|
$
|
261
|
|
|
$
|
(663
|
)
|
|
$
|
(205
|
)
|
|
$
|
2,231
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
621
|
|
|
|
|
|
|
|
|
|
|
|
621
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60
|
|
|
|
60
|
|
Unrealized gain on derivatives, net of $135 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
405
|
|
|
|
405
|
|
Minimum pension liability, net of $3 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,093
|
|
Impact upon adoption of SFAS 158, net of $10 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
15
|
|
Reduction to tax valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Impact upon adoption of EITF 04-6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(93
|
)
|
|
|
|
|
|
|
|
|
|
|
(93
|
)
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Issuance of common stock to the public
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
986
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
986
|
|
Issuance of preferred stock
|
|
|
486
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
486
|
|
Issuance of common and treasury stock to the shareholders of
Texas Genco LLC
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
71
|
|
|
|
1,028
|
|
|
|
|
|
|
|
663
|
|
|
|
|
|
|
|
1,691
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
|
|
(732
|
)
|
|
|
|
|
|
|
(732
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2006
|
|
$
|
892
|
|
|
|
2.4
|
|
|
$
|
3
|
|
|
|
245
|
|
|
$
|
4,474
|
|
|
$
|
739
|
|
|
$
|
(732
|
)
|
|
$
|
282
|
|
|
$
|
5,658
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
586
|
|
|
|
|
|
|
|
|
|
|
|
586
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
|
|
|
|
73
|
|
Unrealized loss on derivatives, net of $310 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(474
|
)
|
|
|
(474
|
)
|
Available-for-sale securities, net of $1 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
Defined benefit plan prior service cost of $4 and
net loss of $(2), net of $2 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189
|
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Reduction to tax valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
(353
|
)
|
Retirement of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(447
|
)
|
|
|
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007
|
|
$
|
892
|
|
|
|
2.4
|
|
|
$
|
3
|
|
|
|
237
|
|
|
$
|
4,092
|
|
|
$
|
1,270
|
|
|
$
|
(638
|
)
|
|
$
|
(115
|
)
|
|
$
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
132
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
586
|
|
|
$
|
621
|
|
|
$
|
84
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions less than equity in earnings of unconsolidated
affiliates
|
|
|
(33
|
)
|
|
|
(33
|
)
|
|
|
(8
|
)
|
Depreciation and amortization of nuclear fuel
|
|
|
719
|
|
|
|
654
|
|
|
|
195
|
|
Amortization and write-off of deferred financing costs and debt
discount/premiums
|
|
|
66
|
|
|
|
79
|
|
|
|
14
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(156
|
)
|
|
|
(490
|
)
|
|
|
17
|
|
Amortization of equity-based compensation
|
|
|
19
|
|
|
|
14
|
|
|
|
12
|
|
Write down and (gains)/losses on sale of equity method
investments
|
|
|
(1
|
)
|
|
|
(8
|
)
|
|
|
31
|
|
(Gain)/loss on sale and disposal of equipment
|
|
|
(17
|
)
|
|
|
10
|
|
|
|
4
|
|
Impairment charges and asset write downs
|
|
|
20
|
|
|
|
|
|
|
|
6
|
|
Changes in derivatives
|
|
|
77
|
|
|
|
(149
|
)
|
|
|
143
|
|
Changes in deferred income taxes
|
|
|
352
|
|
|
|
327
|
|
|
|
2
|
|
Gain on legal settlement
|
|
|
|
|
|
|
(67
|
)
|
|
|
(14
|
)
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(76
|
)
|
|
|
(6
|
)
|
Gain on sale of emission allowances
|
|
|
(31
|
)
|
|
|
(64
|
)
|
|
|
|
|
Change in nuclear decommissioning trust liability
|
|
|
32
|
|
|
|
12
|
|
|
|
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(125
|
)
|
|
|
454
|
|
|
|
(405
|
)
|
Settlement of out-of-market power contracts
|
|
|
|
|
|
|
(1,073
|
)
|
|
|
|
|
Cash provided by changes in other working capital, net of
acquisition and disposition effects
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
(102
|
)
|
|
|
87
|
|
|
|
(8
|
)
|
Inventory
|
|
|
(38
|
)
|
|
|
(50
|
)
|
|
|
(14
|
)
|
Prepayments and other current assets
|
|
|
22
|
|
|
|
43
|
|
|
|
(35
|
)
|
Accounts payable
|
|
|
49
|
|
|
|
(73
|
)
|
|
|
57
|
|
Accrued expenses and other current liabilities
|
|
|
106
|
|
|
|
133
|
|
|
|
(16
|
)
|
Other assets and liabilities
|
|
|
(28
|
)
|
|
|
57
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
1,517
|
|
|
|
408
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Texas Genco LLC, WCP and Padoma , net of cash
acquired
|
|
|
|
|
|
|
(4,333
|
)
|
|
|
(5
|
)
|
Capital expenditures
|
|
|
(481
|
)
|
|
|
(221
|
)
|
|
|
(106
|
)
|
Decrease in restricted cash, net
|
|
|
12
|
|
|
|
6
|
|
|
|
45
|
|
Decrease in notes receivable
|
|
|
34
|
|
|
|
27
|
|
|
|
107
|
|
Decrease in trust fund balances
|
|
|
19
|
|
|
|
|
|
|
|
|
|
Purchases of emission allowances
|
|
|
(161
|
)
|
|
|
(135
|
)
|
|
|
|
|
Proceeds from sale of emission allowances
|
|
|
272
|
|
|
|
146
|
|
|
|
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(265
|
)
|
|
|
(227
|
)
|
|
|
|
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
233
|
|
|
|
214
|
|
|
|
|
|
Proceeds from sale of investments and equipment
|
|
|
2
|
|
|
|
86
|
|
|
|
79
|
|
Purchases of securities
|
|
|
(49
|
)
|
|
|
|
|
|
|
|
|
Proceeds from sale of discontinued operations and assets
|
|
|
57
|
|
|
|
260
|
|
|
|
36
|
|
Return of capital from equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
(327
|
)
|
|
|
(4,176
|
)
|
|
|
158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
(55
|
)
|
|
|
(50
|
)
|
|
|
(20
|
)
|
Payment of financing element of acquired derivatives
|
|
|
|
|
|
|
(296
|
)
|
|
|
|
|
Payment for treasury stock
|
|
|
(353
|
)
|
|
|
(732
|
)
|
|
|
(250
|
)
|
Payment of minority interest obligations
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
Funded letter of credit
|
|
|
|
|
|
|
350
|
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
7
|
|
|
|
986
|
|
|
|
|
|
Proceeds from issuance of preferred shares, net of issuance costs
|
|
|
|
|
|
|
486
|
|
|
|
246
|
|
Proceeds from issuance of long-term debt
|
|
|
1,411
|
|
|
|
8,619
|
|
|
|
249
|
|
Payment of deferred debt issuance costs
|
|
|
(5
|
)
|
|
|
(199
|
)
|
|
|
(46
|
)
|
Payments for short and long-term debt
|
|
|
(1,819
|
)
|
|
|
(5,111
|
)
|
|
|
(1,005
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(814
|
)
|
|
|
4,053
|
|
|
|
(830
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
(25
|
)
|
|
|
2
|
|
|
|
37
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
4
|
|
|
|
4
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
355
|
|
|
|
291
|
|
|
|
(569
|
)
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
777
|
|
|
|
486
|
|
|
|
1,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
1,132
|
|
|
$
|
777
|
|
|
$
|
486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
133
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
Note 1
Nature of Business
General
NRG Energy, Inc., NRG, or the Company, is a wholesale power
generation company with a significant presence in major
competitive power markets in the United States. NRG is engaged
in the ownership, development, construction and operation of
power generation facilities, the transacting in and trading of
fuel and transportation services, and the trading of energy,
capacity and related products in the United States and select
international markets.
As of December 31, 2007, NRG had a total portfolio of 191
active operating generation units at 49 power generation plants,
with an aggregate generation capacity of approximately
24,115 MW. Within the United States, NRG has a power
generation portfolio of approximately 22,880 MW of
generation capacity in 175 active generating units at 43 plants,
primarily located in the Texas or ERCOT region (approximately
10,805 MW), the Northeast (approximately 6,980 MW),
South Central (approximately 2,850 MW), and West
(approximately 2,130 MW) regions of the United States, with
approximately 115 MW of additional generation capacity from
the Companys thermal assets.
NRG was incorporated as a Delaware corporation on May 29,
1992. NRGs common stock is listed on the New York Stock
Exchange under the symbol NRG. The Companys
headquarters and principal executive offices are located at 211
Carnegie Center, Princeton, New Jersey 08540. NRGs
telephone number is
(609) 524-4500.
The address of the Companys website is
www.nrgenergy.com. NRGs recent annual reports,
quarterly reports, current reports, and other periodic filings
are available free of charge through the Companys website.
Note 2
Summary of Significant Accounting Policies
Principles
of Consolidation and Basis of Presentation
The consolidated financial statements include NRGs
accounts and operations and those of its subsidiaries in which
the Company has a controlling interest. All significant
intercompany transactions and balances have been eliminated in
consolidation. The usual condition for a controlling financial
interest is ownership of a majority of the voting interests of
an entity. However, a controlling financial interest may also
exist in entities, such as a variable interest entity, through
arrangements that do not involve controlling voting interests.
As such, NRG applies the guidance of FASB Interpretation
No. 46(R), Consolidation of Variable Interest Entities,
or FIN 46R, to consolidate variable interest entities,
or VIEs, for which the Company is the primary beneficiary.
FIN 46R requires a variable interest holder to consolidate
a VIE if that party will absorb a majority of the expected
losses of the VIE, receive the majority of the expected residual
returns of the VIE, or both. This party is considered the
primary beneficiary. Conversely, NRG will not consolidate a VIE
in which it has a majority ownership interest when the Company
is not considered the primary beneficiary. In determining the
primary beneficiary, NRG thoroughly evaluates the VIEs design,
capital structure, and relationships among variable interest
holders. If a primary beneficiary cannot be determined by a
qualitative analysis, a quantitative analysis of allocating the
expected cash flows among the variable interest holders is used
in the determination.
As discussed in Note 14, Investments Accounted for by
the Equity Method, NRG also has investments in partnerships,
joint ventures and projects.
Accounting policies for all of NRGs operations are in
accordance with accounting principles generally accepted in the
United States of America. Upon its emergence from bankruptcy on
December 5, 2003, the Company qualified for and adopted
fresh start reporting, or Fresh Start, under Statement of
Position
90-7,
Financial Reporting by Entities in Reorganization under the
Bankruptcy Code.
134
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Cash
and Cash Equivalents
Cash and cash equivalents include highly liquid investments with
an original maturity of three months or less at the time of
purchase.
Restricted
Cash
Restricted cash consists primarily of funds held to satisfy the
requirements of certain debt agreements and funds held within
the Companys projects that are restricted in their use.
These funds are used to pay for current operating expenses and
current debt service payments, per the restrictions of the debt
agreements.
Inventory
Inventory is valued at the lower of weighted average cost or
market and consists principally of fuel oil, coal and raw
materials used to generate steam. Spare parts inventory is
valued at a weighted average cost, since the Company expects to
recover these costs in the ordinary course of business. Sales of
inventory are classified as an operating activity in the
consolidated statements of cash flows.
Property,
Plant and Equipment
Property, plant and equipment are stated at cost however
impairment adjustments are recorded whenever events or changes
in circumstances indicate that their carrying values may not be
recoverable. NRG also classifies nuclear fuel related to the
Companys 44% ownership interest in STP as part of the
Companys property, plant, and equipment. Significant
additions or improvements extending asset lives are capitalized
as incurred, while repairs and maintenance that do not improve
or extend the life of the respective asset are charged to
expense as incurred. Depreciation other than nuclear fuel is
computed using the straight-line method, while nuclear fuel is
amortized based on units of production over the estimated useful
lives. Certain assets and their related accumulated depreciation
amounts are adjusted for asset retirements and disposals with
the resulting gain or loss included in other income/(expense) in
the consolidated statements of operations.
Asset
Impairments
Long-lived assets that are held and used are reviewed for
impairment whenever events or changes in circumstances indicate
carrying values may not be recoverable. Such reviews are
performed in accordance with SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived
Assets, or SFAS 144. An impairment loss is recognized
if the total future estimated undiscounted cash flows expected
from an asset are less than its carrying value. An impairment
charge is measured by the difference between an assets
carrying amount and fair value with the difference recorded in
operating costs and expenses in the statements of operations.
Fair values are determined by a variety of valuation methods,
including appraisals, sales prices of similar assets and present
value techniques.
Investments accounted for by the equity method are reviewed for
impairment in accordance with APB No. 18, The Equity
Method of Accounting for Investments in Common Stock, or APB
18, which requires that a loss in value of an investment that is
other than a temporary decline should be recognized. The Company
identifies and measures losses in the value of equity method
investments based upon a comparison of fair value to carrying
value.
Discontinued
Operations
Long-lived assets or disposal groups are classified as
discontinued operations when all of the required criteria
specified in SFAS 144 are met. These criteria include,
among others, existence of a qualified plan to dispose of an
asset or disposal group, an assessment that completion of a sale
within one year is probable and approval of the appropriate
level of management. In addition, upon completion of the
transaction, the operations and cash flows of the disposal group
must be eliminated from ongoing operations of the Company, and
the disposal group must not
135
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
have any significant continuing involvement with the Company.
Discontinued operations are reported at the lower of the
assets carrying amount or fair value less cost to sell.
Project
Development Costs and Capitalized Interest
Development costs are expensed in the preliminary stages of a
project and capitalized when the project is deemed to be
commercially viable. Commercial viability is determined by one
or a series of actions including among others, Board of Director
approval pursuant to a formal project plan that subjects the
Company to significant future obligations that can only be
discharged by the use of a Company asset. When a project is
available for operations, previously capitalized project costs
are reclassified to property, plant and equipment and amortized
on a straight-line basis over the estimated useful life of the
projects related assets. Capitalized costs are charged to
expense if a project is abandoned or management otherwise
determines the costs to be unrecoverable.
Interest incurred on funds borrowed to finance capital projects
is capitalized if material. Capitalization of interest is
discontinued when the asset under construction is ready for its
intended use or when a project is terminated or construction
ceases.
Debt
Issuance Costs
Debt issuance costs are capitalized and amortized as interest
expense on a basis which approximates the effective interest
method over the term of the related debt.
Intangible
Assets
Intangible assets represent contractual rights held by NRG. The
Company recognizes specifically identifiable intangible assets
including emission allowances, power and fuel contracts when
specific rights and contracts are acquired. In addition, NRG
also established values for emission allowances and power
contracts upon adoption of Fresh Start reporting. These
intangible assets are amortized on either contracted volumes,
straight line or units of production basis.
Intangible assets determined to have indefinite lives are not
amortized, but rather are tested for impairment at least
annually or more frequently if events or changes in
circumstances indicate that such acquired intangible assets have
been determined to have finite lives and should now be amortized
over their useful lives. NRG had no intangible assets with
indefinite lives recorded as of December 31, 2007.
Goodwill
In accordance with SFAS No. 142, Goodwill and Other
Intangible Assets, or SFAS 142, the Company recognizes
goodwill for the excess cost of an acquired entity over the net
value assigned to assets acquired and liabilities assumed.
NRG performs goodwill impairment tests annually, typically
during the fourth quarter and when events or changes in
circumstances indicate that the carrying value may not be
recoverable. Goodwill impairment is determined using a two step
process:
|
|
|
|
Step one
|
Identify potential impairment by comparing the fair value of a
reporting unit to the book value, including goodwill. If the
fair value exceeds book value, goodwill of the reporting unit is
not considered impaired. If the book value exceeds fair value,
proceed to step two.
|
|
|
Step two
|
Compare the implied fair value of the reporting units
goodwill to the book value of the reporting unit goodwill. If
the book value of goodwill exceeds fair value, an impairment
charge is recognized for the sum of such excess.
|
136
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Income
Taxes
NRG accounts for income taxes using the liability method in
accordance with SFAS No. 109, Accounting for Income
Taxes, or SFAS 109, which requires that the Company use
the asset and liability method of accounting for deferred income
taxes and provide deferred income taxes for all significant
temporary differences.
NRG has two categories of income tax expense or
benefit current and deferred, as follows:
|
|
|
|
|
Current income tax expense or benefit consists solely of regular
tax less applicable tax credits, and
|
|
|
|
Deferred income tax expense or benefit is the change in the net
deferred income tax asset or liability, excluding amounts
charged or credited to accumulated other comprehensive income.
|
NRG reports some of the Companys revenues and expenses
differently for financial statement purposes than for income tax
return purposes resulting in temporary and permanent differences
between the Companys financial statements and income tax
returns. The tax effects of such temporary differences are
recorded as either deferred income tax assets or deferred income
tax liabilities in the Companys consolidated balance
sheets. NRG measures the Companys deferred income tax
assets and deferred income tax liabilities using income tax
rates that are currently in effect. A valuation allowance is
recorded to reduce the Companys net deferred tax
liabilities to an amount that is more likely than not to be
realized.
In January 2007, the Company adopted FASB Interpretation Number
48, Accounting for Uncertainty in Income Taxes an
interpretation of FASB Statement No. 109, or
FIN 48, which applies to all tax positions related to
income taxes subject to SFAS 109. FIN 48 requires a
new evaluation process for all tax positions taken, recognizing
tax benefits when it is more-likely-than-not that a tax position
will be sustained upon examination by the authorities. The
benefit from a position that has surpassed the
more-likely-than-not threshold is the largest amount of benefit
that is more than 50% likely to be realized upon settlement. The
Company recognizes interest and penalties accrued related to
unrecognized tax benefits as a component of income tax expense.
Revenue
Recognition
NRG is primarily a power generation company, operating a
portfolio of majority-owned electric generating plants and
certain plants in which the Companys ownership interest is
50% or less, which are accounted for under the equity method of
accounting. NRG also produces thermal energy for sale to
customers, principally through steam and chilled water
facilities.
Energy Both physical and financial
transactions are entered into to optimize the financial
performance of NRGs generating facilities. Electric energy
revenue is recognized upon transmission to the customer.
Physical transactions, or the sale of generated electricity to
meet supply and demand, are recorded on a gross basis in the
Companys consolidated statements of operations. Financial
transactions, or the buying and selling of energy for trading
purposes, are recorded net within operating revenues in the
consolidated statements of operations in accordance with EITF
Issue
No. 02-3,
Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading
and Risk Management Activities, or EITF 02-3.
Capacity Capacity revenues are recognized
when contractually earned, and consist of revenues received from
a third party at either the market or a negotiated contract
price for making installed generation capacity available in
order to satisfy system integrity and reliability requirements.
Sale of Emission Allowances NRG records the
Companys bank of emission allowances as part of the
Companys intangible assets. From time to time, management
may authorize the transfer from the Companys emission bank
to intangible assets held-for-sale as part of the Companys
asset optimization strategy. NRG records the sale of emission
allowances on a net basis within other income in the
Companys consolidated statements of operations.
137
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Contract Amortization Liabilities recognized
from power sales agreements assumed at Fresh Start and through
acquisitions related to the sale of electric capacity and energy
in future periods for which the fair value has been determined
to be significantly less than market is amortized as an increase
to revenue over the term of each underlying contract based on
actual generation
and/or
contracted volumes.
Derivative
Financial Instruments
NRG accounts for derivative financial instruments under
SFAS 133. SFAS 133 requires the Company to record all
derivatives on the balance sheet at fair value unless they
qualify for a Normal Purchase or Normal Sale, or NPNS,
exception. 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
|
|
|
|
Deferred and recorded as a component of accumulated other
comprehensive income, or OCI, until the hedged transactions
occur and are recognized in earnings for forecasted transactions.
|
NRGs primary derivative instruments are power sales
contracts, fuels purchase contracts, other energy related
commodities, and interest rate instruments used to mitigate
variability in earnings due to fluctuations in market prices and
interest rates. On an ongoing basis, NRG assesses the
effectiveness of all derivatives that are designated as hedges
for accounting purposes in order to determine that each
derivative continues to be highly effective in offsetting
changes in fair values or cash flows of hedged items. Internal
analyses that measure the statistical correlation between the
derivative and the associated hedged item determine the
effectiveness of such an energy contract designated as a hedge.
If it is determined that the derivative instrument is not highly
effective as a hedge, hedge accounting will be discontinued
prospectively. Hedge accounting will also be discontinued on
contracts related to commodity price risk previously accounted
for as cash flow hedges when it is probable that delivery will
not be made against these contracts. If the derivative
instrument is terminated, the effective portion of this
derivative in OCI will be frozen until the underlying hedged
item is delivered.
Revenues and expenses on contracts that qualify for the NPNS
exception are recognized when the underlying physical
transaction is completed. While these contracts are considered
derivative financial instruments under SFAS 133, they are
not recorded at fair value, but on an accrual basis of
accounting. If it is determined that a transaction designated as
NPNS no longer meets the scope exception, the fair value of the
related contract is recorded on the balance sheet and
immediately recognized through earnings.
NRGs trading activities include contracts entered into to
profit from market price changes as opposed to hedging an
exposure, and are subject to limits in accordance with the
Companys risk management policy. These contracts are
recognized on the balance sheet at fair value and changes in the
fair value of these derivative financial instruments are
recognized in earnings. These trading activities are a
complement to NRGs energy marketing portfolio.
Effective July, 1, 2007, the Company adopted the Emerging Issues
Task Force, or EITF, Topic D-109, Determining the Nature of a
Host Contract Related to a Hybrid Financial Instrument Issued in
the Form of a Share under FASB Statement No. 133. This
Topic conveys the SEC staffs views on determining whether
the characteristics of a host contract in a hybrid financial
instruments issued in the form of a share is more like debt or
equity. The SEC staff believes that in evaluating an embedded
derivative feature for separation under FASB Statement 133, the
consideration of the economic characteristics and risks of the
host contract should not ignore the stated or implied
substantive terms and features of the hybrid financial
instrument. The adoption of Topic D-109 did not have an impact
on the Companys, results of operations, financial position
or cash flows.
138
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Foreign
Currency Translation and Transaction Gains and
Losses
The local currencies are generally the functional currency of
NRGs foreign operations. Foreign currency denominated
assets and liabilities are translated at end-of-period rates of
exchange. Revenues, expenses, and cash flows are translated at
the weighted-average rates of exchange for the period. The
resulting currency translation adjustments are accumulated and
reported as a separate component of stockholders equity
and are not included in the determination of the Companys
statements of operations. Foreign currency transaction gains or
losses are reported within other income/(expense) in the
Companys statements of operations. For the years ended
December 31, 2007, 2006 and 2005, amounts recognized as
foreign currency transaction gains (losses) were immaterial.
Concentrations
of Credit Risk
Financial instruments, which potentially subject NRG to
concentrations of credit risk, consist primarily of cash, trust
funds, accounts receivable, notes receivable, and investments in
debt securities. Cash and cash equivalents are held at financial
institutions with high credit ratings. Trust funds are held in
accounts managed by experienced investment advisors. Accounts
receivable, notes receivable, and derivative instruments are
concentrated within entities engaged in the energy industry.
These industry concentrations may impact the Companys
overall exposure to credit risk, either positively or
negatively, in that the customers may be similarly affected by
changes in economic, industry or other conditions. Receivables
are generally not collateralized; however, NRG believes that the
credit risk posed by industry concentration is offset by the
diversification and creditworthiness of the Companys
customer base.
Fair
Value of Financial Instruments
The carrying amount of cash and cash equivalents, trust funds,
receivables, accounts payables, and accrued liabilities
approximate fair value because of the short-term maturity of
these instruments. The carrying amounts of long-term receivables
usually approximate fair value, as the effective rates for these
instruments are comparable to market rates at year-end,
including current portions. Any differences are disclosed in
Note 4, Financial Instruments. The fair value of
long-term debt is based on quoted market prices for those
instruments that are publicly traded, or estimated based on the
income approach valuation technique for non-publicly traded
debt. During the fourth quarter 2007, the Company recorded an
$11 million impairment charge related to an investment in
commercial paper reducing its carrying value to approximately
$32 million.
Asset
Retirement Obligations
NRG has adopted SFAS No. 143, Accounting for Asset
Retirement Obligations, or SFAS 143, which requires an
entity to recognize the fair value of a liability for an asset
retirement obligation in the period in which it is incurred.
Upon initial recognition of a liability for an asset retirement
obligation, an entity shall capitalize an asset retirement cost
by increasing the carrying amount of the related long-lived
asset by the same amount as the liability. Over time, the
liability is accreted to its present value each period, while
the capitalized cost is depreciated over the useful life of the
related asset. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for
which a legal obligation exists under enacted laws, statutes,
written or oral contracts, including obligations arising under
the doctrine of promissory estoppel. In addition, NRG has also
identified conditional asset retirement obligations for asbestos
removal and disposal, which are specific to certain power
generation operations. Under FASB Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations,
or FIN 47, a conditional asset retirement obligation is
reasonably estimable if (a) it is evident that the fair
value of the obligation is embodied in the acquisition price of
the asset, (b) an active market exists for the transfer of
the obligation, or (c) sufficient information exists to
apply an expected present value technique.
These asset retirement obligations are primarily related to the
future dismantlement of equipment on leased property and
environment obligations related to nuclear decommissioning, ash
disposal site closures, and fuel
139
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
storage facilities. See Note 6, Nuclear Decommissioning
Trust Fund, for a further discussion of NRGs
nuclear decommissioning obligations.
The following table represents the balances of the asset
retirement obligation as of December 31, 2007 and 2006,
along with the additions, reductions and accretion related to
the Companys asset retirement obligation for the year
ended December 31, 2007:
|
|
|
|
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Balance as of December 31, 2006
|
|
$
|
381
|
|
Additions
|
|
|
4
|
|
Reduction
|
|
|
(1
|
)
|
Accretion Expense
|
|
|
7
|
|
Accretion Other
|
|
|
18
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
$
|
409
|
|
|
|
|
|
|
Pensions
NRG offers pension benefits through either a defined benefit
pension plan or a cash balance plan. In addition, the Company
provides postretirement health and welfare benefits for certain
groups of employees. Effective December 31, 2006, NRG
accounts for pension and other postretirement benefits in
accordance with SFAS No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans an amendment of FASB Statements No. 87,
88, 106 and 132(R), or SFAS 158. NRG recognizes the
funded status of the Companys defined benefit plans in the
statement of financial position and records an offset to other
comprehensive income. In addition, NRG also recognizes on an
after tax basis, as a component of other comprehensive income,
gains and losses as well as all prior service costs that have
not been included as part of the Companys net periodic
benefit cost. The determination of NRGs 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. NRGs
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 the Company.
Stock-Based
Compensation
On January 1, 2006, NRG transitioned from
SFAS No. 123, Accounting for Stock-Based
Compensation, or SFAS 123, and adopted
SFAS No. 123 (Revised 2004), Share-Based
Payment, or SFAS 123(R), using the modified prospective
method. Under the modified prospective method, NRG applied the
provisions of SFAS 123(R) to new awards of stock-based
compensation and to awards modified, repurchased, or cancelled
after the required effective date. SFAS 123(R) requires
that NRG apply a forfeiture rate to existing awards and apply
the standards fair value recognition provisions. The fair
value of the Companys non-qualified stock options and
performance units are estimated on the date of grant using the
Black-Scholes option-pricing model and the Monte Carlo valuation
model, respectively. NRG uses the Companys common stock
price on the date of grant as the fair value of the
Companys restricted stock units and deferred stock units.
Forfeiture rates are estimated based on an analysis of
NRGs historical forfeitures, employment turnover, and
expected future behavior. The Company recognizes compensation
expense for both graded and cliff vesting awards on a
straight-line basis over the requisite service period for the
entire award.
Investments
Accounted for by the Equity Method
NRG has investments in various international and domestic energy
projects. The equity method of accounting is applied to such
investments in affiliates, which include joint ventures and
partnerships, because the ownership
140
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
structure prevents NRG from exercising a controlling influence
over the operating and financial policies of the projects. Under
this method, equity in pre-tax income or losses of domestic
partnerships and, generally, in the net income or losses of
international projects, are reflected as equity in earnings of
unconsolidated affiliates.
On January 1, 2006, NRG adopted EITF Issue
No. 04-6,
Accounting for Stripping Costs Incurred during Production in
the Mining Industry, or
EITF 04-6.
EITF 04-6
provides that costs incurred to remove overburden and waste
material to access coal seams, or stripping costs; during the
production phase of a mine are variable production costs that
should be included in the costs of the inventory produced during
the period that the stripping costs are incurred. MIBRA GmbH, or
MIBRAG, in which NRG holds a 50% equity investment, has mining
operations which were negatively affected by this pronouncement.
The adoption of
EITF 04-6
did not have a material impact on NRGs consolidated
results of operations, but did have a material impact on
NRGs consolidated financial position. Upon adoption of
EITF 04-6
on January 1, 2006, NRGs investment in MIBRAG was
reduced by 50% of the above mentioned asset, or approximately
$93 million after-tax, with an offsetting charge to
retained earnings.
On January 1, 2006, NRG adopted EITF Issue
No. 05-5,
Accounting for Early Retirement or Post-employment Programs
with Specific Features (such as terms specified in
Altersteilzeit Early Retirement Arrangements), or
EITF 05-5.
The Altersteilzeit, or ATZ, arrangement is a voluntary early
retirement program in Germany designed to create an incentive
for employees, within a certain age group, to transition from
employment into retirement before their legal retirement age. If
certain criteria are met by the employer, the German government
provides to the employer a subsidy for bonuses paid to the
employee and the additional contributions paid by the employer
into the German government pension plan under an ATZ arrangement
for a maximum of six years. Upon adoption of
EITF 05-5
on January 1, 2006, NRG recognized additional equity in
earnings of unconsolidated affiliates of approximately
$2 million, after- tax, from the Companys MIBRAG
interest. This amount reflects the cumulative effect of the
adoption of
EITF 05-5,
and did not materially affect NRGs consolidated financial
position, results of operations, or statement of cash flows for
the year ended December 31, 2006.
Use of
Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at
the date of the financial statements, disclosure of contingent
assets and liabilities at the date of the financial statements,
and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these
estimates.
In recording transactions and balances resulting from business
operations, NRG uses estimates based on the best information
available. Estimates are used for such items as plant
depreciable lives, tax provisions, uncollectible accounts,
actuarially determined benefit costs, and the valuation of
long-term energy commodity contracts, environmental liabilities,
and legal costs incurred in connection with recorded loss
contingencies, among others. In addition, estimates are used to
test long-lived assets for impairment and to determine the fair
value of impaired assets. As better information becomes
available or actual amounts are determinable, the recorded
estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates.
Reclassifications
Certain prior-year amounts have been reclassified for
comparative purposes. These reclassifications had no effect on
the Companys net income or total stockholders
equity, as previously reported.
Stock
Split
On April 25, 2007, NRGs Board of Directors approved a
two-for-one stock split of the Companys outstanding shares
of common stock which was effected through a stock dividend. The
stock split entitled each
141
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
stockholder of record at the close of business on May 22,
2007 to receive one additional share for every outstanding share
of common stock held. The additional shares resulting from the
stock split were distributed by the Companys transfer
agent on May 31, 2007. All share and per share amounts
within this document retroactively reflect the effect of the
stock split.
Recent
Accounting Developments
In September 2006, the Financial Accounting Standards Board, or
FASB, issued SFAS No. 157, Fair Value
Measurements, or SFAS 157. This statement defines fair
value, establishes a framework for measuring fair value, and
expands disclosures about fair value measurements. This
statement is effective for financial statements issued for
fiscal years beginning after November 15, 2007, and interim
periods within those years. In February 2008, the FASB issued
FASB Staff Position, or FSP,
No. FAS 157-1,
Application of FASB Statement No. 157 to FASB Statement
No. 13 and Other Accounting Pronouncements That Address
Fair Value Measurements for Purposes of Lease Classification or
Measurement under Statement 13, which amends SFAS 157
to exclude FASB Statement No. 13, Accounting for
Leases, or SFAS 13, and other accounting pronouncements
that address fair value measurements for purposes of lease
classification or measurement under SFAS 13. In February
2008, the FASB also issued FSP
No. FAS 157-2,
Effective Date of FASB Statement No. 157, which
permitted delayed application of this statement for nonfinancial
assets and nonfinancial liabilities, except for items that are
recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually), until
fiscal years beginning after November 15, 2008, and interim
periods within those fiscal years. NRG partially adopted
SFAS 157 on January 1, 2008, delaying application for
nonfinancial assets and nonfinancial liabilities as permitted.
This partial adoption of SFAS 157 did not have a material
impact on the Companys consolidated financial position,
statement of operations, and cash flows. The Company is
currently evaluating the impact of the deferred portion of
SFAS 157 on the Companys consolidated financial
position, statement of operations, and cash flows.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities-including an amendment of FASB Statement
No. 115, or SFAS 159. This statement provides
entities with an option to measure and report selected financial
assets and liabilities at fair value. This statement requires a
business entity to report unrealized gains and losses on items
for which the fair value option has been elected in earnings at
each subsequent reporting date. An entity may decide whether to
elect the fair value option for each eligible item on its
election date, subject to certain requirements described in the
statement. As of the January 1, 2008 effective date, the
Company elected not to apply this standard to any of its
existing eligible assets or liabilities; therefore there was no
impact on NRGs consolidated financial position, results of
operations, or cash flows.
In April 2007, FASB issued its Staff Position
FIN 39-1,
Amendment of FASB Interpretation No. 39, or FSP
FIN 39-1,
which amends FIN 39, Offsetting of Amounts Related to
Certain Contracts. FSP
FIN 39-1
impacts entities that enter into master netting arrangements as
part of their derivative transactions. Under the guidance in
this new FSP, entities may choose to offset derivative positions
in the financial statements against the fair value of amounts
recognized as cash collateral paid or received under those
arrangements. As of the January 1, 2008 effective date, the
Company elected not to apply this FSP to any of its existing
eligible derivative positions; therefore there was no impact on
NRGs consolidated financial position, results of
operations, or cash flows.
In December 2007, the FASB issued SFAS No. 141
(revised 2007), Business Combinations, or
SFAS 141(R). This statement applies prospectively to all
business combinations for which the acquisition date is on or
after the beginning of an entitys first annual reporting
period beginning on or after December 15, 2008. The
statement establishes principles and requires an acquirer to
recognize and measure in its financial statements the
identifiable assets acquired, the liabilities assumed, and any
minority interest in the acquiree at fair value. It also
recognizes and measures the goodwill acquired or a gain from a
bargain purchase in the business combination and determines what
information to disclose to enable users of an entitys
financial statements to evaluate the nature and financial
effects of the business combination. NRG is currently evaluating
the impact of this statement upon its adoption on the
Companys results of operations, financial position and
cash flows.
142
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
In December 2007, the FASB issued SFAS No. 160,
Noncontrolling Interests in Consolidated Financial
Statements an amendment of ARB No. 51,
Consolidated Financial Statements, or SFAS 160. This
Statement amends ARB No. 51 to establish accounting and
reporting standards for the minority interest in a subsidiary
and for the deconsolidation of a subsidiary. It also amends
certain of ARB No. 51s consolidation procedures for
consistency with the requirements of SFAS 141(R). This
Statement shall be effective and applied prospectively for
fiscal years, and interim periods within those fiscal years,
beginning on or after December 15, 2008, except for the
presentation and disclosure requirements, which shall be applied
retrospectively. NRG is currently evaluating the impact of this
statement upon its adoption on the Companys results of
operations, financial position and cash flows.
NRG has non-qualified stock options for which it estimates the
expected term using the simplified method allowed under Staff
Accounting Bulletin (SAB) No. 107, Share Based
Payment, or SAB 107. In December 2007, the SEC issued
SAB No. 110, Certain Assumptions Used in Valuation
Methods, which eliminates the December 31, 2007
expiration of SAB 107s permission to use this
simplified method. NRG will therefore continue to use this
simplified method after December 31, 2007, for as long as
the Company deems it to be the most appropriate method.
Note 3
Discontinued Operations, Business Acquisitions and
Dispositions
Discontinued
Operations
NRG has classified material business operations, and
gains/(losses) recognized on sales, as discontinued operations
for projects that were sold or have met the required criteria
for such classification. The financial results for the affected
businesses have been accounted for as discontinued operations.
SFAS 144 requires that discontinued operations be valued on
an
asset-by-asset
basis at the lower of carrying amount or fair value, less costs
to sell. In applying the provisions of SFAS 144, the
Companys management considers cash flow analyses, bids,
and offers related to those assets and businesses. In accordance
with the provisions of SFAS 144, discontinued operations
are not depreciated commencing with their classification as
such. The assets and liabilities of the discontinued operations
are reported in NRGs balance sheets as discontinued
operations.
The following table summarizes NRGs discontinued
operations for all periods presented in the Companys
consolidated financial statements:
|
|
|
|
|
|
|
|
|
|
|
Initial Discontinued
|
|
|
|
|
|
|
Operations
|
|
|
Project
|
|
Segment
|
|
Treatment Date
|
|
Disposal Date
|
|
Northbrook New York and Northbrook Energy
|
|
Corporate
|
|
Third Quarter 2005
|
|
Third Quarter 2005
|
Audrain
|
|
Corporate
|
|
Fourth Quarter 2005
|
|
Second Quarter 2006
|
Flinders
|
|
International
|
|
Second Quarter 2006
|
|
Third Quarter 2006
|
Resource Recovery
|
|
Corporate
|
|
Third Quarter 2006
|
|
Fourth Quarter 2006
|
ITISA
|
|
International
|
|
Fourth Quarter 2007
|
|
First Half
2008(a)
|
143
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the major classes of assets and
liabilities classified as discontinued operations as of
December 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
As of
|
|
As of
|
|
|
December 31,
|
|
December 31,
|
|
|
2007
|
|
2006
|
|
|
(In millions)
|
|
Cash and cash equivalents
|
|
$
|
43
|
|
$
|
18
|
Restricted cash
|
|
|
4
|
|
|
3
|
Receivables, net
|
|
|
4
|
|
|
3
|
|
|
|
|
|
|
|
Current assets discontinued operations
|
|
|
51
|
|
|
24
|
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
61
|
|
|
54
|
Other non-current assets
|
|
|
32
|
|
|
28
|
|
|
|
|
|
|
|
Non-current assets discontinued operations
|
|
|
93
|
|
|
82
|
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
|
10
|
|
|
8
|
Accounts payable trade
|
|
|
4
|
|
|
3
|
Other current liabilities
|
|
|
23
|
|
|
17
|
|
|
|
|
|
|
|
Current liabilities discontinued operations
|
|
|
37
|
|
|
28
|
|
|
|
|
|
|
|
Long-term debt
|
|
|
51
|
|
|
44
|
Minority interest
|
|
|
1
|
|
|
1
|
Other non-current liabilities
|
|
|
24
|
|
|
19
|
|
|
|
|
|
|
|
Non-current liabilities discontinued
operations
|
|
$
|
76
|
|
$
|
64
|
|
|
|
|
|
|
|
Summarized results of discontinued operations for the years
ended December 31, 2007, 2006, and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
50
|
|
|
$
|
227
|
|
|
$
|
323
|
|
Operating costs and other expenses
|
|
|
27
|
|
|
|
224
|
|
|
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax income from operations of discontinued components
|
|
|
23
|
|
|
|
3
|
|
|
|
12
|
|
Income tax expense
|
|
|
6
|
|
|
|
1
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations of discontinued components
|
|
|
17
|
|
|
|
2
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Disposal of discontinued components pre-tax gain
|
|
|
|
|
|
|
80
|
|
|
|
13
|
|
Income tax expense
|
|
|
|
|
|
|
4
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on disposal of discontinued components, net of income
taxes
|
|
|
|
|
|
|
76
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
$
|
17
|
|
|
$
|
78
|
|
|
$
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
144
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
There were no pre-tax gains or losses on disposals of the
Companys discontinued operations for the year ended
December 31, 2007. The pre-tax gain on disposal of the
Companys discontinued operations for the years ended
December 31, 2006 and 2005 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
2006
|
|
|
2005
|
|
|
Segment
|
|
|
(In millions)
|
|
Resource Recovery
|
|
$
|
5
|
|
|
$
|
|
|
|
Corporate
|
Flinders
|
|
|
60
|
|
|
|
|
|
|
International
|
Audrain
|
|
|
15
|
|
|
|
|
|
|
Corporate
|
Northbrook New York and Northbrook Energy
|
|
|
|
|
|
|
12
|
|
|
Corporate
|
Other
|
|
|
|
|
|
|
1
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax gain on disposal of discontinued operations
|
|
$
|
80
|
|
|
$
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ITISA On December 18, 2007, NRG entered
into a sale and purchase agreement to sell 100% interest in
Tosli, which holds all NRGs interest in ITISA, to
Brookfield Power Inc., a wholly-owned subsidiary of Brookfield
Asset Management Inc., for a purchase price of approximately
$288 million, plus the assumption of approximately
$60 million in debt. The transaction, which is subject to
the receipt of regulatory approval and other customary closing
conditions, is expected to close during the first half of 2008.
Resource Recovery In 2006, NRG completed the
sale of the Companys Newport and Elk River Resource
Recovery facilities, Becker Ash Disposal facility as well as the
Companys ownership interest in NRG Processing Solutions
LLC, to Resource Recovery Technologies, LLC for total proceeds
of approximately $22 million.
Flinders In 2006, NRG completed the sale of
the Companys 100% owned Flinders power station and related
assets, or Flinders, located near Port Augusta, Australia, which
consisted of two coal-fueled plants Northern and
Playford, with a combined generation capacity of approximately
760 MW, to Babcock & Brown Power Pty, a
subsidiary of Babcock & Brown. Proceeds from the sale
were approximately $242 million (AU$317 million). The
sale resulted in the elimination of approximately
$370 million (AU$485 million) of consolidated
liabilities, including approximately $183 million
(AU$240 million) of non-recourse debt obligations and
approximately $92 million (AU$121 million) in
non-current liabilities related to obligations for the purchase
of electricity and the supply of fuel to the Osborne power
station that were guaranteed by NRG.
Audrain In 2006, NRG completed the sale of
Audrain generating station, a gas-fired peaking facility in
Vandalia, Missouri, to AmerenUE, a subsidiary of Ameren
Corporation. The proceeds from the sale were $115 million,
plus AmerenUEs assumption of $240 million of
non-recourse capital lease obligations and assignment of a
$240 million note receivable. Of the $115 million in
cash proceeds, approximately $20 million was paid to NRG
and the balance was paid to the lenders of NRG Financial I LLC.
Northbrook New York LLC and Northbrook Energy
LLC In 2005, NRG completed the sale of
Northbrook New York LLC and Northbrook Energy LLC. In exchange
for the sale, NRG received net cash proceeds of $36 million
and paid off Northbrook New York LLCs third party debt of
$17 million.
Acquisition
of Texas Genco LLC
On February 2, 2006, NRG acquired Texas Genco LLC, which
subsequently is being managed and accounted for as a separate
business segment referred to as NRGs Texas region. As
such, the results of Texas Genco LLC have been included in
NRGs consolidated financial statements since
February 2, 2006. The purchase price of approximately
$6.2 billion consisted of approximately $4.4 billion
in cash, the issuance of approximately 71 million shares of
NRGs common stock valued at approximately
$1.7 billion, and acquisition costs of approximately
145
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$0.1 billion. The value of NRGs common stock issued
to the sellers was based on NRGs average stock price
immediately before and after the closing date of
February 2, 2006. The acquisition also included the
assumption of approximately $2.7 billion of Texas Genco LLC
debt.
The acquisition of Texas Genco LLC was funded at closing with a
combination of: (i) cash proceeds received upon the
issuance and sale in a public offering of approximately
42 million shares of NRGs common stock at a price of
$24.38 per share; (ii) cash proceeds received upon the
issuance and sale of $1.2 billion aggregate principal
amount of 7.25% Senior Notes due 2014 and $2.4 billion
aggregate principal amount of 7.375% Senior Notes due 2016;
(iii) cash proceeds received upon the issuance and sale in
a public offering of 2,000,000 shares of mandatory
convertible preferred stock at a price of $250 per share;
(iv) funds borrowed under a new senior secured credit
facility consisting of a $3.6 billion term loan facility, a
$1.0 billion revolving credit facility, and a
$1.0 billion synthetic letter of credit facility; and
(v) cash on hand.
The acquisition of Texas Genco LLC was accounted for using the
purchase method of accounting and, accordingly, the purchase
price was allocated to the assets acquired and liabilities
assumed based on the estimated fair value of such assets and
liabilities as of February 2, 2006. The excess of the
purchase price over the fair value of the net tangible and
identified intangible assets acquired was recorded as goodwill.
The allocation of the purchase price may be adjusted if
additional information for certain income tax items becomes
available through December 31, 2008 pursuant to
SFAS 141(R).
146
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the fair value of the assets
acquired and liabilities assumed at the date of the acquisition:
|
|
|
|
|
|
|
February 2,
|
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current and non-current assets
|
|
$
|
832
|
|
Coal inventory
|
|
|
33
|
|
In-market contracts:
|
|
|
|
|
Power contracts
|
|
|
39
|
|
Water contracts
|
|
|
64
|
|
Fuel contracts
|
|
|
171
|
|
Emission allowances
|
|
|
880
|
|
Property, plant and equipment
|
|
|
9,336
|
|
Deferred tax asset
|
|
|
2,868
|
|
Goodwill
|
|
|
1,782
|
|
|
|
|
|
|
Total assets acquired
|
|
|
16,005
|
|
|
|
|
|
|
|
LIABILITIES
|
Current and non-current liabilities
|
|
|
935
|
|
Pension and post-retirement liability
|
|
|
222
|
|
Out-of-market contracts:
|
|
|
|
|
Coal
|
|
|
93
|
|
Gas swaps
|
|
|
472
|
|
Power contracts
|
|
|
2,100
|
|
Deferred tax liability
|
|
|
3,217
|
|
Long term debt
|
|
|
2,735
|
|
|
|
|
|
|
Total liabilities assumed
|
|
|
9,774
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
6,231
|
|
|
|
|
|
|
Acquisition
of Remaining 50% interest in WCP
On March 31, 2006, NRG completed a purchase and sale
agreement for projects co-owned with Dynegy, Inc. Under the
agreements, NRG acquired Dynegys 50% ownership interest in
WCP (Generation) Holdings, Inc., or WCP, for $205 million
in cash and the assumption of a $1 million liability, with
NRG becoming the sole owner of WCPs 1,825 MW of
generation capacity in Southern California. In addition, NRG
sold to Dynegy the Companys 50% ownership interest in
Rocky Road Power LLC, or Rocky Road, a 330 MW gas-fueled,
simple cycle peaking plant located in Dundee, Illinois. NRG sold
Rocky Road for a fair value sale price of $45 million,
paying Dynegy a net purchase price of $160 million at
closing. Prior to the purchase, NRG had an existing investment
in WCP accounted for as an equity method investment, or Original
Investment.
The acquisition of the remaining 50% interest in WCP, or New
Investment, was accounted for as a step acquisition since the
Original Investment was transacted in a prior period. As a
result, the value of the Original Investment and the purchase
price of the New Investment were determined and allocated
separately. The value of the Original Investment was based on
the book value of approximately $159 million as of the date
of the acquisition of the New Investment.
147
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The value of the New Investment was allocated based on the
estimated fair value of assets acquired and liabilities assumed
as of March 31, 2006. The purchase price allocation
reflected an excess of fair value of the net assets acquired
over the purchase price of the New Investment, resulting in
negative goodwill of approximately $48 million. The
negative goodwill was subsequently allocated as a reduction to
the fair value of WCPs fixed assets. The following table
summarizes the purchase price and allocation impact of the WCP
acquisition as of March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Investment
|
|
|
|
|
|
|
|
|
|
Fair Value Before
|
|
|
|
|
|
Fair Value after
|
|
|
|
|
|
|
Original
|
|
|
Negative Goodwill
|
|
|
Allocation of
|
|
|
Negative Goodwill
|
|
|
Purchase Price
|
|
|
|
Investment
|
|
|
Allocation
|
|
|
Negative Goodwill
|
|
|
Allocation
|
|
|
Allocation
|
|
|
|
(In millions)
|
|
|
Current assets
|
|
$
|
149
|
|
|
$
|
153
|
|
|
$
|
|
|
|
$
|
153
|
|
|
$
|
302
|
|
Property, plant and equipment
|
|
|
24
|
|
|
|
103
|
|
|
|
(38
|
)
|
|
|
65
|
|
|
|
89
|
|
Intangible assets
|
|
|
2
|
|
|
|
26
|
|
|
|
(10
|
)
|
|
|
16
|
|
|
|
18
|
|
Other non-current assets
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
|
|
9
|
|
Current liabilities
|
|
|
(13
|
)
|
|
|
(18
|
)
|
|
|
|
|
|
|
(18
|
)
|
|
|
(31
|
)
|
Non-current liabilities
|
|
|
(3
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
(19
|
)
|
|
|
(22
|
)
|
Negative goodwill
|
|
|
|
|
|
|
(48
|
)
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Equity
|
|
$
|
159
|
|
|
$
|
206
|
|
|
$
|
|
|
|
$
|
206
|
|
|
$
|
365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unaudited
Supplemental Pro Forma Information
The following pro forma information represents the results of
operations as if NRG, Texas Genco LLC and WCP had combined at
the beginning of the respective reporting periods. The pro forma
information is not indicative of what the combined
companys result of operations would have been had the
companies been combined prior to the respective reporting
periods or of future results of the combined operations.
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
5,884
|
|
|
$
|
5,891
|
|
Net income
|
|
|
399
|
|
|
|
296
|
|
Earnings per share Basic
|
|
|
1.30
|
|
|
|
0.87
|
|
Earnings per share Diluted
|
|
|
1.27
|
|
|
|
0.86
|
|
Weighted average number of shares outstanding Basic
|
|
|
267.8
|
|
|
|
281.6
|
|
Weighted average number of shares outstanding Diluted
|
|
|
288
|
|
|
|
304
|
|
The pro forma net income for the year ended December 31,
2006 reflects the following nonrecurring expenses incurred by
Texas Genco LLC before February 2, 2006:
|
|
|
|
|
|
|
(In millions)
|
|
|
Equity compensation costs incurred due to immediate vesting of
equity compensation awards under change of control provisions
|
|
$
|
271
|
|
Professional fees and other acquisition-related costs
|
|
|
61
|
|
|
|
|
|
|
Total
|
|
$
|
332
|
|
|
|
|
|
|
148
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Other
Business Events
Red Bluff and Chowchilla On January 3,
2007, NRG completed the sale of the Companys Red Bluff and
Chowchilla II power plants to an entity controlled by
Wayzata Investment Partners LLC. These power plants, located in
California, are fueled by natural gas, with generating capacity
of 45 MW and 49 MW, respectively.
Note 4
Financial Instruments
The estimated carrying values and fair values of NRGs
recorded financial instruments related to continuing operations
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying Amount
|
|
|
Fair Value
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,132
|
|
|
$
|
777
|
|
|
$
|
1,132
|
|
|
$
|
777
|
|
Restricted cash
|
|
|
29
|
|
|
|
41
|
|
|
|
29
|
|
|
|
41
|
|
Investment in available-for-sale securities (classified within
other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
32
|
|
|
|
|
|
|
|
32
|
|
|
|
|
|
Marketable equity securities
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
Trust fund investments
|
|
|
390
|
|
|
|
377
|
|
|
|
390
|
|
|
|
377
|
|
Notes receivable
|
|
|
126
|
|
|
|
114
|
|
|
|
138
|
|
|
|
126
|
|
Long-term debt, including current portion
|
|
|
8,180
|
|
|
|
8,525
|
|
|
|
8,164
|
|
|
|
8,628
|
|
For cash and cash equivalents and restricted cash, the carrying
amount approximates fair value because of the short-term
maturity of those instruments. The fair value of marketable
securities is based on quoted market prices for those
instruments. Trust fund investments are comprised of various
U.S. debt and equity securities carried at fair market
value.
The fair value of notes receivable, debt securities and certain
long-term debt are based on expected future cash flows
discounted at market interest rates. The fair value of
NRGs traded long-term debt is estimated based on quoted
market prices for those instruments that are traded or on a
present value method using current interest rates for similar
instruments with equivalent credit quality.
Note 5
Accounting for Derivative Instruments and Hedging
Activities
SFAS 133, requires NRG to recognize all derivative
instruments on the balance sheet as either assets or liabilities
and to measure them at fair value each reporting period unless
they qualify for a NPNS exception. If certain conditions are
met, NRG may be able to designate certain derivatives as cash
flow hedges and defer the effective portion of the change in
fair value of the derivatives to OCI and subsequently recognized
in earnings when the hedged transaction occurs. The ineffective
portion of a cash flow hedge is immediately recognized in
earnings.
For derivatives designated as hedges of the fair value of assets
or liabilities, the changes in fair value of both the derivative
and the hedged transaction are recorded in current earnings. The
ineffective portion of a hedging derivative instruments
change in fair value is immediately recognized into earnings.
For derivatives that are not designated as cash flow hedges or
do not qualify for hedge accounting treatment, the changes in
the fair value will be immediately recognized in earnings. Under
the guidelines established per SFAS 133, certain derivative
instruments may qualify for the NPNS exception and are therefore
exempt from fair
149
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
value accounting treatment. SFAS 133 applies to NRGs
energy related commodity contracts, interest rate swaps, and
foreign exchange contracts.
As the Company engages principally in the trading and marketing
of its generation assets, most of NRGs commercial
activities qualify for hedge accounting under the requirements
of SFAS 133. In order to so qualify, the physical
generation and sale of electricity should be highly probable at
inception of the trade and throughout the period it is held, as
is the case with the Companys baseload plants. For this
reason, the majority of trades in support of NRGs baseload
units normally qualify for NPNS or cash flow hedge accounting
treatment, and trades in support of NRGs peaking units
will generally not qualify for hedge accounting treatment, with
any changes in fair value likely to be reflected on a
mark-to-market basis in the statement of operations. All of
NRGs hedging and trading activities are in accordance with
the Companys risk management policy.
Derivative
Financial Instruments
Energy-Related
Commodities
To manage the commodity price risk associated with the
Companys competitive supply activities and the price risk
associated with power sales from the Companys electric
generation facilities, NRG may enter into a variety of
derivative and non-derivative hedging instruments, utilizing the
following:
|
|
|
|
|
Forward contracts, which commit NRG to sell energy commodities
or purchase fuels in the future.
|
|
|
|
Futures contracts, which are exchange-traded standardized
commitments to purchase or sell a commodity or financial
instrument.
|
|
|
|
Swap agreements, which require payments to or from
counter-parties based upon the differential between two prices
for a predetermined contractual, or notional, quantity.
|
|
|
|
Option contracts, which convey the right or obligation to buy or
sell a commodity.
|
The objectives for entering into derivative contracts designated
as hedges include:
|
|
|
|
|
Fixing the price for a portion of anticipated future electricity
sales through the use of various derivative instruments
including gas collars and swaps at a level that provides an
acceptable return on the Companys electric generation
operations.
|
|
|
|
Fixing the price of a portion of anticipated fuel purchases for
the operation of NRGs power plants.
|
|
|
|
Fixing the price of a portion of anticipated energy purchases to
supply NRGs load-serving customers.
|
As of December 31, 2007, NRG had hedge and non-hedge
energy-related derivative financial instruments, and other
energy-related contracts that did not qualify as derivative
financial instruments extending through December 2026. As of
December 31, 2007, NRGs derivative assets and
liabilities consisted primarily of the following:
|
|
|
|
|
Forward and financial contracts for the sale of electricity and
related products economically hedging NRGs generation
assets forecasted output through 2014.
|
|
|
|
Forward and financial contracts for the purchase of fuel
commodities relating to the forecasted usage of NRGs
generation assets into 2017.
|
Also, as of December 31, 2007, NRG had other energy-related
contracts that qualified for the NPNS exception and were
therefore exempt from fair value accounting treatment under the
guidelines established by SFAS 133 as follows:
|
|
|
|
|
Power sales and capacity contracts extending to 2025.
|
|
|
|
Coal purchase contracts extending through 2012 designated as
normal purchases and disclosed as part of NRGs contractual
cash obligations. See Note 21, Commitments and
Contingencies, for further discussion.
|
150
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Also, as of December 31, 2007, NRG had other energy-related
contracts that did not qualify as derivatives under the
guidelines established by SFAS 133 as follows:
|
|
|
|
|
Load-following forward electric sale contracts extending through
2026.
|
|
|
|
Power Tolling contracts through 2017.
|
|
|
|
Lignite purchase contract through 2018.
|
|
|
|
Power transmission contracts through 2009.
|
|
|
|
Natural gas transportation contracts and storage agreements
through 2018.
|
|
|
|
Coal transportation contracts through 2015.
|
Interest
Rate Swaps
NRG is exposed to changes in interest rates through the
Companys issuance of variable and fixed rate debt. In
order to manage the Companys interest rate risk, NRG
enters into interest-rate swap agreements. In January 2006, in
anticipation of the New Senior Credit Facility, NRG entered into
a series of forward starting interest rate swaps intended to
hedge the variability in cash flows associated with the debt
issuance. These transactions were designated as cash flow hedges
with any gains/losses deferred on the balance sheet in OCI. In
February 2006, with the completion of the sale of the Senior
Notes, the Company designated a fixed-to-floating interest rate
swap as a hedge of fair value changes in the Senior Notes. This
interest rate swap was previously designated as a hedge of
NRGs 8% Second Priority Notes, which were effectively
replaced by the Senior Notes.
As of December 31, 2007, all of NRGs interest rate
swap arrangements had been designated as either cash flow or
fair value hedges. As of December 31, 2007, NRG had
interest rate derivative instruments extending through June 2019.
Accumulated
Other Comprehensive Income
Gains and losses attributable to hedge derivatives are
reclassified from OCI to current period earnings due to the
unwinding of previously deferred amounts. These amounts are
recorded on the same line in the statement of operations in
which the hedged transactions are recorded. Changes in the fair
values of derivatives accounted for as hedges are also recorded
in OCI.
151
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the effects of SFAS 133, on
NRGs accumulated other comprehensive income balance
attributable to hedged derivatives for the years ended
December 31, 2007, 2006 and 2005, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-Related
|
|
|
|
|
|
|
|
|
|
Commodities
|
|
|
Interest Rate
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Accumulated OCI balance at December 31, 2004
|
|
$
|
5
|
|
|
$
|
2
|
|
|
$
|
7
|
|
Realized from OCI during period due to unwinding of
previously deferred amounts
|
|
|
132
|
|
|
|
(2
|
)
|
|
|
130
|
|
Changes in fair value of hedge contracts
gains/(losses)
|
|
|
(341
|
)
|
|
|
8
|
|
|
|
(333
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2005
|
|
$
|
(204
|
)
|
|
$
|
8
|
|
|
$
|
(196
|
)
|
Realized from OCI during period: due to unwinding of
previously deferred amounts
|
|
|
6
|
|
|
|
(2
|
)
|
|
|
4
|
|
Changes in fair value of hedge contracts gains
|
|
|
391
|
|
|
|
10
|
|
|
|
401
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2006
|
|
$
|
193
|
|
|
$
|
16
|
|
|
$
|
209
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized from OCI during period due to unwinding of
previously deferred amounts
|
|
|
(50
|
)
|
|
|
(2
|
)
|
|
|
(52
|
)
|
Changes in fair value of hedge contracts losses
|
|
|
(377
|
)
|
|
|
(45
|
)
|
|
|
(422
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2007
|
|
$
|
(234
|
)
|
|
$
|
(31
|
)
|
|
$
|
(265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains expected to unwind from OCI during next 12 months,
net of $26 tax
|
|
$
|
41
|
|
|
$
|
|
|
|
$
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2007, the net balance in OCI relating to
SFAS 133 was an unrecognized loss of approximately
$265 million, which is net of $175 million in income
taxes. NRG expects $41 million of net deferred gains on
derivative instruments accumulated in OCI to be recognized in
earnings during the next twelve months.
Statement
of Operations
In accordance with SFAS 133, unrealized gains and losses
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives and
ineffectiveness of hedge derivatives are reflected in current
period earnings.
The following table summarizes the pre-tax effects of non-hedge
derivatives, derivatives that do not qualify as hedges, and
ineffectiveness of hedge derivatives on NRGs statement of
operations for the years ended December 31, 2007, 2006 and
2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the
|
|
|
For the
|
|
|
For the
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Revenue from operations energy commodities
|
|
$
|
(77
|
)
|
|
$
|
295
|
|
|
$
|
(154
|
)
|
Cost of operations
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Equity in earnings of unconsolidated subsidiaries
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Interest expense interest rate swaps
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact to statement of operations
|
|
$
|
(77
|
)
|
|
$
|
292
|
|
|
$
|
(140
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2007, the unrealized loss
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives of
$77 million is comprised of $34 million of fair value
increases in forward sales of electricity and fuel,
$160 million loss from the reversal of mark-to-market
gains,
152
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
which ultimately settled as financial revenues, and
$49 million of gains associated with our trading activity.
The $34 million of fair value increases in forward sales of
electricity and fuel includes approximately $14 million due
to the ineffectiveness associated with financial forward
contracted electric and gas sales.
For the year ended December 31, 2006, the unrealized gain
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives of
$295 million is comprised of $172 million of fair
value increases in forward sales of electricity and fuel,
$90 million from the reversal of mark-to-market losses,
which ultimately settled as financial revenues, and
$33 million of gains associated with our trading activity.
The $172 million of fair value increases in forward sales
of electricity and fuel includes approximately $28 million
due to the ineffectiveness associated with financial forward
contracted electric and gas sales. NRGs pre-tax earnings
were also affected by a $3 million loss due to
ineffectiveness associated with our fixed-to-floating interest
rate swap designated as a hedge of fair value changes in the
Senior Notes.
For the year ended December 31, 2005, the unrealized loss
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives of
$154 million is comprised of $122 million of fair
value decreases in forward sales of electricity and fuel,
$59 million from the reversal of mark-to-market gains,
which ultimately settled as financial revenues, and
$27 million of gains associated with our trading activity.
The impact of hedge ineffectiveness associated with financial
forward contracted electric sales was immaterial.
Discontinued Hedge Accounting During 2006,
due to a relatively mild summer season and expected lower power
generation for the remainder of 2006, NRG discontinued cash flow
hedge accounting for certain contracts related to commodity
prices previously accounted for as a cash flow hedge and
determined forecasted sales were no longer probable. These
contracts were originally entered into as hedges of forecasted
sales by baseload plants. The decision not to deliver against
these contracts was driven by the decline in natural gas and
associated power prices, making it uneconomical to dispatch the
units into the marketplace. As a result, approximately
$5 million of previously deferred revenue in OCI was
recognized in earnings for the year ended December 31, 2006.
Impact of Hedge Reset NRG accounted for the
Companys Hedge Reset transaction as a net settlement of
its current hedge positions and a subsequent reestablishment of
new hedge positions. The impact of the net settlement reduced
revenues by approximately $129 million.
As of December 31, 2006, the impact to NRGs
consolidated financial position and statement of operations from
the Hedge Reset transaction was as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
Settlement payment
|
|
$
|
(1,347
|
)
|
Reduction in derivative liability
|
|
|
145
|
|
Reduction in out-of-market contracts
|
|
|
1,073
|
|
|
|
|
|
|
Net decrease in revenues
|
|
$
|
(129
|
)
|
|
|
|
|
|
Note 6
Nuclear Decommissioning Trust Fund
NRGs nuclear decommissioning trust fund assets which are
for the decommissioning of South Texas Project, or STP, are
primarily comprised of securities recorded at fair value based
on actively quoted market prices. NRG accounts for these trust
fund assets per SFAS 71, Accounting for the Effects of
Certain Types of Regulation, because the Companys
nuclear decommissioning activities are regulated by the Public
Utility Commission of Texas, or PUCT. Although the owners of STP
are responsible for the management of decommissioning STP, the
cost of decommissioning is the responsibility of the Texas
ratepayers. As such, NRG does not bear the cost for these
decommissioning responsibilities, except to the extent that NRG
has a prudence obligation with respect to the management of the
trust funds or the future decommissioning of STP. Third party
appraisals are periodically conducted to estimate the future
decommissioning liability related to STP. These appraisals are
then used to determine the adequacy of the existing
decommissioning trust investments to cover that estimated future
liability.
153
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Should there be a shortfall in the value of the assets in the
trust relative to the estimated liability, NRG has the ability
to file a rate case with the PUCT to increase decommissioning
reimbursements over time from retail customers. As of
December 31, 2007, NRG believes the trust funds are
adequately funded.
The following table summarizes the fair values of the securities
held in the trust funds as of December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
4
|
|
|
$
|
7
|
|
U.S. government and federal agency obligations
|
|
|
21
|
|
|
|
29
|
|
Federal agency mortgage-backed securities
|
|
|
59
|
|
|
|
41
|
|
Commercial mortgage-backed securities
|
|
|
22
|
|
|
|
16
|
|
Corporate debt securities
|
|
|
44
|
|
|
|
43
|
|
Marketable equity securities
|
|
|
234
|
|
|
|
216
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
384
|
|
|
$
|
352
|
|
|
|
|
|
|
|
|
|
|
Note 7
Inventory
Inventory, which is stated at the lower of weighted average cost
or market, consists of:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Fuel oil
|
|
$
|
140
|
|
|
$
|
162
|
|
Coal/Lignite
|
|
|
174
|
|
|
|
118
|
|
Natural gas
|
|
|
16
|
|
|
|
12
|
|
Spare parts
|
|
|
121
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
Total Inventory
|
|
$
|
451
|
|
|
$
|
420
|
|
|
|
|
|
|
|
|
|
|
154
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 8
Capital Lease and Notes Receivable
Notes receivable primarily consists of fixed and variable rate
notes secured by equity interests in partnerships and joint
ventures. NRGs notes receivable and capital lease as of
December 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Capital Lease Receivable non-affiliate
|
|
|
|
|
|
|
|
|
VEAG Vereinigte Energiewerke AG, due August 31, 2021,
11.00%(a)
|
|
$
|
395
|
|
|
$
|
392
|
|
|
|
|
|
|
|
|
|
|
Capital Lease non-affiliates
|
|
|
395
|
|
|
|
392
|
|
Less current maturities
|
|
|
30
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
365
|
|
|
|
365
|
|
|
|
|
|
|
|
|
|
|
Note Receivable affiliates
|
|
|
|
|
|
|
|
|
Kraftwerke Schkopau GBR, indefinite maturity date,
5.89%-7.00%(b)
|
|
|
126
|
|
|
|
114
|
|
|
|
|
|
|
|
|
|
|
Notes receivable affiliates
|
|
$
|
126
|
|
|
$
|
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Saale Energie GmbH, or SEG, has
sold 100% of its share of capacity from the Schkopau power plant
to VEAG Vereinigte Energiewerke AG under a
25-year
contract, which is more than 83% of the useful life of the
plant. This direct financing lease receivable amount was
calculated based on the present value of the income to be
received over the life of the contract.
|
|
(b)
|
|
SEG entered into a note receivable
with Kraftwerke Schkopau GBR, a partnership between Saale and
E.On Kraftwerke GmbH. The note was used to fund SEGs
initial capital contribution to the partnership and to cover
project liquidity shortfalls during construction of the Schkopau
power plant. The note is subject to repayment upon the
disposition of the Schkopau plant.
|
Note 9
Property, Plant, and Equipment
NRGs major classes of property, plant, and equipment as of
December 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
Depreciable
|
|
|
|
2007
|
|
|
2006
|
|
|
Lives
|
|
|
|
(In millions)
|
|
|
Facilities and equipment
|
|
$
|
11,829
|
|
|
$
|
11,636
|
|
|
|
5-40 Years
|
|
Land and improvements
|
|
|
584
|
|
|
|
559
|
|
|
|
|
|
Nuclear fuel
|
|
|
181
|
|
|
|
159
|
|
|
|
5 Years
|
|
Office furnishings and equipment
|
|
|
84
|
|
|
|
79
|
|
|
|
3-10 Years
|
|
Construction in progress
|
|
|
337
|
|
|
|
87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
13,015
|
|
|
|
12,520
|
|
|
|
|
|
Accumulated depreciation
|
|
|
(1,695
|
)
|
|
|
(974
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
11,320
|
|
|
$
|
11,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 10
Goodwill and Other Intangibles
Goodwill In connection with the
acquisitions of Texas Genco LLC and Padoma Wind Power, LLC, NRG
has recorded goodwill in the amount of approximately
$1.8 billion. Goodwill is not amortized but instead tested
for impairment in accordance with SFAS 142 at the
reporting-unit
level. Goodwill is tested annually, typically during
155
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the fourth quarter, or more often if events or circumstances,
such as adverse changes in the business climate, indicate there
may be an impairment. As of December 31, 2007, there was no
impairment to goodwill. As of December 31, 2007, NRG had
approximately $851 million of goodwill that is deductible
for U.S. income tax purposes in future periods.
Intangible Assets NRG acquired
intangible assets as part of the Companys acquisition of
Texas Genco LLC and established intangible assets upon adoption
of Fresh Start reporting. These intangible assets include
SO2
and
NOx
emission allowances and certain in-market power, fuel (coal,
gas, and nuclear) and water contracts. The emission allowances
are amortized and recorded as part of the cost of operations,
with
NOx
emission allowances amortized on a straight line basis and
SO2
emission allowances amortized based on units of production. The
power contracts are amortized based on contracted volumes over
the life of each contract and the fuel contracts are amortized
over expected volumes over the life of each contract. The power
contracts are amortized and recorded as part of revenues, while
fuel and water contracts are amortized and recorded as part of
the cost of operations.
NRG actively trades portions of the Companys emission
allowances as part of the Companys asset optimization
strategy, with their respective costs expensed when sold.
Emission allowances that the Company designates for such trading
are reclassified to intangible assets held-for-sale on the
balance sheet and are not amortized.
The following tables summarize the components of NRGs
intangible assets subject to amortization for the years ended
December 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Contracts
|
|
|
|
|
|
|
|
As of December 31,
2007
|
|
Allowances
|
|
|
Power
|
|
|
Fuel
|
|
|
Water
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2007
|
|
$
|
913
|
|
|
$
|
92
|
|
|
$
|
171
|
|
|
$
|
64
|
|
|
$
|
|
|
|
$
|
1,240
|
|
Acquisitions
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
7
|
|
Sales
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
Transfer to held for sale
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross amount
|
|
|
916
|
|
|
|
92
|
|
|
|
171
|
|
|
|
64
|
|
|
|
2
|
|
|
|
1,245
|
|
Less accumulated amortization
|
|
|
(114
|
)
|
|
|
(92
|
)
|
|
|
(102
|
)
|
|
|
(64
|
)
|
|
|
|
|
|
|
(372
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
802
|
|
|
$
|
|
|
|
$
|
69
|
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
873
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Contracts
|
|
|
|
|
As of December 31,
2006
|
|
Allowances
|
|
|
Power
|
|
|
Fuel
|
|
|
Water
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2006
|
|
$
|
280
|
|
|
$
|
56
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
336
|
|
Acquisitions
|
|
|
894
|
|
|
|
39
|
|
|
|
171
|
|
|
|
64
|
|
|
|
1,168
|
|
Transfer to held for sale
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23
|
)
|
Tax adjustments
|
|
|
(238
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
(241
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross amount
|
|
|
913
|
|
|
|
92
|
|
|
|
171
|
|
|
|
64
|
|
|
|
1,240
|
|
Less accumulated amortization
|
|
|
(74
|
)
|
|
|
(92
|
)
|
|
|
(65
|
)
|
|
|
(28
|
)
|
|
|
(259
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
839
|
|
|
$
|
|
|
|
$
|
106
|
|
|
$
|
36
|
|
|
$
|
981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In accordance with
SOP 90-7,
any future income tax benefits realized from reducing the
valuation allowance should first reduce intangible assets until
exhausted, and thereafter be recorded as a direct addition to
paid-in capital. For the year ended December 31, 2006, NRG
reduced its valuation allowance by approximately
156
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
$231 million and reduced a related deferred tax liability
by $10 million, offset against the Companys
intangible assets, in accordance with
SOP 90-7.
The following table presents NRGs amortization of
intangible assets for the years ended December 31, 2007,
2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Emission allowances
|
|
$
|
40
|
|
|
$
|
44
|
|
|
$
|
12
|
|
Fuel contracts
|
|
|
37
|
|
|
|
65
|
|
|
|
|
|
Water contracts
|
|
|
36
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amortization in cost of operations
|
|
$
|
113
|
|
|
$
|
137
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power contract amortization recorded as a reduction to operating
revenues
|
|
$
|
|
|
|
$
|
43
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents estimated amortization related to
NRGs emission allowances and in-market contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
|
|
|
|
|
Year Ended December
31,
|
|
Allowances
|
|
|
Fuel
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
41
|
|
|
$
|
21
|
|
|
$
|
62
|
|
2009
|
|
|
41
|
|
|
|
26
|
|
|
|
67
|
|
2010
|
|
|
55
|
|
|
|
6
|
|
|
|
61
|
|
2011
|
|
|
54
|
|
|
|
2
|
|
|
|
56
|
|
2012
|
|
|
45
|
|
|
|
2
|
|
|
|
47
|
|
The weighted average remaining amortization period is
3.3 years for fuel contracts. Emission allowances are
amortized based on a mix of a straight line and actual emissions
emitted from the respective plants.
Intangible assets held for sale NRG records
the Companys bank of emission allowances as part of the
Companys intangible assets. From time to time, management
may authorize the transfer from the Companys emission bank
to intangible assets held-for-sale as part of the Companys
asset optimization strategy. As of December 31, 2007, the
value of emission allowances held-for-sale is $14 million
and is managed within the Corporate segment. Once transferred to
held-for-sale, these emission allowances transferred are
prohibited from moving back to held-for-use.
Out-of-market contracts Due to Fresh Start
accounting, as well as the acquisition of Texas Genco LLC, NRG
acquired certain out-of-market contracts. These are primarily
power, gas swaps, and certain coal contracts and are classified
as non-current liabilities on NRGs consolidated balance
sheet. Both the gas swap and power contracts are amortized to
revenues, while the coal contracts are amortized to cost of
operations.
The following table summarizes the estimated amortization
related to NRGs out-of-market contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December
31,
|
|
Coal
|
|
|
Gas Swaps
|
|
|
Power Contracts
|
|
|
Total
|
|
|
2008
|
|
$
|
33
|
|
|
$
|
11
|
|
|
$
|
279
|
|
|
$
|
323
|
|
2009
|
|
|
19
|
|
|
|
34
|
|
|
|
82
|
|
|
|
135
|
|
2010
|
|
|
6
|
|
|
|
28
|
|
|
|
32
|
|
|
|
66
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
22
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
22
|
|
157
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 11 Debt
and Capital Leases
Long-term debt and capital leases consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
|
|
As of December 31,
|
|
2007
|
|
|
2006
|
|
|
Rate
|
|
|
|
(In millions except rates)
|
|
|
NRG Recourse Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior notes due 2017
|
|
$
|
1,100
|
|
|
$
|
1,100
|
|
|
|
7.375
|
|
Senior notes due 2016
|
|
|
2,400
|
|
|
|
2,400
|
|
|
|
7.375
|
|
Senior notes due
2014(a)
|
|
|
1,199
|
|
|
|
1,183
|
|
|
|
7.25
|
|
ML note payable
|
|
|
|
|
|
|
11
|
|
|
|
L+1.9
|
(e)
|
Term loan B due 2013
|
|
|
2,816
|
|
|
|
3,148
|
|
|
|
L+1.75/L+2.0
|
(e)
|
NRG Non-Recourse Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
CSF non-recourse obligations due 2008 and 2009
|
|
|
333
|
|
|
|
333
|
|
|
|
5.45-13.23
|
|
NRG Peaker Finance Co. LLC, due June
2019(b)
|
|
|
235
|
|
|
|
240
|
|
|
|
L+1.07
|
(e)
|
NRG Energy Center Minneapolis LLC, senior secured notes, due
2013 and
2017(c)
|
|
|
97
|
|
|
|
107
|
|
|
|
7.12-7.31
|
|
Camas Power Boiler LP, unsecured term loan, due June 2007
|
|
|
|
|
|
|
1
|
|
|
|
L+0.69
|
(e)
|
Camas Power Boiler LP, revenue bonds, due August 2007
|
|
|
|
|
|
|
2
|
|
|
|
3.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal long term debt
|
|
|
8,180
|
|
|
|
8,525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau capital lease, due 2021
|
|
|
181
|
|
|
|
199
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
8,361
|
|
|
|
8,726
|
|
|
|
|
|
Less current
maturities(d)
|
|
|
466
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,895
|
|
|
$
|
8,603
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes fair value adjustment as of December 31 2007 and 2006,
reflects $(1) million and $(17) million, respectively,
reduction for an interest rate swap. The swap was re-designated
from the retired 2nd priority note to this note as part of the
financing related to the Texas Genco LLC acquisition.
|
|
(b)
|
Includes discount of $(43) million and $(50) million
as of December 31, 2007 and 2006, respectively.
|
|
(c)
|
Includes premium of $3 million and $4 million as of
December 31, 2007 and 2006, respectively.
|
|
(d)
|
Includes premium of $7 million on the NRG Peaker Finance
debt and a discount of $1 million on NRG Energy Center
Minneapolis debt as of December 31, 2007 and 2006.
|
|
(e)
|
L+ equals LIBOR plus x%
|
NRG
Recourse Debt
Senior
Notes
NRG has three outstanding issuances of senior notes, or Senior
Notes, under an Indenture, dated February 2, 2006, or the
Indenture, between NRG and Law Debenture Trust Company of
New York, as trustee:
(i) 7.25% senior notes, issued February 2, 2006
and due February 1, 2014, or the 2014 Senior Notes;
(ii) 7.375% senior notes issued February 2, 2006
and due February 1, 2016, or the 2016 Senior Notes;
(iii) 7.375% Senior Notes issued November 21,
2006 and due January 15, 2017, or the 2017 Senior Notes.
158
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Supplemental indentures to the series of notes have been issued
to add newly formed or acquired subsidiaries as guarantors.
The Indentures and the form of notes provide, among other
things, that the Senior Notes will be senior unsecured
obligations of NRG. The Indentures also provide for customary
events of default, which include, among others: nonpayment of
principal or interest; breach of other agreements in the
Indentures; defaults in failure to pay certain other
indebtedness; the rendering of judgments to pay certain amounts
of money against NRG and its subsidiaries; the failure of
certain guarantees to be enforceable; and certain events of
bankruptcy or insolvency. Generally, if an event of default
occurs, the Trustee or the Holders of at least 25% in principal
amount of the then outstanding series of Senior Notes may
declare all of the Senior Notes of such series to be due and
payable immediately.
The terms of the Indentures, among other things, limit
NRGs ability and certain of its subsidiaries ability
to:
|
|
|
|
|
return capital to shareholders;
|
|
|
|
grant liens on assets to lenders; and
|
|
|
|
incur additional debt.
|
Interest is payable semi-annually on the Senior Notes until
their maturity dates.
At any time prior to February 1, 2009, NRG may redeem up to
35% of the aggregate principal amount of the 2014 Senior Notes
and the 2016 Senior Notes with the net proceeds of certain
equity offerings, at a redemption price of 107.25% of the
principal amount, in the case of the 2014 Senior Notes, and
107.375% of the principal amount, in the case of the 2016 Senior
Notes. In addition, NRG may redeem the 2014 Senior Notes and
2016 Senior Notes at the redemption prices expressed as a
percentage of the principal amount redeemed set forth below,
plus accrued and unpaid interest on the notes redeemed.
Prior to February 1, 2010, for the 2014 Senior Notes, or
the First Applicable 7.25% Redemption Date, NRG may redeem
all or a portion of the 2014 Senior Notes at a price equal to
100% of the principal amount plus a premium and accrued
interest. The premium is the greater of (i) 1% of the
principal amount of the note, or (ii) the excess of the
principal amount of the note over the following: the present
value of 103.625% of the note, plus interest payments due on the
note from the date of redemption through the First Applicable
7.25% Redemption Date, discounted at a treasury rate plus
0.50%.
The following table sets forth the premium upon redemption after
February 1, 2010, for the 2014 Senior Notes:
|
|
|
|
|
|
|
Premium as
|
|
Redemption Period
|
|
Defined Above
|
|
|
February 1, 2010 to February 1, 2011
|
|
|
103.625
|
%
|
February 1, 2011 to February 1, 2012
|
|
|
101.813
|
%
|
February 1, 2012 and thereafter
|
|
|
100.000
|
%
|
Prior to February 1, 2011, for the 2016 Senior Notes, or
the First Applicable 7.375% Redemption Date, NRG may redeem
all or a portion of the 7.375% Notes at a price equal to
100% of the principal amount plus a premium and accrued
interest. The premium is the greater of (i) 1% of the
principal amount of the note, or (ii) the excess of the
principal amount of the note over the following: the present
value of 103.688% of the note, plus interest
159
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
payments due on the note from the date of redemption through the
First Applicable 7.375% Redemption Date, discounted at a
Treasury rate plus 0.50%.
The following table sets forth the premium upon redemption after
February 1, 2011, for the 2016 Senior Notes:
|
|
|
|
|
|
|
Premium as
|
|
Redemption Period
|
|
Defined Above
|
|
|
February 1, 2011 to February 1, 2012
|
|
|
103.688
|
%
|
February 1, 2012 to February 1, 2013
|
|
|
102.458
|
%
|
February 1, 2013 to February 1, 2014
|
|
|
101.229
|
%
|
February 1, 2014 and thereafter
|
|
|
100.000
|
%
|
Prior to January 15, 2012, NRG may redeem up to 35% of the
2017 Senior Notes with net cash proceeds of certain equity
offerings at a price of 107.375%, provided at least 65% of the
aggregate principal amount of the notes issued remain
outstanding after the redemption. Prior to January 15,
2012, NRG may redeem all or a portion of the Senior Notes at a
price equal to 100% of the principal amount of the notes
redeemed, plus a premium and any accrued and unpaid interest. In
addition, on or after January 15, 2012, NRG may redeem some
or all of the notes at redemption prices expressed as
percentages of principal amount as set forth below, plus accrued
and unpaid interest on the notes redeemed to the first
applicable redemption date of February 1, 2012.
The following table sets forth the premium upon redemption after
February 1, 2012, for the 2017 Senior Notes:
|
|
|
|
|
|
|
Premium as
|
|
Redemption Period
|
|
Defined Above
|
|
|
February 1, 2012 to February 1, 2013
|
|
|
103.688
|
%
|
February 1, 2013 to February 1, 2014
|
|
|
102.458
|
%
|
February 1, 2014 to February 1, 2015
|
|
|
101.229
|
%
|
February 1, 2015 and thereafter
|
|
|
100.000
|
%
|
In November 2007, NRG made a repayment of $11 million on a
revolving note after Merrill Lynch put the note back to the
Company.
Senior
Credit Facility
2007 Activity On June 8, 2007, NRG
completed a $4.4 billion refinancing of the Companys
then existing senior credit facility which was comprised of a
senior first priority secured term loan, or the Term Loan
Facility, a $1.0 billion senior first priority secured
revolving credit facility, or the Revolving Credit Facility, and
a senior first priority secured synthetic letter of credit
facility, or the Letter of Credit Facility. The refinancing
resulted in a 0.25% reduction on the spread that the Company
pays on its Term B loan and Synthetic Letter of Credit Facility,
a $200 million reduction in the Synthetic Letter of Credit
Facility from $1.5 billion to $1.3 billion, and
various amendments to provide improved flexibility, efficiency
for returning capital to shareholders, asset repowering and
investment opportunities. The pricing on the Companys Term
B loan and Synthetic Letter of Credit Facility is also subject
to further reductions upon the achievement of certain financial
ratios. The refinancing resulted in a charge of approximately
$35 million to the Companys results of operations for
the year ended December 31, 2007, which was primarily
related to the write-off of previously deferred financing costs.
On August 6, 2007, NRG entered into an agreement with BNP
Paribas, or BNP, whereby BNP has agreed to be an issuing bank
under the revolver portion of the Companys Senior Credit
Facility. BNP has agreed to issue up to $350 million of
letters of credit under the revolver. This increased the amount
of unfunded letters of credit the Company can issue under its
Revolving Credit Facility to $650 million. As of
December 31, 2007, NRG was permitted to issue additional
letters of credit of up to $350 million under the Senior
Credit Facility through other financial institutions.
160
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
On December 31, 2007, the Company used cash on hand to
prepay, without penalty, $300 million of its Term B loan
under the Senior Credit Facility. With this prepayment, the
Company has met a financial ratio by the end of 2007 that would
result in a 0.25% reduction in the interest rate on both its
Term B loan and Synthetic Letter of Credit Facility. The
prepayment will be credited against the Companys mandatory
annual prepayment which is required in March 2008 under the
Senior Credit Facility.
Significant terms The Term Loan Facility
matures on February 1, 2013, and amortizes in 27
consecutive equal quarterly installments of 0.25% term loan
commitments, beginning June 30, 2006, with the balance
payable on the seventh anniversary thereof. The full amount of
the Revolving Credit Facility will mature on February 2,
2011. The Synthetic Letter of Credit Facility will mature on
February 1, 2013, and no amortization will be required in
respect thereof. As of December 31, 2007, NRG had issued
$743 million under the Companys Synthetic Letter of
Credit Facility and $3 million in letters of credit under
the Companys Revolving Credit Facility. NRG has the option
to prepay the Senior Credit Facility in whole or in part at any
time.
Beginning 2008, NRG must offer a portion of its excess cash
flow, an amount which approximates the Companys free cash
flow for the prior year, to its first lien lenders. The
percentage of the excess cash flow offered to these lenders is
dependent upon the Companys consolidated leverage ratio at
the end of the preceding year. Of the amount offered, the first
lien lenders must accept 50%, while the remaining 50% may either
be accepted or rejected at the lenders option. Based on
current credit market conditions the Company expects that its
lenders will accept in full the mandatory offer required in
March 2008, and, as such, the Company has reclassified
approximately $146 million of Term Loan B maturity
from a non-current to a current liability as of
December 31, 2007.
The Senior Credit Facility is guaranteed by substantially all of
NRGs existing and future direct and indirect subsidiaries,
with certain customary or
agreed-upon
exceptions for unrestricted foreign subsidiaries, project
subsidiaries, and certain other subsidiaries. The capital stock
of substantially all of NRGs subsidiaries, with certain
exceptions for unrestricted subsidiaries, foreign subsidiaries,
and project subsidiaries, has been pledged for the benefit of
the Senior Credit Facilitys lenders.
The Senior Credit Facility is also secured by first-priority
perfected security interests in substantially all of the
property and assets owned or acquired by NRG and its
subsidiaries, other than certain limited exceptions. These
exceptions include assets of certain unrestricted subsidiaries,
equity interests in certain of NRGs project affiliates
that have non-recourse debt financing, and voting equity
interests in excess of 66% of the total outstanding voting
equity interest of certain of NRGs foreign subsidiaries.
The Senior Credit Facility contains customary covenants, which,
among other things, require NRG to meet certain financial tests,
including minimum interest coverage ratio and a maximum leverage
ratio on a consolidated basis, and limit NRGs ability to:
|
|
|
|
|
incur indebtedness and liens and enter into sale and lease-back
transactions;
|
|
|
|
make investments, loans and advances; and
|
|
|
|
return capital to shareholders.
|
Interest Rate Swaps In connection with the
Senior Credit Facility, NRG entered into a series of
forward-setting interest rate swaps in 2006 which are intended
to hedge the risks associated with floating interest rates. For
each of the interest rate swaps, the Company pays its
counterparty the equivalent of a fixed interest payment on a
predetermined notional value, and NRG receives quarterly the
equivalent of a floating interest payment based on a
3-month
LIBOR calculated on the same notional value. All interest rate
swap payments by NRG and its counterparties are made quarterly,
and the LIBOR is determined in advance of each interest period.
While the notional value of each of the swaps does not vary over
time, the swaps are designed to mature sequentially.
161
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The notional amounts and maturities of each tranche of these
swaps as of December 31, 2007 are as follows:
|
|
|
|
|
Maturity
|
|
Notional Value
|
|
|
March 31, 2008
|
|
$
|
140 million
|
|
March 31, 2009
|
|
$
|
150 million
|
|
March 31, 2010
|
|
$
|
190 million
|
|
March 31, 2011
|
|
$
|
1.55 billion
|
|
Holdco
Credit Facility
During 2007, the Company initiated a capital allocation strategy
that contemplated NRG becoming a wholly-owned operating
subsidiary of a newly created holding company, NRG Holdings,
Inc. or Holdco, with the stockholders of NRG becoming
stockholders of Holdco. On June 8, 2007, NRG executed a
Holdco Credit Facility, a delayed-draw credit facility that
expired December 28, 2007 that provided for the funding of
$1 billion in term loan financing to Holdco which was
intended for Holdco to make a capital contribution to NRG in the
amount of $1 billion, to be used to prepay a portion of
NRGs existing Term B loan. As part of the commitment NRG
agreed to pay a fee equal to 0.5% of the facility for the first
180 days and 0.75% thereafter.
In November 2007, NRG exercised its right to provide its Senior
Note holders with a conditional change of control notice, and
related offer to purchase the Companys Senior Notes at
101% of par, prior to the actual formation of the Holdco
structure. Concurrently, NRG also sought consent from its Senior
Note holders to either waive the change of control or permit
additional restricted payments under the indentures. In December
2007, the conditional tender offers and concurrent consent
solicitations expired with no tendered Senior Notes accepted for
payment and without receipt of the requisite consents to amend
the indentures for the Senior Notes. Consequently, the Company
decided not to move forward and form the Holdco structure.
NRG
Non-Recourse Debt
Debt
Related to Capital Allocation Program
During the third quarter 2006, the Company formed two
wholly-owned unrestricted subsidiaries, NRG Common Stock
Finance I, LLC, or CSF I, and NRG Common Stock Finance
II, LLC, or CSF II, that are both consolidated by NRG. Their
purpose was to repurchase $500 million shares of NRGs
common stock in the public markets or in privately negotiated
transactions in connection with the Companys Capital
Allocation Program. These subsidiaries were funded with a
combination of cash from NRG and a mix of notes and preferred
interests issued to Credit Suisse. Both the notes and the
preferred interests are non-recourse debt to NRG or any of its
restricted subsidiaries, with the notes collateralized by the
NRG common stock repurchased by these two wholly-owned
unrestricted subsidiaries that are consolidated in the
Companys statement of financial position. In addition, the
assets of these two subsidiaries are not available to the
creditors of NRG or the Companys other subsidiaries.
These notes and preferred interests contain a feature considered
an embedded derivative, which requires NRG to pay to Credit
Suisse at maturity, either in cash or stock, the excess of
NRGs then current stock price over a Reference Price. This
Reference Price is the price of NRGs stock in excess of a
compound annual growth rate, or CAGR, of 20% beyond the
volume-weighted average share price of the stock at the time of
repurchase. Although this feature is considered a derivative, it
is exempt from derivative accounting under the guidance in
paragraph 11(a) of SFAS 133, and will only be
recognized upon settlement with a corresponding impact to
Additional Paid-In Capital if settled in stock.
Notes As of December 31, 2007, CSF I and
CSF II issued a total of $249 million in notes in
connection with Phase I of the Capital Allocation Program that
mature in two tranches: $137 million in October 2008, plus
accrued interest at an annual rate of 5.45%, and the balance of
$112 million in October 2009, plus accrued interest at an
annual rate of 6.11%.
162
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Preferred Interests As of December 31,
2007, total preferred interests issued and outstanding by CSF I
and CSF II were approximately $84 million to Credit Suisse.
These preferred interests are classified as a liability per
SFAS 150, because they embody a fixed unconditional
obligation that these two unrestricted subsidiaries must settle.
The preferred interests also mature in two tranches:
$53 million in October 2008, plus accrued interest at an
annual rate of 12.65%, and $31 million in October 2009,
plus accrued interest at an annual rate of 13.23%.
CSF I Extension On February 27, 2008,
the Company entered into an arrangement with Credit Suisse that
allows the Company, at the Companys option and subject to
customary closing conditions, to extend the $220 million
notes and preferred interest maturities of CSF I from October
2008 to June 2010. In addition, the previous settlement date for
any share price appreciation beyond a 20% compound annual growth
rate since the original date of purchase by CSF I, may be
extended 30 days to early December 2008. As part of this
extension arrangement, the Company intends to contribute to CSF
I additional collateral in the form of treasury shares to
maintain a blended interest rate of CSF I facility of
approximately 7.5%. The Company expects to implement this
extension arrangement by March 17, 2008.
Project
Financings
The following are descriptions of certain indebtedness of
NRGs project subsidiaries that remain outstanding as of
December 31, 2007. The indebtedness described below is
non-recourse to NRG, unless otherwise noted.
Peakers
In June 2002, NRG Peaker Financing LLC, or Peakers, an indirect
wholly-owned subsidiary, issued $325 million in floating
rate bonds due June 2019. Peakers subsequently swapped such
floating rate debt for fixed rate debt at an all-in cost of
6.67% per annum. Principal, interest, and swap payments are
guaranteed by XL Capital Assurance, through a financial guaranty
insurance policy. These notes are also secured by, among other
things, substantially all of the assets of and membership
interests in Bayou Cove Peaking Power LLC, Big Cajun I Peaking
Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG
Rockford II LLC, and NRG Rockford Equipment LLC. As of
December 31, 2007, approximately $279 million in
principal remained outstanding on these bonds. Upon emergence
from bankruptcy, NRG issued a $36 million letter of credit
to the Peakers Collateral Agent. The letter of credit may
be drawn if the project is unable to meet principal or interest
payments. There are no provisions requiring NRG to replenish the
letter of credit if it is drawn.
NRG
Thermal
NRG owns and operates its thermal business through a
wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG
Thermal. In August 1993, the predecessor entity to NRG
Thermals largest subsidiary, NRG Energy Center Minneapolis
LLC, or NRG Thermal Minneapolis, issued $84 million of
7.31% senior secured notes due June 2013, of which
approximately $36 million remained outstanding as of
December 31, 2007. In July 2002, NRG Thermal Minneapolis
issued an additional $55 million of 7.25% Series A
notes due August 2017, of which approximately $42 million
remained outstanding as of December 31, 2007, and
$20 million of 7.12% Series B notes due August 2017,
of which approximately $15 million remained outstanding as
of December 31, 2007. This indebtedness is secured by
substantially all of the assets of NRG Thermal Minneapolis. NRG
Thermal has guaranteed the indebtedness, and its guarantee is
secured by a pledge of the equity interests in all of NRG
Thermals subsidiaries.
163
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Debt
Related to Discontinued Operations
As discussed in Note 3, Discontinued Operations,
Business Acquisitions and Dispositions, on December 18,
2007, NRG entered into a sale and purchase agreement to sell its
interest in ITISA, and consequently all ITISA debt,
approximately $60 million at December 31, 2007, has
been classified as discontinued operations.
Capital
Leases
Saale
Energie GmbH
Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has
a 41.9% participation in the Schkopau Power Plant, or Schkopau,
through NRGs interest in the Kraftwerke Schkopau GbR, or
KSGbR, partnership. Under the terms of a Use and Benefit Fee
Agreement, SEG and the other partner to the project, E.ON
Kraftwerke GmbH, are required to fund debt service and certain
other costs resulting from the construction and financing of
Schkopau. The Use and Benefit Fee Agreement is treated as a
capital lease under U.S. GAAP. Calls for funds are made to
the partners based on their participation interest as cash is
needed. The KSGbR issued debt to fund Schkopau pursuant to
multiple facilities totaling approximately
785 million (approximately $1.1 billion). As of
December 31, 2007, approximately 239 million
(approximately $349 million) remained outstanding at
Schkopau. Interests on the individual loans accrue at fixed
rates averaging 5.47% per annum, with maturities occurring
between 2008 and 2015. The lenders to the project rely almost
exclusively on the creditworthiness of E.ON Kraftwerke GmbH. SEG
remains liable to the lenders as a partner in KSGbR, but there
is no recourse to NRG. As of December 31, 2007, the capital
lease obligation at SEG was approximately $181 million.
Consolidated
Annual Maturities and Future Minimum Lease
Payments
Annual payments based on the maturities of NRGs long-term
debt and capital leases for the years ending after
December 31, 2007 are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
472
|
|
2009
|
|
|
226
|
|
2010
|
|
|
75
|
|
2011
|
|
|
70
|
|
2012
|
|
|
71
|
|
Thereafter
|
|
|
7,488
|
|
|
|
|
|
|
Total
|
|
$
|
8,402
|
|
|
|
|
|
|
NRGs future minimum lease payments for capital leases
included above as of December 31, 2007 are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
93
|
|
2009
|
|
|
42
|
|
2010
|
|
|
24
|
|
2011
|
|
|
15
|
|
2012
|
|
|
13
|
|
Thereafter
|
|
|
203
|
|
|
|
|
|
|
Total minimum obligations
|
|
|
390
|
|
Interest
|
|
|
209
|
|
|
|
|
|
|
Present value of minimum obligations
|
|
|
181
|
|
Current portion
|
|
|
75
|
|
|
|
|
|
|
Long-term obligations
|
|
$
|
106
|
|
|
|
|
|
|
164
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 12 Benefit
Plans and Other Postretirement Benefits
In September 2006, the FASB issued SFAS 158. This statement
requires an employer that sponsors one or more single-employer
defined benefit plans to recognize the funded status of a
benefit plan in its statement of financial position with an
offset to other comprehensive income, and recognize as a
component of other comprehensive income, net of tax, the gains
or losses and prior service costs or credits that arise during
the period but are not recognized as components of net periodic
benefit cost. NRG adopted this statement as of the
Companys fiscal year ended December 31, 2006.
NRG sponsors and operates three defined benefit pension and
other postretirement plans. The NRG Plan for Bargained Employees
and the NRG Plan for Non-bargained Employees are maintained
solely for eligible legacy NRG participants. A third plan, the
Texas Genco Retirement Plan, is maintained for participation
solely by eligible Texas based employees. NRG expects to
contribute approximately $87 million to the Companys
three pension plans in 2008.
NRG Plans for Bargained and Non-bargained Employees
Substantially all employees hired prior to
December 5, 2003 were eligible to participate in NRGs
legacy defined benefit pension plans. The Company initiated a
noncontributory, defined benefit pension plan effective
January 1, 2004, with credit for service from
December 5, 2003. In addition, the Company provides
postretirement health and welfare benefits for certain groups of
employees. Generally, these are groups that were acquired prior
to 2004 and for whom prior benefits are being continued (at
least for a certain period of time or as required by union
contracts). Cost sharing provisions vary by acquisition group
and terms of any applicable collective bargaining agreements.
Texas Genco Retirement Plan The Texas
regions pension plan is a noncontributory defined benefit
pension plan that provides a final average pay benefit or cash
balance benefit, where the participant receives the more
favorable of the two formulas, based on all years of service. In
addition, employees who were hired prior to 1999 are also
eligible for grandfathered benefits under a final average pay
formula. In most cases, the benefits under the grandfathered
formula will be frozen on December 31, 2008. NRGs
Texas region employees are also covered under an unfunded
postretirement health and welfare plan. Each year, employees
receive a fixed credit of $750 to their account plus interest.
Certain grandfathered employees will receive additional credits
through 2008. At retirement, the employees may use their
accounts to purchase retiree medical and dental benefits from
NRG. NRGs costs are limited to the amounts earned in the
employees account; all other costs are paid by the
participant.
NRG
Defined Benefit Plans
The net annual periodic pension cost related to NRG domestic
pension and other postretirement benefit plans include the
following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Service cost benefits earned
|
|
$
|
15
|
|
|
$
|
17
|
|
|
$
|
11
|
|
Interest cost on benefit obligation
|
|
|
17
|
|
|
|
15
|
|
|
|
4
|
|
Expected return on plan assets
|
|
|
(11
|
)
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
21
|
|
|
$
|
25
|
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
165
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Service cost benefits earned
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
2
|
|
Interest cost on benefit obligation
|
|
|
5
|
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
7
|
|
|
$
|
7
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A comparison of the pension benefit obligation, other post
retirement benefit obligations, and related plan assets as of
December 31, 2007 and 2006 for NRGs plans on a
combined basis is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Benefit obligation at January 1
|
|
$
|
294
|
|
|
$
|
318
|
|
|
$
|
80
|
|
|
$
|
80
|
|
Service cost
|
|
|
15
|
|
|
|
17
|
|
|
|
2
|
|
|
|
3
|
|
Interest cost
|
|
|
17
|
|
|
|
15
|
|
|
|
5
|
|
|
|
4
|
|
Plan amendments
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial (gain)/loss
|
|
|
(13
|
)
|
|
|
(29
|
)
|
|
|
(2
|
)
|
|
|
(6
|
)
|
Benefit payments
|
|
|
(19
|
)
|
|
|
(27
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31
|
|
$
|
290
|
|
|
$
|
294
|
|
|
$
|
83
|
|
|
$
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
|
123
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
7
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
Employer contributions
|
|
|
58
|
|
|
|
51
|
|
|
|
1
|
|
|
|
1
|
|
Benefit payments
|
|
|
(20
|
)
|
|
|
(28
|
)
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
$
|
168
|
|
|
$
|
123
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at December 31 excess of obligation
over assets
|
|
$
|
(122
|
)
|
|
$
|
(171
|
)
|
|
$
|
(83
|
)
|
|
$
|
(80
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in NRGs balance sheets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Assets
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Current liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-current liabilities
|
|
|
122
|
|
|
|
171
|
|
|
|
83
|
|
|
|
80
|
|
166
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Amounts recognized in NRGs accumulated other comprehensive
income that have not yet been recognized as components of net
periodic benefit cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Unrecognized (gain)/loss
|
|
$
|
(36
|
)
|
|
$
|
(27
|
)
|
|
$
|
1
|
|
|
$
|
1
|
|
Prior service credit
|
|
$
|
(3
|
)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
Pension
|
|
|
Postretirement
|
|
|
|
Benefits
|
|
|
Benefits
|
|
As of December 31,
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net gain
|
|
$
|
(8
|
)
|
|
$
|
(2
|
)
|
Prior service credit
|
|
$
|
(4
|
)
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in other comprehensive income
|
|
$
|
(12
|
)
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
Total recognized in net periodic pension cost and other
comprehensive income
|
|
$
|
9
|
|
|
$
|
5
|
|
The Companys estimated net gain for NRGs domestic
pension plan that will be amortized from the accumulated other
comprehensive income to net periodic cost over the next fiscal
year is $1 million.
The following table presents the balances of significant
components of NRGs domestic pension plan:
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Projected benefit obligation
|
|
$
|
290
|
|
|
$
|
294
|
|
Accumulated benefit obligation
|
|
|
236
|
|
|
|
226
|
|
Fair value of plan assets
|
|
|
168
|
|
|
|
123
|
|
The following table presents the significant assumptions used to
calculate NRGs benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
Weighted-Average
Assumptions
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
Discount rate
|
|
|
6.56%
|
|
|
|
5.92%
|
|
|
|
6.56%
|
|
|
|
5.92%
|
|
Rate of compensation increase
|
|
|
4.00-4.50%
|
|
|
|
4.00-4.50%
|
|
|
|
|
|
|
|
|
|
Health care trend rate
|
|
|
|
|
|
|
|
|
|
|
9.5% grading to
5.5% in 2016
|
|
|
|
10.5% grading to
5.5% in 2012
|
|
167
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table presents the significant assumptions used to
calculate NRGs benefit expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
Weighted-Average
Assumptions
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Discount rate
|
|
|
5.92
|
%
|
|
|
5.50
|
%
|
|
|
5.75
|
%
|
|
|
5.92%
|
|
|
|
5.50%
|
|
|
|
5.75%
|
|
Expected return on plan assets
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate of compensation increase
|
|
|
4.00-4.50
|
%
|
|
|
4.00-4.50
|
%
|
|
|
4.00-4.50
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Health care trend rate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10.5% grading
|
|
|
|
11.5% grading
|
|
|
|
9% grading
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
to 5.5% in 2012
|
|
|
|
to 5.5% in 2012
|
|
|
|
to 5.5% in 2012
|
|
NRG uses December 31 of each respective year as the measurement
date for the Companys pension and other postretirement
benefit plans. The Company sets the discount rate assumptions on
an annual basis for each of NRGs retirement related
benefit plans at their respective measurement date. This rate is
determined by NRGs Investment Committee based on
information provided by the Companys actuary. The discount
rate assumptions reflect the current rate at which the
associated liabilities could be effectively settled at the end
of the year. The discount rate assumptions used to determine
future pension obligations as of December 31, 2007 and 2006
were based on the Hewitt Yield Curve, or HYC, which was designed
by Hewitt Associates to provide a means for plan sponsors to
value the liabilities of their postretirement benefit plans. The
HYC is a hypothetical yield curve represented by a series of
annualized individual discount rates. Each bond issue underlying
the HYC is required to have a rating of Aa or better by
Moodys Investor Service, Inc. or a rating of AA or better
by Standard & Poors. Prior to using the HYC
rates, the discount rate assumptions for pension expense in 2006
and 2005 were based on investment yields available on AA rated
long-term corporate bonds.
NRG employs a total return investment approach, whereby a mix of
equities and fixed income investments are used to maximize the
long-term return of plan assets for a prudent level of risk.
Risk tolerance is established through careful consideration of
plan liabilities, plan funded status, and corporate financial
condition. The target allocation of plan assets is 60% to 80%
invested in equity securities, with the remainder invested in
fixed income securities. The Investment Committee reviews the
asset mix periodically and as the plan assets increase in future
years, the Investment Committee may examine other asset classes
such as real estate or private equity. NRG employs a building
block approach to determining the long-term rate of return for
plan assets, with proper consideration given to diversification
and rebalancing. Historical markets are studied and long-term
historical relationships between equities and fixed income are
preserved, consistent with the widely accepted capital market
principle that assets with higher volatility generate a greater
return over the long run. Current factors such as inflation and
interest rates are evaluated before long-term capital market
assumptions are determined. Peer data and historical returns are
reviewed to check for reasonability and appropriateness.
Plan assets are currently invested in a diversified blend of
equity and fixed-income investments. Furthermore, equity
investments are diversified across U.S. and
non-U.S. equities,
as well as among growth, value, small and large capitalization
stocks.
NRGs pension plan assets weighted average allocation as of
December 31, 2007 and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
US Equity
|
|
|
50-55
|
%
|
|
|
55
|
%
|
International Equity
|
|
|
15
|
%
|
|
|
17
|
%
|
US Fixed Income
|
|
|
30-35
|
%
|
|
|
28
|
%
|
168
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
NRGs expected future benefit payments for each of the next
five years, and in the aggregate for the five years thereafter,
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefit
|
|
|
|
Pension
|
|
|
|
|
|
Medicare Prescription
|
|
|
|
Benefit Payments
|
|
|
Benefit Payments
|
|
|
Drug Reimbursements
|
|
|
|
(In millions)
|
|
|
2008
|
|
$
|
13
|
|
|
$
|
2
|
|
|
$
|
|
|
2009
|
|
|
14
|
|
|
|
2
|
|
|
|
|
|
2010
|
|
|
16
|
|
|
|
3
|
|
|
|
|
|
2011
|
|
|
17
|
|
|
|
3
|
|
|
|
|
|
2012
|
|
|
19
|
|
|
|
4
|
|
|
|
|
|
2013-2017
|
|
$
|
126
|
|
|
$
|
25
|
|
|
$
|
1
|
|
Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care cost trend
rates would have the following effect:
|
|
|
|
|
|
|
|
|
|
|
1-Percentage-
|
|
|
1-Percentage-
|
|
|
|
Point Increase
|
|
|
Point Decrease
|
|
|
|
(In millions)
|
|
|
Effect on total service and interest cost components
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
Effect on postretirement benefit obligation
|
|
|
7
|
|
|
|
(5
|
)
|
STP
Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed
further in Note 26, Jointly Owned Plants. STPNOC,
who operates and maintains STP, provides its employees a defined
benefit pension plan as well as postretirement health and
welfare benefits. Although NRG does not sponsor the STP plan, it
reimburses STPNOC for 44% of the contributions made towards its
retirement plan obligations. For the period ending
December 31, 2007 and 2006, NRG reimbursed STPNOC
approximately $12 million and $4 million,
respectively, towards its defined benefit plans. In 2008, NRG
expects to reimburse STPNOC approximately $6 million for
its contributions towards the plans.
The Company has recognized the following in its statement of
financial position and accumulated other comprehensive income
related to its 44% interest in STP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Funded status STPNOC benefit plans
|
|
$
|
(20
|
)
|
|
$
|
(27
|
)
|
|
$
|
(22
|
)
|
|
$
|
(16
|
)
|
Net periodic pension costs
|
|
|
4
|
|
|
|
5
|
|
|
|
3
|
|
|
|
3
|
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income
|
|
$
|
4
|
|
|
$
|
1
|
|
|
$
|
4
|
|
|
$
|
|
|
Defined
Contribution Plans
NRGs employees have also been eligible to participate in
defined contribution 401(K) plans. The Companys
contributions to these plans were approximately
$16 million, $15 million, and $5 million for the
years ended December 31, 2007, 2006 and 2005, respectively.
169
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 13 Capital
Structure
Stock
Split
On April 25, 2007, NRGs Board of Directors approved a
two-for-one stock split of the Companys outstanding shares
of common stock which was effected through a stock dividend. The
stock split entitled each stockholder of record at the close of
business on May 22, 2007 to receive one additional share
for every outstanding share of common stock held. The additional
shares resulting from the stock split were distributed by the
Companys transfer agent on May 31, 2007. In
connection with the stock split, the Company transferred
approximately $1.3 million from Additional Paid-in Capital
to Common Stock, representing the par value of additional shares
issued. All share amounts for all periods presented have been
adjusted to reflect the stock split.
The following table reflects the changes in NRGs common
stock issued and outstanding for the year ended
December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized
|
|
|
Issued
|
|
|
Treasury
|
|
|
Outstanding
|
|
|
Balance as of December 31, 2005
|
|
|
500,000,000
|
|
|
|
200,097,352
|
|
|
|
(38,693,576
|
)
|
|
|
161,403,776
|
|
Shares issued January 2006
|
|
|
|
|
|
|
41,710,114
|
|
|
|
|
|
|
|
41,710,114
|
|
Acquisition of Texas Genco LLC
|
|
|
|
|
|
|
32,119,008
|
|
|
|
38,693,576
|
|
|
|
70,812,584
|
|
Capital Allocation Program Phase I and II
during 2006
|
|
|
|
|
|
|
|
|
|
|
(29,601,162
|
)
|
|
|
(29,601,162
|
)
|
Shares issued from LTIP through December 31, 2006
|
|
|
|
|
|
|
321,790
|
|
|
|
|
|
|
|
321,790
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2006
|
|
|
500,000,000
|
|
|
|
274,248,264
|
|
|
|
(29,601,162
|
)
|
|
|
244,647,102
|
|
Capital Allocation Program Phase II during 2007
|
|
|
|
|
|
|
|
|
|
|
(7,006,700
|
)
|
|
|
(7,006,700
|
)
|
Additional Share Repurchases December 2007
|
|
|
|
|
|
|
|
|
|
|
(2,037,700
|
)
|
|
|
(2,037,700
|
)
|
Shares issued from LTIP through December 31, 2007
|
|
|
|
|
|
|
1,132,227
|
|
|
|
|
|
|
|
1,132,227
|
|
Retirement of shares through December 31, 2007
|
|
|
|
|
|
|
(14,094,962
|
)
|
|
|
14,094,962
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
|
500,000,000
|
|
|
|
261,285,529
|
|
|
|
(24,550,600
|
)
|
|
|
236,734,929
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock
NRGs authorized common stock consists of 500 million
shares of NRG stock. Common stock issued as of December 31,
2007 and 2006 was 261,285,529 and 274,248,264 shares,
respectively, at a par value of $0.01 per share. Common stock
issued and outstanding as of December 31, 2007 and 2006
were 236,734,929 and 244,647,102, respectively.
170
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes NRGs common stock reserved
for the maximum number of shares potentially issuable based on
the conversion and redemption features of outstanding equity
instruments and the long term incentive plan as of
December 31, 2007:
|
|
|
|
|
|
|
Common Stock
|
|
Equity Instrument
|
|
Reserve Balance
|
|
|
4% Convertible perpetual preferred
|
|
|
26,151,972
|
|
3.625% Redeemable perpetual preferred
|
|
|
16,000,000
|
|
5.75% Mandatory convertible preferred
|
|
|
20,520,000
|
|
Long term incentive plan
|
|
|
14,565,741
|
|
|
|
|
|
|
Total
|
|
|
77,237,713
|
|
|
|
|
|
|
Treasury
Stock
As of December 31, 2007 and 2006, NRG had repurchased
24,550,600 shares and 29,601,162 shares, respectively
at a cost of approximately $638 million and
$732 million, respectively, of the Companys common
stock.
In 2006, NRG initiated a Capital Allocation Program to be
executed in two phases. Phase I, completed in the fourth
quarter 2006, resulted in the repurchase of
21,175,400 shares of the Companys common stock for
approximately $500 million. Phase II, also a
$500 million share buyback program, began in the fourth
quarter 2006 with the repurchase of 8,425,762 shares of NRG
common stock for approximately $232 million. NRG completed
Phase II in the third quarter 2007. The Company has thus
repurchased 7,006,700 shares of NRG common stock for
approximately $268 million relating to Phase II of the
Capital Allocation Program for the year ended December 31,
2007.
In December 2007, the Company repurchased 2,037,700 shares
of NRG common stock for approximately $85 million. In
January 2008, the Company repurchased an additional
344,000 shares of NRG common stock for approximately
$15 million.
Retirement
of Treasury Stock
On May 22, 2007, NRG retired 14,094,962 shares of
treasury stock. These retired shares are now included in the
Companys pool of authorized but unissued shares. The
retired stock had a carrying value of approximately
$447 million. The Companys accounting policy upon the
formal retirement of treasury stock is to deduct its par value
from Common Stock and to reflect any excess of cost over par
value as a deduction from Additional Paid-in Capital.
Preferred
Stock
As of December 31, 2007, the Company had
10,000,000 shares of preferred stock authorized. As of
December 31, 2007, the Companys preferred stock
consisted of three series, the 5.75% Mandatory Convertible
Preferred Stock, or 5.75% Preferred Stock, the
4% Convertible Perpetual Preferred Stock, or 4% Preferred
Stock, and the 3.625% Convertible Perpetual Preferred
Stock, which is treated as Redeemable Preferred Stock, or 3.625%
Preferred Stock.
5.75%
Preferred Stock
On February 2, 2006, NRG completed the issuance of
2,000,000 shares of 5.75% Preferred Stock, for net proceeds
of $486 million, reflecting an offering price of $250 per
share and the deduction of offering expenses and discounts of
approximately $14 million. Dividends on the 5.75% Preferred
Stock are $14.375 per share per year, and are due and payable on
a quarterly basis beginning on March 15, 2006. The 5.75%
Preferred Stock will
171
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
automatically convert into common stock on March 16, 2009,
or the Conversion Date, at a rate that is dependent upon the
applicable market value of NRGs common stock.
Included in the agreement is a call option which allows that at
any time prior to March 16, 2009, should the price of
NRGs common stock exceed $45.375, for at least 20 trading
days within a period of 30 consecutive trading days, NRG may
elect to cause the conversion of all, but not less than all, of
its 5.75% Preferred Stock outstanding at the minimum conversion
rate of 8.2712 shares of the Companys common stock
for each share of the 5.75% Preferred Stock. However, NRG can
cause conversion only if it pays the holders in cash an amount
equal to any accrued, accumulated and unpaid dividends on the
outstanding 5.75% Preferred Stock declared and not declared plus
the present value of all remaining future dividends through
March 16, 2009.
Also included is an early conversion feature by the holders
which is contingent upon a cash acquisition of NRG on or prior
to March 16, 2009. This feature requires paying converting
holders an amount equal to the sum of any accumulated and unpaid
dividends, the present value of all remaining dividend payments
through and including March 16, 2009, and a specified
conversion rate determined by reference to the price per share
of the Companys common stock paid in such acquisition for
each share of the outstanding 5.75% Preferred Stock. However,
should such a transaction be consummated by a public acquirer,
in lieu of providing for conversion and paying the dividend
amount, the Company may adjust its conversion obligation such
that upon conversion of the outstanding 5.75% Preferred Stock,
NRG will deliver the acquirers common stock.
The following table illustrates the conversion rate per share of
the 5.75% Preferred Stock:
|
|
|
|
|
Applicable Market Value on
Conversion Date
|
|
Conversion Rate
|
|
|
equal to or greater than $30.23
|
|
|
8.2712
|
|
less than $30.23 but greater than $24.38
|
|
|
8.2712 to 10.2564
|
|
less than or equal to $24.38
|
|
|
10.2564
|
|
4%
Preferred Stock
As of December 31, 2007 and 2006, 420,000 shares of
the Companys 4% Preferred Stock were issued and
outstanding at a liquidation value, net of issuance costs, of
$406 million. Holders of the 4% Preferred Stock are
entitled to receive, when declared by NRGs Board of
Directors, cash dividends at the rate of 4% per annum, or $40.00
per share per year, payable quarterly in arrears commencing on
March 15, 2005. The 4% Preferred Stock is convertible, at
the option of the holder, at any time into shares of NRGs
common stock at an initial conversion price of $20.00 per share.
On or after December 20, 2009, NRG may redeem, subject to
certain limitations, some or all of the 4% 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.
Should NRG be subject to a fundamental change, as defined in the
Certificate of Designation of the 4% Preferred Stock, each
holder of shares of the 4% Preferred Stock has the right,
subject to certain limitations, to require NRG to purchase any
or all of the Companys shares of Preferred Stock at a
purchase price equal to 100% of the liquidation preference, plus
accumulated and unpaid dividends, including liquidated damages,
if any, to the date of purchase. Final determination of a
fundamental change must be approved by the Board of Directors.
Each holder of the 4% Preferred Stock has one vote for each
share of the 4% Preferred Stock held by the holder on all
matters voted upon by the holders of NRG common stock, as well
as voting rights specifically provided for in NRGs amended
and restated certificate of incorporation or as otherwise, from
time to time, required by law.
The 4% Preferred Stock is, with respect to dividend rights and
rights upon liquidation, winding up or dissolution: junior to
all of NRGs existing and future debt obligations; junior
to each other class or series of NRGs capital stock other
than (1) NRGs common stock and any other class or
series of the Companys capital stock that provides that
such class or series will rank junior to the 4% Preferred Stock,
and (2) any other class or series of
172
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
NRGs capital stock, the terms of which provide that such
class or series will rank on a parity with the 4% Preferred
Stock.
Redeemable
Preferred Stock
3.625%
Preferred Stock
On August 11, 2005, NRG issued 250,000 shares of
3.625% Preferred Stock, which is treated as Redeemable Preferred
Stock, to Credit Suisse in a private placement. As of
December 31, 2007, 250,000 shares of the 3.625%
Preferred Stock were issued and outstanding at a liquidation
value, net of issuance costs, of $247 million. The 3.625%
Preferred Stock amount is located after the Liabilities but
before the Stockholders Equity section on the Balance
Sheet, due to the fact that the preferred shares can be redeemed
in cash by the shareholder.
The 3.625% Preferred Stock has a liquidation preference of
$1,000 per share. Holders of the 3.625% Preferred Stock are
entitled to receive, out of legally available funds, cash
dividends at the rate of 3.625% per annum, or $36.25 per share
per year, payable in cash quarterly in arrears commencing on
December 15, 2005. Each share of the 3.625% Preferred Stock
is convertible during the
90-day
period beginning August 11, 2015 at the option of NRG or
the holder. Holders tendering the 3.625% Preferred Stock for
conversion shall be entitled to receive, for each share of
3.625% Preferred Stock converted, $1,000 in cash and a number of
shares of NRG common stock equal to the product of (a) the
greater of (i) the difference between the average closing
share price of NRG common stock on each of the 20 consecutive
scheduled trading days starting on the date 30 exchange business
days immediately prior to the conversion date, or the Market
Price, and $29.54 and (ii) zero, times (b) 50.77. The
number of NRG common stock to be delivered under the conversion
feature is limited to 16,000,000 shares. If upon
conversion, the Market Price is less than $19.69, then the
Holder will deliver to NRG cash or a number of shares of NRG
common stock equal in value to the product of (i) $19.69
minus the Market Price, times (ii) 50.77. NRG may elect to
make a cash payment in lieu of delivering shares of NRG common
stock in connection with such conversion, and NRG may elect to
receive cash in lieu of shares of common stock, if any, from the
Holder in connection with such conversion. If a fundamental
change occurs, the holders will have the right to require NRG to
repurchase all or a portion of the 3.625% Preferred Stock for a
period of time after the fundamental change at a purchase price
equal to 100% of the liquidation preference, plus accumulated
and unpaid dividends. The 3.625% Preferred Stock is senior to
all classes of common stock, on a parity with the Companys
4% Preferred Stock, and junior to all of the Companys
existing and future debt obligations and all of NRG
subsidiaries existing and future liabilities and capital
stock held by persons other than NRG or its subsidiaries.
Note 14 Investments
Accounted for by the Equity Method
NRG accounts for the companys significant investments
using the equity method of accounting. NRGs carrying value
of equity investments can be impacted by impairments, unrealized
gains and losses on derivatives and movements in foreign
currency exchange rates, as well as other adjustments.
The following table summarizes NRGs significant equity
method investments, which were in operation as of
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economic
|
|
Name
|
|
Geographic Area
|
|
|
Interest
|
|
|
MIBRAG
|
|
|
Germany
|
|
|
|
50.0
|
%
|
Saguaro Power Company, or Saguaro
|
|
|
USA
|
|
|
|
50.0
|
%
|
Gladstone Power Station, or Gladstone
|
|
|
Australia
|
|
|
|
37.5
|
%
|
173
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Summarized financial information for investments in
unconsolidated affiliates accounted for under the equity method
for the years ended December 31, 2007, 2006 and 2005 was as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Summarized Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
871
|
|
|
$
|
910
|
|
|
$
|
1,300
|
|
Costs and expenses
|
|
|
748
|
|
|
|
770
|
|
|
|
1,107
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
123
|
|
|
|
140
|
|
|
|
193
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summarized Balance Sheets
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
268
|
|
|
|
223
|
|
|
|
|
|
Non-current assets
|
|
|
1,808
|
|
|
|
1,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
|
2,076
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
|
88
|
|
|
|
53
|
|
|
|
|
|
Non-current liabilities
|
|
|
950
|
|
|
|
1,021
|
|
|
|
|
|
Equity
|
|
|
1,038
|
|
|
|
846
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and equity
|
|
|
2,076
|
|
|
|
1,920
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs share of equity and net income
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs share of equity
|
|
|
425
|
|
|
|
344
|
|
|
|
|
|
NRGs share of net income
|
|
$
|
54
|
|
|
$
|
60
|
|
|
$
|
104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG NRG owns a 50% interest in
MIBRAG. Located near Leipzig, Germany, MIBRAG owns
and manages a coal mining operation, three lignite fueled power
generation facilities and other related businesses.
Approximately 40% of the power generated by MIBRAG is used to
support its mining operations, with the remainder sold to a
German utility company. A portion of the coal from MIBRAGs
mining operation is used to fuel the power generation
facilities, but a majority of the mined coal is sold primarily
to two major customers, including Schkopau, an affiliate of NRG.
A significant portion of MIBRAGs sales are made pursuant
to long-term coal and energy supply contracts. For the years
ended December 31, 2007, 2006 and 2005, NRGs equity
earnings from MIBRAG were approximately $36 million,
$30 million and $26 million, respectively.
As discussed in Note 2, Summary of Significant
Accounting Policies, the Companys MIBRAG equity
investment was negatively affected by the adoption of
EITF 04-6.
Upon adoption of
EITF 04-6
on January 1, 2006, NRGs investment in MIBRAG was
reduced by approximately $93 million, with an offsetting
charge to retained earnings.
Saguaro Power Company NRG owns a 50%
interest in the Saguaro plant, a cogeneration plant with
dual-fuel capability, natural gas and oil. For the year ended
December 31, 2007, NRGs equity loss from Saguaro was
$3 million and a loss of approximately $1 million for
the year ended December 31, 2006. NRG had no equity
earnings in 2005 from Saguaro. However, at the end of 2005, NRG
determined that it had a permanent decline in value of its 50%
interest and recorded a write down of the Companys equity
investment in Saguaro by approximately $27 million.
Gladstone NRG owns a 37.5% interest in
Gladstone, an unincorporated joint venture, or UJV, which
operates a 1,613 megawatt coal-fueled power generation facility
in Queensland, Australia. The power generation facility is
managed by the joint venture participants and the facility is
operated by NRG. Operating expenses incurred in connection with
the operation of the facility are funded by each of the
participants in proportion to their ownership interests. Coal is
sourced from a mining operation owned and operated by certain
joint venture partners
174
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and other investors under a long-term supply agreement. NRG and
the joint venture participants receive a majority of their
respective share of revenues directly from customers and are
directly responsible and liable for project-related debt, all in
proportion to the ownership interests in the UJV. Power
generated by the facility is primarily sold to an adjacent
aluminum smelter, with excess power sold on the national market.
For the years ended December 31, 2007, 2006 and 2005,
NRGs equity earnings from Gladstone were approximately
$21 million, $25 million and $24 million,
respectively.
On June 8, 2006, NRG announced the sale of the
Companys 37.5% equity interest in the Gladstone power
station, or Gladstone, and its associated 100% owned NRG
Gladstone Operating Services to Transfield Services of
Australia. The sale is pending until NRG satisfies certain
conditions, particularly the securing of certain consents and
waivers from the other owners of the project, or agrees to
complete the sale on alternative terms.
Note 15 Write
Downs and Gains/(Losses) on Sales of Equity Method
Investments
Investments accounted for by the equity method are reviewed for
impairment in accordance with APB 18, which requires that a loss
in value of an investment that is other than a temporary decline
should be recognized. Gains or losses are recognized on
completion of the sale. Write downs and gains/(losses) on sales
of equity method investments recorded in other income/expense in
the Companys consolidated statements of operations include
the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Segment
|
|
|
|
(In millions)
|
|
|
Powersmith Cogeneration
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
|
|
|
|
Corporate
|
|
Latin American Funds
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
International
|
|
James River Power LLC
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
Corporate
|
|
Cadillac
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
Corporate
|
|
Saguaro
|
|
|
|
|
|
|
|
|
|
|
(27
|
)
|
|
|
West
|
|
Rocky Road
|
|
|
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
Corporate
|
|
Kendall
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
Corporate
|
|
Enfield
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
International
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total write downs and gains/(losses) on sales of equity
method investments
|
|
$
|
1
|
|
|
$
|
8
|
|
|
$
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Latin American Funds On June 30, 2006,
NRG, through its wholly-owned entities NRG Caymans-C and NRG
Caymans-P, completed the sale of the entities remaining
interests in various Latin American power funds to a subsidiary
of Australia Post. Total proceeds received were approximately
$23 million and a pre-tax gain of approximately
$3 million was recognized in the second quarter 2006.
James River On May 15, 2006, NRG
completed the sale of Capistrano Cogeneration Company, a
subsidiary of NRG which owned a 50% interest in James River, to
Cogentrix. The proceeds from the sale were approximately
$8 million. As a result of the sale, NRG recorded a pre-tax
loss of approximately $6 million.
Cadillac On January 1, 2006, NRG sold
49.5% of the Companys 50% interest in a 38MW biomass fuel
generation facility located in Cadillac, Michigan, along with
its right to receive Production Tax Credits, or PTCs, through
2009 to Lakes Renewable LLC. In consideration, NRG received
approximately $4 million in a note receivable and a
promissory note equal to the value of the Companys share
in future PTCs earned through 2009. The sale was contingent upon
the receipt of a favorable private letter ruling from the
Internal Revenue Service, or IRS, and accordingly, all
consideration was held in escrow. On April 13, 2006, NRG
sold its remaining 0.5% share
175
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
in Cadillac along with the Companys interest in the note
receivable and promissory note to Delta Power for approximately
$11 million, resulting in a pre-tax gain of approximately
$11 million.
Saguaro During the fourth quarter of 2005,
due to the expiration of the partnerships long-term gas
supply contract and higher market prices paid for natural gas,
NRG determined that a decline in the value of the Companys
50% investment in Saguaro was considered to be permanent and
recorded a write down of the Companys investment of
approximately $27 million.
Rocky Road In December 2005, NRG entered into
a purchase and sale agreement with Dynegy, Inc., whereby NRG
agreed to sell to Dynegy the Companys 50% ownership
interest in Rocky Road Power LLC for $45 million in cash.
As a result of the purchase and sale agreement with Dynegy, NRG
recorded an impairment charge of approximately $20 million
to write down the value of the Companys 50% interest in
Rocky Road to the investments fair value of
$45 million.
Kendall In December 2004, NRG sold its
interest in Kendall to LS Power Associates, L.P., or LS Power.
Under the terms of the December 2004 agreement, NRG retained the
right to acquire a 40% interest in the plant within a
10-year
period for a nominal amount, or the Call Option. Therefore, the
transaction was treated as a partial sale for accounting
purposes. On August 8, 2005, NRG executed an agreement with
LS Power to sell the Call Option for $5 million. A pre-tax
gain of $4 million was recognized in the third quarter of
2005.
Enfield On April 1, 2005, NRG completed
the sale of the Companys 25% interest in Enfield to
Infrastructure Alliance Limited. Net cash proceeds received from
the sale were approximately $65 million and a pre-tax gain
of approximately $12 million was recorded in 2005.
Note 16 Earnings
Per Share
Basic earnings per common share is computed by dividing net
income less accumulated preferred stock dividends by the
weighted average number of common shares outstanding. Shares
issued and treasury shares repurchased during the year are
weighted for the portion of the year that they were outstanding.
Diluted earnings per share is computed in a manner consistent
with that of basic earnings per share while giving effect to all
potentially dilutive common shares that were outstanding during
the period.
Dilutive effect for equity compensation The
outstanding non-qualified stock options, non-vested restricted
stock units, deferred stock units and performance units are not
considered outstanding for purposes of computing basic earnings
per share. However, these instruments are included in the
denominator for purposes of computing diluted earnings per share
under the treasury stock method.
Dilutive effect for other equity instruments
NRGs outstanding 4% Preferred Stock and 5.75% Preferred
Stock are not considered outstanding for purposes of computing
basic earnings per share. However, these instruments are
considered for inclusion in the denominator for purposes of
computing diluted earnings per share under the if-converted
method. The Companys 3.625% Preferred Stock and preferred
interests and notes issued by CSF I and CSF II include
conversion features that, if dilutive, are calculated using the
if-converted method as well.
176
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The reconciliation of NRGs basic earnings per common share
to diluted earnings per share for the years ended
December 31, 2007, 2006 and 2005 is shown in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Basic earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
569
|
|
|
$
|
543
|
|
|
$
|
68
|
|
Deduct preferred stock dividends
|
|
|
(55
|
)
|
|
|
(52
|
)
|
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income available to common stockholders from continuing
operations
|
|
|
514
|
|
|
|
491
|
|
|
|
48
|
|
Discontinued operations, net of tax
|
|
|
17
|
|
|
|
78
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
531
|
|
|
$
|
569
|
|
|
$
|
64
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
240.2
|
|
|
|
258.0
|
|
|
|
169.2
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
2.14
|
|
|
$
|
1.90
|
|
|
$
|
0.28
|
|
Discontinued operations, net of tax
|
|
|
0.07
|
|
|
|
0.31
|
|
|
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2.21
|
|
|
$
|
2.21
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income available to common stockholders from continuing
operations
|
|
|
514
|
|
|
|
491
|
|
|
|
48
|
|
Add preferred stock dividends for dilutive preferred stock
|
|
|
46
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted income from continuing operations
|
|
|
560
|
|
|
|
534
|
|
|
|
48
|
|
Discontinued operations, net of tax
|
|
|
17
|
|
|
|
78
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
577
|
|
|
$
|
612
|
|
|
$
|
64
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
240.2
|
|
|
|
258.0
|
|
|
|
169.2
|
|
Incremental shares attributable to the issuance of stock-based
compensation (treasury stock method)
|
|
|
3.8
|
|
|
|
2.8
|
|
|
|
1.4
|
|
Incremental shares attributable to embedded derivatives of
certain financial instruments (if-converted method)
|
|
|
6.0
|
|
|
|
|
|
|
|
|
|
Incremental shares attributable to the assumed conversion
features of outstanding preferred stock (if-converted method)
|
|
|
37.5
|
|
|
|
39.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total dilutive shares
|
|
|
287.5
|
|
|
|
300.6
|
|
|
|
170.6
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1.95
|
|
|
$
|
1.78
|
|
|
$
|
0.28
|
|
Discontinued operations, net of tax
|
|
|
0.06
|
|
|
|
0.26
|
|
|
|
0.10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
2.01
|
|
|
$
|
2.04
|
|
|
$
|
0.38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
177
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes NRGs outstanding equity
instruments that are anti-dilutive and were not included in the
computation of the Companys diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions of shares)
|
|
|
Equity compensation NQSOs and PUs
|
|
|
0.1
|
|
|
|
0.7
|
|
|
|
0.4
|
|
Convertible preferred stock
|
|
|
|
|
|
|
|
|
|
|
21.0
|
|
Embedded derivative of 3.625% redeemable perpetual preferred
stock
|
|
|
12.2
|
|
|
|
16.0
|
|
|
|
16.0
|
|
Embedded derivative of preferred interests and notes issued by
CSF I and CSF II
|
|
|
16.1
|
|
|
|
18.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
28.4
|
|
|
|
35.0
|
|
|
|
37.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 17 Segment
Reporting
NRGs segment structure reflects core areas of operation
which are primarily the geographic regions of the Companys
wholesale power generation, thermal and chilled water business,
and corporate activities. Within NRGs wholesale power
generation operations, there are distinct components with
separate operating results and management structures for the
following regions: Texas, Northeast, South Central, West and
International.
The following table summarizes customers from whom NRG derived
more than 10% of the Companys consolidated revenues for
the years ended December 31, 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Customer A Northeast region
|
|
|
|
%
|
|
|
10
|
%
|
|
|
40
|
%
|
Customer B Northeast region
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Customer C Texas region
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
27
|
%
|
|
|
10
|
%
|
|
|
57
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
3,287
|
|
|
$
|
1,605
|
|
|
$
|
658
|
|
|
$
|
127
|
|
|
$
|
140
|
|
|
$
|
159
|
|
|
$
|
30
|
|
|
$
|
(17
|
)
|
|
$
|
5,989
|
|
Operating expenses
|
|
|
1,849
|
|
|
|
1,045
|
|
|
|
533
|
|
|
|
85
|
|
|
|
112
|
|
|
|
125
|
|
|
|
47
|
|
|
|
(8
|
)
|
|
|
3,788
|
|
Depreciation and amortization
|
|
|
469
|
|
|
|
102
|
|
|
|
68
|
|
|
|
3
|
|
|
|
|
|
|
|
11
|
|
|
|
5
|
|
|
|
|
|
|
|
658
|
|
Gain/(loss) on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
969
|
|
|
|
458
|
|
|
|
57
|
|
|
|
39
|
|
|
|
28
|
|
|
|
41
|
|
|
|
(23
|
)
|
|
|
(9
|
)
|
|
|
1,560
|
|
Equity in earnings/(loss) of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
Write downs and gain on sales of equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Other income, net
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
1
|
|
|
|
58
|
|
|
|
(19
|
)
|
|
|
55
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
(35
|
)
|
Interest expense
|
|
|
(164
|
)
|
|
|
(57
|
)
|
|
|
(53
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
(6
|
)
|
|
|
(423
|
)
|
|
|
19
|
|
|
|
(689
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
812
|
|
|
|
401
|
|
|
|
4
|
|
|
|
36
|
|
|
|
88
|
|
|
|
36
|
|
|
|
(422
|
)
|
|
|
(9
|
)
|
|
|
946
|
|
Income tax expense/(benefit)
|
|
|
327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
62
|
|
|
|
|
|
|
|
377
|
|
Income/(loss) from continuing operations
|
|
|
485
|
|
|
|
401
|
|
|
|
4
|
|
|
|
36
|
|
|
|
100
|
|
|
|
36
|
|
|
|
(484
|
)
|
|
|
(9
|
)
|
|
|
569
|
|
Income on discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
485
|
|
|
$
|
401
|
|
|
$
|
4
|
|
|
$
|
36
|
|
|
$
|
117
|
|
|
$
|
36
|
|
|
$
|
(484
|
)
|
|
$
|
(9
|
)
|
|
$
|
586
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
27
|
|
|
|
397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425
|
|
Capital expenditures
|
|
|
190
|
|
|
|
106
|
|
|
|
30
|
|
|
|
80
|
|
|
|
|
|
|
|
6
|
|
|
|
69
|
|
|
|
|
|
|
|
481
|
|
Goodwill
|
|
|
1,781
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
1,786
|
|
Total assets
|
|
$
|
12,165
|
|
|
$
|
1,572
|
|
|
$
|
995
|
|
|
$
|
246
|
|
|
$
|
1,169
|
|
|
$
|
211
|
|
|
$
|
12,847
|
|
|
$
|
(9,931
|
)
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
179
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2006
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
3,088
|
|
|
$
|
1,543
|
|
|
$
|
570
|
|
|
$
|
146
|
|
|
$
|
135
|
|
|
$
|
152
|
|
|
$
|
12
|
|
|
$
|
(61
|
)
|
|
$
|
5,585
|
|
Operating expenses
|
|
|
1,794
|
|
|
|
993
|
|
|
|
397
|
|
|
|
135
|
|
|
|
110
|
|
|
|
121
|
|
|
|
30
|
|
|
|
(3
|
)
|
|
|
3,577
|
|
Depreciation and amortization
|
|
|
413
|
|
|
|
89
|
|
|
|
68
|
|
|
|
3
|
|
|
|
|
|
|
|
12
|
|
|
|
5
|
|
|
|
|
|
|
|
590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
881
|
|
|
|
461
|
|
|
|
105
|
|
|
|
8
|
|
|
|
25
|
|
|
|
19
|
|
|
|
(23
|
)
|
|
|
(58
|
)
|
|
|
1,418
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
57
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
60
|
|
Write downs and gain on sales of equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
8
|
|
Other income, net
|
|
|
9
|
|
|
|
6
|
|
|
|
|
|
|
|
1
|
|
|
|
7
|
|
|
|
1
|
|
|
|
152
|
|
|
|
(20
|
)
|
|
|
156
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(187
|
)
|
|
|
|
|
|
|
(187
|
)
|
Interest expense
|
|
|
(138
|
)
|
|
|
(63
|
)
|
|
|
(57
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(7
|
)
|
|
|
(344
|
)
|
|
|
20
|
|
|
|
(590
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
752
|
|
|
|
404
|
|
|
|
48
|
|
|
|
10
|
|
|
|
91
|
|
|
|
13
|
|
|
|
(395
|
)
|
|
|
(58
|
)
|
|
|
865
|
|
Income tax expense/(benefit)
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
23
|
|
|
|
|
|
|
|
278
|
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
729
|
|
|
|
404
|
|
|
|
48
|
|
|
|
12
|
|
|
|
68
|
|
|
|
13
|
|
|
|
(673
|
)
|
|
|
(58
|
)
|
|
|
543
|
|
Income on discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
729
|
|
|
$
|
404
|
|
|
$
|
48
|
|
|
$
|
12
|
|
|
$
|
129
|
|
|
$
|
13
|
|
|
$
|
(656
|
)
|
|
$
|
(58
|
)
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
29
|
|
|
|
312
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
344
|
|
Capital expenditures
|
|
|
125
|
|
|
|
49
|
|
|
|
11
|
|
|
|
7
|
|
|
|
5
|
|
|
|
12
|
|
|
|
12
|
|
|
|
|
|
|
|
221
|
|
Goodwill
|
|
|
1,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
1,789
|
|
Total assets
|
|
$
|
12,980
|
|
|
$
|
1,583
|
|
|
$
|
1,029
|
|
|
$
|
176
|
|
|
$
|
1,293
|
|
|
$
|
251
|
|
|
$
|
12,608
|
|
|
$
|
(10,484
|
)
|
|
$
|
19,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
180
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2005
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
1,554
|
|
|
$
|
560
|
|
|
$
|
4
|
|
|
$
|
135
|
|
|
$
|
150
|
|
|
$
|
6
|
|
|
$
|
(9
|
)
|
|
$
|
2,400
|
|
Operating expenses
|
|
|
1,262
|
|
|
|
485
|
|
|
|
9
|
|
|
|
107
|
|
|
|
118
|
|
|
|
35
|
|
|
|
(11
|
)
|
|
|
2,005
|
|
Depreciation and amortization
|
|
|
74
|
|
|
|
67
|
|
|
|
1
|
|
|
|
|
|
|
|
11
|
|
|
|
5
|
|
|
|
|
|
|
|
158
|
|
Corporate relocation charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
Restructuring and impairment charges
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
218
|
|
|
|
8
|
|
|
|
(6
|
)
|
|
|
28
|
|
|
|
21
|
|
|
|
(46
|
)
|
|
|
2
|
|
|
|
225
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
69
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
104
|
|
Write downs and gain/(loss) on sales of equity method investments
|
|
|
|
|
|
|
|
|
|
|
(27
|
)
|
|
|
12
|
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
(31
|
)
|
Other income, net
|
|
|
4
|
|
|
|
|
|
|
|
1
|
|
|
|
17
|
|
|
|
2
|
|
|
|
51
|
|
|
|
(21
|
)
|
|
|
54
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(65
|
)
|
|
|
|
|
|
|
(65
|
)
|
Interest expense
|
|
|
|
|
|
|
(27
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
(8
|
)
|
|
|
(162
|
)
|
|
|
21
|
|
|
|
(177
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
222
|
|
|
|
(19
|
)
|
|
|
(10
|
)
|
|
|
125
|
|
|
|
15
|
|
|
|
(225
|
)
|
|
|
2
|
|
|
|
110
|
|
Income tax expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
4
|
|
|
|
17
|
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
222
|
|
|
|
(19
|
)
|
|
|
(10
|
)
|
|
|
104
|
|
|
|
11
|
|
|
|
(242
|
)
|
|
|
2
|
|
|
|
68
|
|
Income on discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
4
|
|
|
|
10
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
222
|
|
|
$
|
(19
|
)
|
|
$
|
(10
|
)
|
|
$
|
106
|
|
|
$
|
15
|
|
|
$
|
(232
|
)
|
|
$
|
2
|
|
|
$
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
181
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 18 Income
Taxes
The income tax provision from continuing operations for the
years ended December 31, 2007, 2006 and 2005 consisted of
the following amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S
|
|
$
|
(7
|
)
|
|
$
|
(27
|
)
|
|
$
|
19
|
|
Foreign
|
|
|
20
|
|
|
|
19
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
(8
|
)
|
|
|
34
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S
|
|
|
394
|
|
|
|
326
|
|
|
|
2
|
|
Foreign
|
|
|
(30
|
)
|
|
|
4
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
364
|
|
|
|
330
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax
|
|
$
|
377
|
|
|
$
|
322
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
39.9
|
%
|
|
|
37.2
|
%
|
|
|
38.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following represents the domestic and foreign components of
income from continuing operations before income tax expense for
the years ended December 31, 2007, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
U.S.
|
|
$
|
860
|
|
|
$
|
767
|
|
|
$
|
(11
|
)
|
Foreign
|
|
|
86
|
|
|
|
98
|
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
946
|
|
|
$
|
865
|
|
|
$
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
182
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
A reconciliation of the U.S. federal statutory rate of 35%
to NRGs effective rate from continuing operations for the
years ended December 31, 2007, 2006 and 2005 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions, except percentages)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
946
|
|
|
$
|
865
|
|
|
$
|
110
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
331
|
|
|
|
303
|
|
|
|
39
|
|
State taxes, net of federal benefit
|
|
|
46
|
|
|
|
34
|
|
|
|
(1
|
)
|
Foreign operations
|
|
|
(13
|
)
|
|
|
(21
|
)
|
|
|
(18
|
)
|
2005 Section 965 taxable dividend
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Subpart F taxable income
|
|
|
|
|
|
|
11
|
|
|
|
19
|
|
Valuation allowance, including change in state effective rate
|
|
|
6
|
|
|
|
(10
|
)
|
|
|
22
|
|
Change in state effective tax rate
|
|
|
|
|
|
|
21
|
|
|
|
(22
|
)
|
Claimant reserve settlements
|
|
|
|
|
|
|
(28
|
)
|
|
|
|
|
Change in local German effective tax rates
|
|
|
(29
|
)
|
|
|
|
|
|
|
|
|
Foreign dividends
|
|
|
26
|
|
|
|
1
|
|
|
|
|
|
Non-deductible interest
|
|
|
10
|
|
|
|
3
|
|
|
|
|
|
Permanent differences, reserves, other
|
|
|
|
|
|
|
8
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
377
|
|
|
$
|
322
|
|
|
$
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
39.9
|
%
|
|
|
37.2
|
%
|
|
|
38.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The effective income tax rate for the year ended
December 31, 2007 differs from the U.S. statutory rate
of 35% primarily due to a taxable dividend from foreign
operations and non-deductible interest, offset by earnings in
foreign jurisdictions taxed at rates lower than the
U.S. statutory rate including the impact of a law change
that reduced the German tax rate.
For the year ended December 31, 2007, NRGs state
effective income tax rate has remained at 7%, which is
consistent with its 2006 rate. For the year ended
December 31, 2006, the Company decreased the estimated
state effective income tax rate to 7% from the prior year state
income tax rate of 9%. This decrease was due to the acquisition
of Texas Genco LLC, which operates in the state of Texas where
there was no state income tax as of December 31, 2006. A
decrease to the net deferred tax asset balance of approximately
$24 million, of which $21 million is derived from
continuing operations and $3 million is from discontinued
operations, has been recorded for this change during 2006. In
addition, a reduction of $22 million, of which
$19 million is generated from continuing operations and
$3 million is from discontinued operations, reflected in
our domestic valuation allowance, was recorded due to a change
in our estimated state effective income tax rate during 2006.
183
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The temporary differences, which gave rise to the Companys
deferred tax assets and liabilities as of December 31, 2007
and 2006, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Discount/premium on notes
|
|
$
|
23
|
|
|
$
|
25
|
|
Emissions allowances
|
|
|
109
|
|
|
|
83
|
|
Difference between book and tax basis of property
|
|
|
1,568
|
|
|
|
1,579
|
|
Derivative asset, net
|
|
|
|
|
|
|
216
|
|
Goodwill
|
|
|
45
|
|
|
|
51
|
|
Investment in projects
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
1,751
|
|
|
|
1,954
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Deferred compensation, pension, accrued vacation and other
reserves
|
|
|
129
|
|
|
|
133
|
|
Derivative liability, net
|
|
|
125
|
|
|
|
|
|
Differences between book and tax basis of contracts
|
|
|
577
|
|
|
|
890
|
|
Non-depreciable property
|
|
|
19
|
|
|
|
21
|
|
Intangibles amortization (excluding goodwill)
|
|
|
152
|
|
|
|
145
|
|
Equity compensation
|
|
|
15
|
|
|
|
16
|
|
Claimants reserve
|
|
|
7
|
|
|
|
8
|
|
U.S. net operating loss carry forwards
|
|
|
|
|
|
|
27
|
|
U.S. capital loss carryforwards
|
|
|
439
|
|
|
|
485
|
|
Foreign net operating loss carryforwards
|
|
|
80
|
|
|
|
74
|
|
Foreign capital loss carryforwards
|
|
|
1
|
|
|
|
|
|
Investments in projects
|
|
|
|
|
|
|
6
|
|
Deferred financing costs
|
|
|
12
|
|
|
|
|
|
Other
|
|
|
15
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
1,571
|
|
|
|
1,817
|
|
Valuation allowance
|
|
|
(539
|
)
|
|
|
(581
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
1,032
|
|
|
|
1,236
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
719
|
|
|
$
|
718
|
|
|
|
|
|
|
|
|
|
|
184
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes NRGs net deferred tax
position as of December 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Current deferred tax asset
|
|
$
|
124
|
|
|
$
|
|
|
Current deferred tax liability
|
|
|
|
|
|
|
164
|
|
Non-current deferred tax liability
|
|
|
843
|
|
|
|
554
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
719
|
|
|
$
|
718
|
|
|
|
|
|
|
|
|
|
|
The effective income tax rate for the year ended
December 31, 2007 differs from the U.S. statutory rate
of 35% due to a taxable dividend from foreign operations and
non-deductible interest, offset by earnings in foreign
jurisdictions that are taxed at rates lower than the
U.S. statutory rate including the impact of a law change
that reduced the German tax rate. For the year ended
December 31, 2006, the effective tax rate differs from the
U.S. statutory rate of 35% due to settlements paid from a
claimant reserve established at bankruptcy as well as earnings
in foreign jurisdictions that are taxed at rates lower than the
U.S. statutory rate.
Deferred
tax assets and valuation allowance
Net deferred tax balance As of
December 31, 2007, NRG recorded a net deferred tax
liability of $180 million. Due to an assessment of positive
and negative evidence, related to projected capital gains and
available tax planning strategies, NRG believes that it is more
likely than not that a benefit will not be realized on
$539 million of tax assets, thus a valuation allowance has
remained, resulting in a net deferred tax liability of
$719 million. NRG believes it is more likely than not that
future earnings will be sufficient to utilize the Companys
deferred tax assets, net of the existing valuation allowances at
December 31, 2007.
NOL carryforwards As of December 31,
2007, the Company had generated total domestic pretax book
income of $860 million which fully utilized cumulative
domestic net operating loss, or NOL, in the amount of
$245 million. In addition, as of December 31, 2007,
NRG has cumulative foreign NOL carryforwards of
$288 million of which $72 million will expire starting
2011 through 2016 and of which $216 million do not have an
expiration date.
Valuation allowance As of December 31,
2007, the Companys valuation allowance and other deferred
tax items were reduced as a result of the reduction in
NRGs net deferred tax assets. In accordance with
SOP 90-7,
these movements resulted in an increase in Additional Paid in
Capital of approximately $56 million.
As of December 31, 2006, these movements resulted in the
reduction of intangibles by $241 million, an increase in
Additional Paid in Capital of $17 million and reduced tax
expense by approximately $22 million (of which
$3 million was reflected in discontinued operations).
Any future reductions to valuation allowance will be recorded to
Additional
Paid-in-Capital
with the exception of $14 million which will be recorded to
income tax expense.
APB
Opinion 23
To the extent that NRG does not provide deferred income taxes
for unremitted earnings, it is managements intent to
permanently reinvest those earnings overseas in accordance with
APB Opinion No. 23 Accounting for Income Taxes-Special
Areas, or APB 23. If NRG does not permanently reinvest earnings
then deferred taxes of approximately $39 million would be
recognized for the cumulative translation adjustment as of
December 31, 2007.
185
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Repatriation
of foreign funds pursuant to the American Jobs Creation Act of
2004
Pursuant to the Jobs Act, during 2005, NRG elected to deduct 85%
of certain eligible dividends received from
non-U.S. subsidiaries
from its taxable income before the end of 2005 as those
dividends were reinvested in the U.S. for eligible
purposes. NRG repatriated approximately $298 million of
accumulated foreign earnings. Only a portion of this amount
represents the cumulative earnings and profits which resulted in
approximately $5 million of tax expense. The remaining
amounts transferred are considered a return of capital.
Tax
Holidays
During 2005, the Amazon Development Agency granted
an income tax holiday to our subsidiary ITISA pertaining to the
local tax liability resulting from ITISAs operating income
for Brazilian tax purposes, applicable retroactively to
January 1, 2005. The tax holiday program reduced the
effective income tax rate to 15.25% from a statutory income tax
rate of 34% resulting in a decrease in tax expense, recognized
within discontinued operations, of approximately $5 and
$3 million in 2007 and 2006 respectively. This tax holiday
will expire in December 31, 2013.
Uncertain
tax benefits
NRG has identified certain unrecognized tax benefits whose
after-tax value was $683 million, of which $19 million
would impact the Companys effective tax rate if
recognized. Of the $683 million in unrecognized tax
benefits, $664 million relates to periods prior to the
Companys emergence from bankruptcy. In accordance with
Statement of Position
90-7,
Financial Reporting by Entities in Reorganization under the
Bankruptcy Code, and the application of fresh start
accounting, recognition of previously unrecognized tax benefits
existing pre-emergence would not impact the Companys
effective tax rate but would increase Additional Paid in
Capital. As of December 31, 2007, NRG has recorded a
$7 million non-current tax liability for unrecognized tax
benefits. This amount was recorded after utilization in 2007 of
the cumulative domestic NOL. In accordance with
SFAS 141(R), any changes to our uncertain tax benefits
occurring after
1/1/2009,
will be credited to income tax expense rather than APIC.
NRG has accrued interest and penalties related to these
unrecognized tax benefits of approximately $4 million as of
the adoption of FIN 48 by the Company on January 1,
2007. The Company recognizes interest and penalties related to
unrecognized tax benefits in income tax expense. For the year
ended December 31, 2007, the Company incurred an immaterial
amount of interest and penalties related to its unrecognized tax
benefits.
Tax jurisdictions NRG is subject to
examination by taxing authorities for income tax returns filed
in the U.S. federal jurisdiction and various state and
foreign jurisdictions including major operations located in
Germany, Australia, and Brazil. The Company is no longer subject
to U.S. federal income tax examinations for years prior to
2002. With few exceptions, state and local income tax
examinations are no longer open for years before 2003. The
Companys significant foreign operations are also no longer
subject to examination by local jurisdictions for years prior to
2000.
Sale of ITISA On December 18, 2007, NRG
entered into a sale and purchase agreement to sell 100% interest
in Tosli, which holds all NRGs interest in ITISA, to
Brookfield Power Inc., a wholly-owned subsidiary of Brookfield
Asset Management Inc., for a purchase price of approximately
$288 million, plus the assumption of approximately
$60 million in debt. The transaction, which is subject to
the receipt of regulatory approval and other customary closing
conditions, is expected to close during the first half of 2008.
We expect a portion of this sale to result in capital gain,
which will further reduce our uncertain tax benefits.
186
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
As of
|
|
|
|
December 31,
|
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Balance as of January 1
|
|
$
|
712
|
|
Increase due to current year positions
|
|
|
76
|
|
Decrease due to current year positions
|
|
|
(105
|
)
|
Increase due to prior year positions
|
|
|
|
|
Decrease due to prior year positions
|
|
|
|
|
Decrease due to settlements and payments
|
|
|
|
|
Decrease due to statute expirations
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits as of December 31
|
|
$
|
683
|
|
|
|
|
|
|
German
Tax Reform Act 2008
On July 6, 2007, the German government passed the Tax
Reform Act of 2008, which reduces the German statutory and
resulting effective tax rates on earnings from approximately 36%
to approximately 27% effective January 1, 2008. Due to this
reduction in the statutory and resulting effective tax rate in
2007, NRG recognized a $29 million tax benefit and as of
December 31, 2007, NRG had a German net deferred tax
liability of approximately $84 million which includes the
impact of this tax rate change.
Note 19 Stock-Based
Compensation
In 2004, the FASB issued SFAS No. 123(R), a revision
to SFAS 123, which required NRG to modify the recognition
of expense for stock-based compensation in the statements of
operations. NRG adopted the requirements of SFAS 123(R)
effective January 1, 2006 using the modified prospective
method. The provisions of SFAS 123(R) did not result in a
significant change in NRGs compensation expense because
the Company previously recognized compensation expense in the
statements of operations under SFAS 123. In accordance with
SFAS 123(R), NRG estimated a forfeiture rate for each of
the Companys awards based on the number of instruments
expected to vest rather than recording the actual forfeitures as
they occur. The elimination of unearned compensation and amounts
previously recognized in income related to the application of
the new forfeiture rate to outstanding instruments as of
January 1, 2006 were immaterial to NRGs consolidated
statements of operations.
Long-Term
Incentive Plan, or LTIP
As of December 31, 2007, a total of 16,000,000 shares
of NRG common stock were authorized for issuance under the LTIP,
subject to adjustments in the event of a reorganization,
recapitalization, stock split, reverse stock split, stock
dividend, and a combination of shares, merger or similar change
in NRGs structure or outstanding shares of common stock.
It is NRGs policy to issue treasury shares upon exercise
of a LTIP award. If there are no treasury shares available, new
shares of common stock will be issued. There were
7,941,758 shares of common stock remaining available for
grants under NRGs LTIP as of December 31, 2007.
Non-Qualified
Stock Options, or NQSOs
NQSOs granted under the LTIP typically have a three-year
graded vesting schedule beginning on the grant date and become
exercisable at the end of the requisite service period. As
provided for by SFAS 123(R), for share options with graded
vesting issued after January 1, 2006, NRG recognizes
compensation costs on a straight-line basis over the requisite
service period for the entire award. The maximum contractual
term is ten years for approximately 1.3 million of
NRGs outstanding NQSOs, and six years for the
remaining 2.3 million NQSOs.
187
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the Companys NQSO activity
as of December 31, 2007 and changes during the year then
ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
|
|
|
Average
|
|
|
Contractual Term
|
|
|
Intrinsic Value
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
(in years)
|
|
|
(In millions)
|
|
|
|
|
|
|
(In whole, except weighted average data)
|
|
|
Outstanding at December 31, 2006
|
|
|
3,411,072
|
|
|
$
|
17.59
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
784,350
|
|
|
|
28.63
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(180,673
|
)
|
|
|
24.29
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(434,974
|
)
|
|
|
15.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
3,579,775
|
|
|
$
|
19.98
|
|
|
|
5
|
|
|
$
|
84
|
|
Exercisable at December 31, 2007
|
|
|
1,917,722
|
|
|
$
|
14.57
|
|
|
|
6
|
|
|
$
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of options granted
during the years ended December 31, 2007, 2006 and 2005 was
$8.28, $7.26 and $6.62, respectively. The total intrinsic value
of options exercised during the years ended December 31,
2007 and 2006 was $11 million and $1 million,
respectively and cash received from the exercise of these
options was $7 million and $1 million, respectively.
There were no NQSOs exercised during 2005.
The fair value of the Companys NQSOs is estimated on
the date of grant using the Black-Scholes option-pricing model.
Significant assumptions used in the fair value model for the
years ended December 31, 2007, 2006 and 2005 with respect
to the Companys NQSOs are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Expected volatility
|
|
|
25.88%-27.28%
|
|
|
|
27.95%-29.64%
|
|
|
|
29.75%
|
|
Expected dividend yield
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected term (in years)
|
|
|
4
|
|
|
|
4-6
|
|
|
|
5
|
|
Risk free rate
|
|
|
4.58%-4.68%
|
|
|
|
4.30%-5.05%
|
|
|
|
4.16%
|
|
For 2005 and 2006, expected volatility was calculated based on a
blended average of NRG and NRGs industry peers
historical two-year stock price volatility data. For 2007, as
more historical NRG data has become available, expected
volatility is calculated based on NRGs historical stock
price volatility data over the period commensurate with the
expected term of the stock option. Typically, the expected term
for the Companys NQSOs is based on the simple
average of the contractual term and vesting term.
Restricted
Stock Units, or RSUs
Typically, RSUs granted under the Companys LTIP
fully vest three years from the date of issuance. Fair value of
the RSUs is based on the closing price of NRG common stock
on the date of grant. The following table
188
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
summarizes the Companys non-vested RSU awards as of
December 31, 2007 and changes during the year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole except weighted average data)
|
|
|
Non-vested at December 31, 2006
|
|
|
2,277,186
|
|
|
$
|
15.74
|
|
Granted
|
|
|
568,580
|
|
|
|
38.61
|
|
Forfeited
|
|
|
(115,150
|
)
|
|
|
23.29
|
|
Vested
|
|
|
(1,142,300
|
)
|
|
|
10.74
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2007
|
|
|
1,588,316
|
|
|
$
|
26.99
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSUs vested during the years ended
December 31, 2007 and 2006, was $40 million and
$11 million, respectively. The total fair value of
RSUs vested during the year ended December 31, 2005
was immaterial.
Deferred
Stock Units, or DSUs
DSUs represent the right of a participant to be paid one
share of NRG common stock at the end of a deferral period
established under the terms of the award. DSUs granted
under the Companys LTIP are fully vested at the date of
issuance. Fair value of the DSUs, which is based on the
closing price of NRG common stock on the date of grant, is
recorded as compensation expense in the period of grant.
The following table summarizes the Companys outstanding
DSU awards as of December 31, 2007 and changes during the
year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole except weighted average data)
|
|
|
Outstanding at December 31, 2006
|
|
|
280,840
|
|
|
$
|
16.19
|
|
Granted
|
|
|
22,289
|
|
|
|
44.43
|
|
Conversions
|
|
|
(34,135
|
)
|
|
|
19.86
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
268,994
|
|
|
$
|
18.06
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic values for DSUs outstanding as of
December 31, 2007, 2006 and 2005 were approximately
$12 million, $8 million and $6 million,
respectively. The aggregate intrinsic values for DSUs
converted to common stock for the years ended December 31,
2007, 2006 and 2005 was $1.2 million, $.4 million and
$.3 million, respectively.
Performance
Units, or PUs
PUs granted under the Companys LTIP fully vest three
to five years from the date of issuance. PUs are paid out
upon vesting if the average closing price of NRGs common
stock for the ten trading days prior to the vesting date, or the
Measurement Price, is equal to or greater than the Target Price.
A Target Price and Maximum Price are determined on the date of
issuance. The payout for each PU will be equal to: (i) one
share of common stock, if the Measurement Price equals the
Target Price; (ii) a pro-rata amount between one and two
shares of common stock, if the Measurement Price is greater than
the Target Price but less than the Maximum Price; and
(iii) two shares of common stock, if the Measurement Price
is equal to, or greater than, the Maximum Price.
189
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the Companys non-vested PU
awards as of December 31, 2007 and changes during the year
then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Outstanding
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole except weighted average data)
|
|
|
Non-vested at December 31, 2006
|
|
|
410,664
|
|
|
$
|
18.86
|
|
Granted
|
|
|
189,300
|
|
|
|
22.43
|
|
Forfeited
|
|
|
(63,200
|
)
|
|
|
18.35
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2007
|
|
|
536,764
|
|
|
$
|
20.18
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of PUs granted
during the years ended December 31, 2007, 2006 and 2005 was
$22.43, $17.62 and $14.94, respectively. No PUs have
vested under the program as of December 31, 2007.
The fair value of PUs is estimated on the date of grant
using a Monte Carlo simulation model and expensed over the
service period, which equals the vesting period. Significant
assumptions used in the fair value model for the years ended
December 31, 2007, 2006 and 2005 with respect to the
Companys PUs are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Expected volatility
|
|
|
25.91%-27.28%
|
|
|
|
27.95%-29.64%
|
|
|
|
29.75%
|
|
Expected dividend payment (in dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected term (in years)
|
|
|
3
|
|
|
|
3-5
|
|
|
|
3
|
|
Risk free rate
|
|
|
4.54%-4.69%
|
|
|
|
4.30%-5.04%
|
|
|
|
4.09%
|
|
For 2005 and 2006, expected volatility was calculated based on a
blended average of NRG and NRGs industry peers
historical two-year stock price volatility data. For 2007, as
more historical NRG data has become available, expected
volatility is calculated based on NRGs historical stock
price volatility data over the period commensurate with the
expected term of the PU, which equals the vesting period.
Supplemental
Information
The following table summarizes NRGs total compensation
expense recognized in accordance with SFAS 123(R) for the
years ended December 31, 2007 and 2006, and in accordance
with SFAS 123 for the year ended 2005, for each of the four
types of awards issued under the Companys LTIP, as well as
total non-vested compensation costs not yet recognized and the
period over which this expense is expected to be recognized as
of December 31, 2007. Minimum tax withholdings of
$17 million and $5 million paid by the Company during
2007
190
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and 2006 are reflected as a reduction to additional paid in
capital on the Companys statement of financial position,
and are reflected as operating activities on the Companys
statement of cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Non-Vested
|
|
|
Weighted Average
|
|
|
|
|
|
|
Compensation Cost
|
|
|
Life Remaining
|
|
|
|
Compensation Expense
|
|
|
Not Yet Recognized
|
|
|
(In years)
|
|
|
|
Year Ended December 31
|
|
|
As of December 31
|
|
Award
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2007
|
|
|
|
(In millions, except weighted average data)
|
|
|
NQSOs
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
4
|
|
|
$
|
8
|
|
|
|
0.9
|
|
RSUs
|
|
|
10
|
|
|
|
10
|
|
|
|
8
|
|
|
|
27
|
|
|
|
1.4
|
|
DSUs
|
|
|
1
|
|
|
|
1
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
PUs
|
|
|
3
|
|
|
|
2
|
|
|
|
|
|
|
|
5
|
|
|
|
1.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
19
|
|
|
$
|
18
|
|
|
$
|
15
|
|
|
$
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit recognized
|
|
$
|
8
|
|
|
$
|
7
|
|
|
$
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 20 Related
Party Transactions
Operating
Agreements
NRG has entered into operation and maintenance agreements, or
O&M agreements, with certain Company equity investments
including Saguaro and Gladstone. Fees for services under these
contracts primarily include recovery of NRGs costs of
operating the plant as approved in the annual budget, as well as
a base monthly fee. In addition, NRG renders technical
consulting services to MIBRAG under a consulting agreement. NRG
has also entered into long-term coal purchase agreements with
MIBRAG to supply coal to Schkopau.
These fees and expenses are included in the Companys
operating revenues and operating costs in the consolidated
statements of operations and consisted of the following:
Related
Party Transactions with Equity Investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Revenues from Related Parties Included in Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
WCP(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
O&M fees
|
|
$
|
|
|
|
$
|
1
|
|
|
$
|
6
|
|
AMA fees
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Gladstone
|
|
|
|
|
|
|
|
|
|
|
|
|
O&M fees
|
|
|
1
|
|
|
|
2
|
|
|
|
3
|
|
MIBRAG
|
|
|
|
|
|
|
|
|
|
|
|
|
Consulting fees
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
5
|
|
|
$
|
7
|
|
|
$
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses from Related Parties Included in Cost of
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of purchased coal
|
|
$
|
43
|
|
|
$
|
43
|
|
|
$
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
For the period January 1, 2006 to March 31, 2006
|
191
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 21 Commitments
and Contingencies
Operating
Lease Commitments
NRG leases certain Company facilities and equipment under
operating leases, some of which include escalation clauses,
expiring on various dates through 2023. Certain operating lease
agreements over their lease term include provisions such as
scheduled rent increases, leasehold incentives, and rent
concessions. The Company recognizes the effects of these
scheduled rent increases, leasehold incentives, and rent
concessions on a straight-line basis over the lease term unless
another systematic and rational allocation basis is more
representative of the time pattern in which the leased property
is physically employed. Rental expense under operating leases
was approximately $40 million, $37 million and
$9 million for the years ended December 31, 2007, 2006
and 2005, respectively.
Future minimum lease commitments under operating leases for the
years ending after December 31, 2007 are as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2008
|
|
$
|
40
|
|
2009
|
|
|
38
|
|
2010
|
|
|
35
|
|
2011
|
|
|
33
|
|
2012
|
|
|
31
|
|
Thereafter
|
|
|
243
|
|
|
|
|
|
|
Total
|
|
$
|
420
|
|
|
|
|
|
|
Coal,
Gas and Transportation Commitments
NRG has entered into long-term contractual arrangements to
procure fuel and transportation services for the Companys
generation assets and for the years ended December 31,
2007, 2006, and 2005, the Company purchased approximately
$1.7 billion, $1.8 billion and $0.7 billion,
respectively, under such arrangements.
As of December 31, 2007, the Companys commitments
under such outstanding agreements are estimated as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2008
|
|
$
|
1,614
|
|
2009
|
|
|
795
|
|
2010
|
|
|
264
|
|
2011
|
|
|
150
|
|
2012
|
|
|
149
|
|
Thereafter
|
|
|
231
|
|
|
|
|
|
|
Total(a)
|
|
$
|
3,203
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes only those coal
transportation commitments for 2008 as no other nominations were
made as of December 31, 2007.
|
Lignite
Contract with Texas Westmoreland Coal Co.
The lignite used to fuel the Texas regions Limestone
facility is obtained from a surface mine, or the Jewett mine,
adjacent to the facility under an amended long-term contract
with TWCC, originally entered into in 1979. In June 2007, TWCC
notified NRG of their election to deliver zero tons of lignite
from the Jewett Mine for 2008,
192
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
effectively ending TWCCs rights to deliver lignite from
the Jewett Mine per the long-term contract after
December 31, 2007. During the third quarter of 2007, NRG
and TWCC renegotiated a long-term contract that has
significantly changed the contractual structure as well as
extended the mining period. The new contract is based on a
cost-plus arrangement with incentives and penalties to ensure
proper management of the mine. NRG has flexibility to increase
or decrease lignite purchases from the mine within certain
ranges, including the ability to suspend or terminate lignite
purchases with adequate notice. The mining period has been
extended through 2018 with an option to extend the mining period
by two five-year intervals.
TWCC is responsible for performing ongoing reclamation
activities at the mine until all lignite reserves have been
produced. When production is completed at the mine, NRG will be
responsible for final mine reclamation obligations. Due to an
increase in reclamation estimates offset by the negotiated
three-year extension of the mining contract, the Companys
asset retirement obligation for mine reclamation costs increased
by $5 million.
The Railroad Commission of Texas has imposed a bond obligation
of approximately $83 million on TWCC for the reclamation of
this lignite mine. Pursuant to the contract with TWCC, an
affiliate of CenterPoint Energy, Inc. has guaranteed
$50 million of this obligation. The remaining sum of
approximately $33 million has been bonded by the mine
operator, TWCC. Approximately $7 million of such amount is
supported by a letter of credit posted by NRG. Under the terms
of the new cost plus agreement with TWCC, NRG is required to
maintain a corporate guarantee of TWCCs bond obligation in
the amount of $50 million if CenterPoint Energy,
Inc.s obligation lapses, or pay the costs of obtaining
replacement performance assurance. Additionally, NRG is required
to provide additional performance assurance over TWCCs
current bond obligations if required by the Commission.
International
Commitments
Two of the Companys wholly-owned, indirect subsidiaries
are severally responsible for the pro rata payments of
principal, interest and related costs incurred in connection
with the financing of NRGs equity investment in the
unincorporated joint venture Gladstone Power Station. At
December 31, 2007, the Company was obligated for the loan
of AUD 42 million (approximately US $37 million) in
principal. This loan is scheduled to be fully repaid on
March 31, 2009.
First
and Second Lien Structure
NRG has granted first and second priority liens to certain
counterparties on substantially all of the Companys assets
in the United States in order to secure certain obligations,
which are primarily long-term in nature under certain power sale
agreements and related contracts. NRG uses the first or second
lien structure to reduce the amount of cash collateral and
letters of credit that it would otherwise be required to post
from time to time to support its obligations under these
agreements. Within the first and second lien structure, the
Company can hedge up to 80% of its baseload capacity and 10% of
its non-baseload assets with these counterparties.
As part of NRGs amended and restated credit agreement
signed June 8, 2007, the Company obtained the ability to
move its current second lien counterparty exposure to the first
lien, on a pari passu basis with the Companys existing
first lien lenders. In exchange for moving some second lien
holders to a pari passu basis with the Companys first lien
lenders, the counterparties relinquished letters of credit
issued by NRG which they held as a part of their collateral
package.
On October 30, 2007, NRG successfully moved certain second
lien holders to a pari passu basis with the Companys first
lien lenders effectively releasing $557 million of letters
of credit. With the movement to the first lien structure, the
Company has significantly reduced its outstanding letter of
credit exposure and thereby increased its liquidity. As of
December 31, 2007, the net discounted exposure on the
agreements and hedges that were subject to the first and second
lien structure was approximately $425 million.
193
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
RepoweringNRG
Project Deposit
NRG has made non-refundable deposits relating to
RepoweringNRG initiatives totaling approximately
$71 million primarily towards the procurement of wind
turbines. The Company believes that these deposits are necessary
for the timely and successful execution of these projects. The
deposits are in support of expected deliveries of wind turbines
and other equipment totaling approximately $409 million
through 2009. Although NRG is committed to their successful
implementation, the Company may decide not to take delivery of
the equipment and thus terminate the projects. This would result
in the Company expensing the deposits it already has made.
On February 4, 2008, NRG through its wholly owned
subsidiary, Padoma Wind Power LLC, had entered into a
50-50 joint
venture with BP Alternative Energy North America Inc. to build
the first phase of the Sherbino Wind Farm. The Sherbino I Wind
Farm will be a 150-megawatt (MW) wind project, consisting of 50
Vestas 3 MW wind turbine generators, located approximately
40 miles east of Fort Stockton in Pecos County, Texas.
NRG expects to contribute approximately $83 million in
equity to the joint venture in 2008 and has posted a letter of
credit in that amount.
Contingencies
Set forth below is a description of the Companys material
legal proceedings. Pursuant to the requirements of
SFAS No. 5, Accounting for Contingencies, or
SFAS 5, and related guidance, NRG records reserves for
estimated losses from contingencies when information available
indicates that a loss is probable and the amount of the loss can
be reasonably estimated. Because litigation is subject to
inherent uncertainties and unfavorable rulings or developments
could occur, there can be no certainty that NRG may not
ultimately incur charges in excess of presently recorded
reserves. A future adverse ruling or unfavorable development
could result in future charges, which could have a materially
adverse effect on NRGs consolidated financial position,
results of operations, or cash flows.
With respect to a number of the items listed below, management
has determined that a loss is not probable or the amount of the
loss is not reasonably estimable, or both. In some cases,
management is not able to predict with any degree of substantial
certainty the range of possible loss that could be incurred.
Notwithstanding these facts, management has assessed each of
these matters based on current information and made a judgment
concerning its potential outcome, considering the nature of the
claim, the amount and nature of damages sought, and the
probability of success. Managements judgment may, as a
result of facts arising prior to resolution of these matters, or
other factors, prove inaccurate and investors should be aware
that such judgment is made subject to the uncertainty of
litigation.
In addition to the legal proceedings noted below, NRG and its
subsidiaries are party to other litigation or legal proceedings
arising in the ordinary course of business. In managements
opinion, the disposition of these ordinary course matters will
not materially adversely effect NRGs consolidated
financial position, results of operations, or cash flows.
NRG believes that it has valid defenses to the legal proceedings
and investigations described below 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 below, the Company is unable to predict
the outcome that these legal proceedings and investigations 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. NRG also has indemnity rights for
some of these proceedings to reimburse NRG for certain legal
expenses and to offset certain amounts deemed to be owed in the
event of an unfavorable litigation outcome.
California
Electricity and Related Litigation
NRG, WCP, WCPs four operating subsidiaries, Dynegy, Inc.,
and numerous other unrelated parties are the subject of lawsuits
that arose based on events that occurred in the California power
market in 2000 and 2001. The
194
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
complaints primarily allege that the defendants engaged in
unfair business practices, price fixing, antitrust violations,
and other market gaming activities. Other cases, including
putative class actions, have been filed in state and federal
court on behalf of business and residential consumers that name
WCP and/or
subsidiaries of WCP, in addition to numerous other defendants.
These complaints allege the defendants attempted to manipulate
gas indexes by reporting false and fraudulent trades, and
violated Californias antitrust law and unfair business
practices law. The complaints seek restitution and disgorgement,
civil fines, compensatory and punitive damages, attorneys
fees, and declaratory and injunctive relief. Discovery is
proceeding in these cases. In October 2007, Dynegy reached a
tentative settlement of all remaining coordinated natural gas
index cases pending in state court in San Diego. The
settlement has yet to be funded by Dynegy and requires court
approval which is underway. If approved, neither WCP and its
subsidiaries nor NRG would pay any settlement costs as Dynegy
owed and continues to provide a complete defense and
indemnification.
In cases relating to natural gas, Dynegy is defending WCP
and/or its
subsidiaries pursuant to an indemnification agreement and will
be the responsible party for any loss. There are no further
cases related to electricity, but should any new cases arise,
Dynegys counsel would represent it and WCP
and/or its
subsidiaries, with each party responsible for half of the costs
and each party responsible for half of any loss.
California
Department of Water Resources
On December 19, 2006, the U.S. Court of Appeals for
the Ninth Circuit reversed the Federal Energy Regulatory
Commissions, or FERCs, prior determinations
regarding the enforceability of certain wholesale power
contracts and remanded the case to FERC for further proceedings
consistent with the decision. One of these contracts was the
wholesale power contract between the California Department of
Water Resources, or CDWR, and subsidiaries of WCP. This case
originated with a February 2002 complaint filed at FERC by the
State of California alleging that many parties, including WCP
subsidiaries, overcharged the State. For WCP, the alleged
overcharges totaled approximately $940 million for 2001 and
2002. The complaint demanded that FERC abrogate the CDWR
contract and sought refunds associated with revenues collected
under the contract. In 2003, FERC rejected this complaint,
denied rehearing, and the case was appealed to the Ninth Circuit
where oral argument was held on December 8, 2004. On
December 19, 2006, the Court decided that in FERCs
review of the contracts at issue, FERC could not rely on the
Mobile-Sierra standard presumption of just and reasonable rates,
where such contracts were not reviewed by FERC with full
knowledge of the then existing market conditions. On May 3,
2007, WCP and the other defendants filed separate petitions for
certiorari seeking review by the U.S. Supreme Court and on
September 25, 2007, the Court agreed to hear two of the
filed petitions. Although WCPs petition was not selected
for review, the Courts ultimate decision with respect to
the other defendants petitions will apply equally to WCP.
Oral argument occurred on February 19, 2008, and a decision
is expected from the Court by the end of 2008. At this time,
while NRG cannot predict with certainty whether WCP will be
required to make refunds for rates collected under the CDWR
contract or estimate the range of any such possible refunds, a
reconsideration of the CDWR contract by FERC with a resulting
order mandating significant refunds could have a material
adverse impact on NRGs financial position, statement of
operations, and statement of cash flows. As part of the 2006
acquisition of Dynegys 50% ownership interest in WCP, WCP
and NRG assumed responsibility for any risk of loss arising from
this case, unless any such loss was deemed to have resulted from
certain acts of gross negligence or willful misconduct on the
part of Dynegy, in which case any such loss would be shared
equally between WCP and Dynegy.
Station
Service Disputes
On October 2, 2000, Niagara Mohawk Power Corporation, or
NiMo, commenced an action against NRG in New York state court
seeking damages related to NRGs alleged failure to pay
retail tariff amounts for utility services at the Dunkirk plant
between June 1999 and September 2000. The parties agreed to
consolidate this action with two other actions against the
Huntley and Oswego plants. On October 8, 2002, by
stipulation and order, this action was stayed pending submission
to FERC of the disputes in the action. At FERC, NiMo asserted
the same claims and legal theories, and on November 19,
2004, FERC denied NiMos petition and ruled that the NRG
facilities could net their service obligations over each 30
calendar day period from the day NRG acquired the
195
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
appealed to the U.S. Court of Appeals for the D.C. Circuit
which, on June 23, 2006, denied the appeal finding that New
York Independent System Operators, or NYISOs,
station service program that permits generators to self supply
their station power needs by netting consumption against
production in a month is lawful. On April 30, 2007, the
U.S. Supreme Court denied NiMos request for review of
the D.C. Circuit decision thus ending further avenues to appeal
FERCs ruling in this matter. NRG believes it is adequately
reserved.
On December 14, 1999, NRG acquired certain generating
facilities from CL&P. A dispute arose over station service
power and delivery services provided to the facilities. On
December 20, 2002, as a result of a petition filed at FERC
by Northeast Utilities Services Company on behalf of itself and
CL&P, FERC issued an order finding that, at times when NRG
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. In August 2003, the parties agreed to submit the dispute
to binding arbitration. On September 11, 2007, the parties
argued the dispute before a three judge arbitration panel. On
February 19, 2008, the parties executed a settlement
agreement ending the arbitration. A component of the settlement
requires approval from ISO-NE. Our accrual was reversed into
income consistent with the settlement.
Spring
Creek Coal Company
In August 2007, Spring Creek Coal Company filed a complaint
against NRG Texas LP, NRG South Texas LP, NRG Texas Power LLC,
NRG Texas LLC, and NRG Energy, Inc. in the U.S. District
Court for the federal district of Wyoming. The complaint alleges
multiple breaches in 2007 of a 1978 coal supply agreement as
amended by a later 1987 agreement, which plaintiff alleges is a
take or pay contract. Damages of approximately
$18 million are being sought. Certain of the defendants
have filed a motion to dismiss for lack of personal jurisdiction
and certain other defendants have filed a motion to dismiss for
lack of a case in controversy. The court will hear these and
other motions on July 11, 2008. The trial is scheduled to
begin on September 8, 2008.
Native
Village of Kivalina and City of Kivalina
Numerous electric generating companies and oil and gas companies
have been named as defendants in this complaint, which has been
filed but not yet served on NRG. Damages of up to
$400 million have been asserted. The complaint alleges that
the carbon dioxide emissions of defendants contribute to global
climate change which has harmed the plaintiffs. The complaint is
filed on behalf of an Alaskan town made up of native tribes and
seeks damages associated with those tribes having to relocate
from the northern coast of Alaska, purportedly because of the
effects of global warming.
Disputed
Claims Reserve
As part of NRGs plan of reorganization, NRG 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, as such claims
are resolved, the claimants are paid from the reserve on the
same basis as if they had been paid out in the bankruptcy. To
the extent the aggregate amount required to be paid on the
disputed claims exceeds the amount remaining in the funded
claims reserve, NRG will be obligated to provide additional cash
and common stock to satisfy the claims. Any excess funds in the
disputed claims reserve will be reallocated to the creditor pool
for the pro rata benefit of all allowed claims. The contributed
common stock and cash in the reserves is held by an escrow agent
to complete the distribution and settlement process. Since NRG
has surrendered control over the common stock and cash provided
to the disputed claims reserve, NRG recognized the issuance of
the common stock as of December 6, 2003 and removed the
cash amounts from the balance sheet. Similarly, NRG removed the
obligations relevant to the claims from the balance sheet when
the common stock was issued and cash contributed.
On April 3, 2006, the Company made a supplemental
distribution to creditors under the Companys
Chapter 11 bankruptcy plan, totaling $25 million in
cash and 5,082,000 shares of common stock. As of
February 7, 2008, the
196
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
reserve held approximately $10 million in cash and
approximately 1,317,138 shares of common stock on a
post-stock split basis. NRG believes the cash and stock together
represent sufficient funds to satisfy all remaining disputed
claims.
Note 22 Regulatory
Matters
NRG operates in a highly regulated industry and the Company is
subject to regulation by various federal and state agencies. As
such, NRG is affected by regulatory developments at both the
federal and state levels and in the regions in which NRG
operates. In addition, NRG is subject to the market rules,
procedures, and protocols of the various ISO markets in which
NRG participates. These wholesale power markets are subject to
ongoing legislative and regulatory changes.
Northeast
Region
New England On July 16, 2007, FERC
conditionally accepted, subject to refund, the
Reliability-Must-Run, or RMR, agreement filed on April 26,
2007 by Norwalk Power for its units 1 and 2, specifying a
June 19, 2007 effective date. Norwalks RMR rate and
its eligibility for the RMR agreement, which is based upon the
facilitys projected market revenues and costs, are subject
to further proceedings. Norwalk filed for the RMR agreement in
response to FERCs order eliminating the Peaking Unit Safe
Harbor bidding mechanism which took effect on June 19,
2007. Settlement proceedings are still ongoing.
On December 28, 2006, the Attorney General of the State of
Connecticut and Commonwealth of Massachusetts filed an appeal of
the FERC orders accepting the settlement of the New England
capacity market design with the U.S. Court of Appeals for
the D.C. Circuit. The settlement, filed with FERC on
March 7, 2006, by a broad group of New England market
participants, provides for interim capacity transition payments
for all generators in New England for the period starting
December 1, 2006 through May 31, 2010, and the
establishment of a FCM commencing May 31, 2010. On
June 16, 2006, FERC issued an order accepting the
settlement, which was reaffirmed on rehearing by order dated
October 31, 2006. Interim capacity transition payments
provided for under the FCM settlement commenced December 1,
2006, as scheduled. A successful appeal by the Attorneys General
could disturb the settlement and create a refund obligation of
interim capacity transition payments. Oral argument was held on
February 14, 2008.
New York On July 6, 2007, FERC issued an
order establishing an approximately six-month paper hearing
process to address reforms to the in-city Installed Capacity, or
ICAP, market and to formulate comprehensive solutions. On
October 4, 2007, the NYISO filed its proposal for revisions
to the ICAP market for the New York City zone. While the
NYISOs proposal will retain the existing ICAP market
structure, it will impose additional market power mitigation on
the current owners of Consolidated Edisons divested
generation units in New York City (which include NRGs
Arthur Kill and Astoria facilities) who are deemed to be pivotal
suppliers. Specifically, the NYISO proposal will impose a
reference price on pivotal suppliers and require bids to be
submitted at or below the reference price. The reference price
will be the expected clearing price based upon the intersection
of the supply curve and the ICAP Demand Curve if all suppliers
bid as price-takers. The NYISO proposal, if accepted by FERC,
would result in a significant decrease in the clearing price for
New York City capacity. Earlier this year, FERC had rejected
proposed mitigation that would have effectively lowered the
capacity offer cap for those units from $105/kW-year to
$82/kW-year. Although that proposal was rejected on
March 6, 2007, FERC initiated an investigation to determine
the justness and reasonableness of the NYISOs in-city
installed capacity market, setting a refund effective date of
May 12, 2007. The NYISOs October 4, 2007 filing
proposes that any market reforms should be implemented only
prospectively and that no refunds should be required.
On December 18, 2007, the U.S. Court of Appeals for
the D.C. Circuit denied the appeals relating to the high prices
for spinning reserves, or SR, and non-spinning reserves, or NSR,
in the NYISO-administered markets during the period from
January 29, 2000 to March 27, 2000. Certain entities
had argued that the NYISO acted unreasonably in declining to
invoke Temporary Extraordinary Operating Procedures, or TEP, to
recalculate prices
197
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
and that the markets should be resettled for various reasons. In
a series of orders, FERC had declined to grant the requested
relief, explaining that (i) the NYISO acted reasonably in
not invoking TEP, (ii) NYISO did not violate its tariff,
and (iii) refunds should not be granted as they would be
disruptive to settled market expectations. The Courts
December 18, 2007 order is expected to conclude this matter.
On March 15, 2006, NRG received the results from NYISO
Market Monitoring Units review of NRGS Astoria
plants 2004 Generating Availability Data System reporting.
This audit may result in the resettlement of NRGs capacity
revenues from the Astoria facility due to a redetermination of
the amount of available capacity. NRG is currently in settlement
discussions with the NYISO, and the Company believes that it is
adequately reserved.
PJM On August 23, 2007, several
entities, including the New Jersey Board of Public Utilities,
the District of Columbia Office of the Peoples Counsel,
and the Maryland Office of Peoples Counsel, filed appeals
of the FERC orders accepting the settlement of the locational
capacity market for PJM Interconnection, LLC. The settlement,
filed at FERC on September 29, 2006, provides for a
capacity market mechanism known as the Reliability Pricing
Model, or RPM, which is designed to provide a long-term price
signal through competitive forward auctions. On
December 22, 2006, FERC issued an order accepting the
settlement, which was reaffirmed on rehearing by order dated
June 25, 2007. The RPM auction period for delivery year
June 1, 2007 through May 31, 2008 was conducted
earlier this year, and capacity payments pursuant to the RPM
mechanism have commenced. A successful appeal by the appellants
could disturb the settlement and create a refund obligation of
capacity payments.
On January 15, 2008, the Maryland Public Service
Commission, or MDPSC, filed at FERC a complaint against PJM
claiming that PJM had failed to adequately mitigate certain
generation resources, due to exemptions for resources used to
relieve reactive limits on interfaces or that were constructed
during certain periods after 1999. In addition to seeking an
order eliminating the exemptions and a refund effective date as
of the date of the complaint, the MDPSC is also seeking an
investigation of periods prior to the complaint that could lead
to disgorgement by certain entities, and possibly a resettlement
of the market back to September 8, 2006. The principal
impacts on NRG would occur as a resettlement of the LMPs, which
is not viewed as likely at this time, and going-forward in the
form of lower LMPs. In addition, NRGs peaking units at its
energy center in Dover, Delaware were built in 2001 and utilize
the post-1999 bidding exemption.
Note 23 Environmental
Matters
The construction and operation of power projects are subject to
stringent environmental and safety protection and land use laws
and regulation in the U.S. If such laws and regulations
become more stringent, or new laws, interpretations or
compliance policies apply and NRGs facilities are not
exempt from coverage, the Company could be required to make
modifications to further reduce potential environmental impacts.
New greenhouse gas legislation and regulations to mitigate the
effects of gases, including
CO2
from power plants, are under consideration at the federal and
state levels. In general, the effect of such future laws or
regulations is expected to require the addition of pollution
control equipment or the imposition of restrictions or
additional costs on the Companys operations.
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2008
through 2012 to meet NRGs environmental commitments will
be between $1.0 billion and $1.4 billion. These
capital expenditures, in general, are related to installation of
particulate,
SO2,
NOx,
and mercury controls to comply with Clean Air Interstate Rule,
or CAIR, the Clean Air Mercury Rule, or CAMR, and related state
requirements as well as installation of Best Technology
Available under the Phase II 316(b) rule. NRG continues to
explore cost effective alternatives that can achieve desired
results. The range reflects alternative strategies available
with respect to the Companys Indian River plant.
198
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Northeast
Region
In January 2006, NRGs Indian River Operations, Inc.
received a letter of informal notification from DNREC stating
that it may be a potentially responsible party with respect to a
historic captive landfill. On October 1, 2007, NRG filed a
Facility Evaluation with DNREC, through the Voluntary
Clean-up
Program to investigate the site. DNREC responded to the Facility
Evaluation on February 4, 2008 finding no further action is
required in relation to surface water and that a previously
planned shoreline stabilization project would adequately address
shore line erosion. The landfill itself will require a further
Remedial Investigation and Feasibility Study to determine the
type and scope of any additional work required. Until the
Remedial Investigation and Feasibility Study is completed, the
Company is unable to predict the impact of any required
remediation.
In November 2006, DNREC, promulgated
Regulation No. 1146, or Reg 1146, Electric Generating
Unit Multi-Pollutant Regulation and Section 111(d) of the
State Plan for the Control of Mercury Emissions from Coal-Fired
Electric Steam Generating Units. These regulations govern the
control of
SO2,
NOx,
and mercury emissions from electric generating units. NRGs
plan to install controls at the Companys Indian River
facility, while on an accelerated basis, was unable to meet
certain deadlines, taking into account the time required, as a
practical matter, to design, install and commission the
necessary equipment. NRG filed a challenge to Reg 1146 with the
Environmental Appeals Board, or EAB, on December 6, 2006.
In addition, NRG also filed a protective appeal with the
Delaware Superior Court on December 29, 2006. This
challenge was settled when DNREC and NRG signed a Consent Order
on September 25, 2007, and filed that document with the
Delaware Superior Court thereby ending the case. Under this
agreement, continued operations at the Companys Indian
River Generating Station are conditioned upon installation of
controls on Units 1 and 2 by May 1, 2008, to reduce
NOx;
installation of controls on Units 1-4 by January 1, 2009 to
meet mercury requirements; mothball of Units 1 and 2 by
May 1, 2011, and May 1, 2010, respectively; and
installation of advanced controls on Units 3 and 4 in 2011 to
further reduce
NOx
and
SO2.
If the plant emits
NOx
in excess of 1,700 tons in any given ozone season, it will be
subject to a graduated scale of stipulated penalties, up to a
maximum $2,500/ton. The capital costs associated with this
settlement are included in the Companys estimated
environmental capital expenditures. In the absence of the
appropriate control technology installed at this facility, Units
3 and 4 totaling approximately 565 MW, could not operate
beyond December 31, 2011, per terms of the Consent Order.
South
Central Region
On January 27, 2004, NRGs Louisiana Generating, LLC
and the Companys Big Cajun II plant received a
request under Section 114 of the Clean Air Act from the
United States Environmental Protection Agency, or USEPA, seeking
information primarily related to physical changes made at the
Big Cajun II plant, and subsequently received a notice of
violation, or NOV, on February 15, 2005, alleging that
NRGs predecessors had undertaken projects that triggered
requirements under the Prevention of Significant Deterioration
program, including the installation of emission controls. NRG
submitted multiple responses commencing February 27, 2004
and ending on October 20, 2004. On May 9, 2006, these
entities received from the Department of Justice, or DOJ, a
Notice of Deficiency related to their responses, to which NRG
responded on May 22, 2006. A document review was conducted
at NRGs Louisiana Generating, LLC offices by the DOJ
during the week of August 14, 2006. On December 8,
2006, the USEPA issued a supplemental NOV updating the original
February 15, 2005 NOV. Discussions with the USEPA are
ongoing and the Company cannot predict with certainty the
outcome of this matter.
199
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 24 Cash
Flow Information
Detail of supplemental disclosures of cash flow and non-cash
investing and financing information was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Interest paid, net of amount capitalized
|
|
$
|
598
|
|
|
$
|
450
|
|
|
$
|
257
|
|
Income taxes
paid(a)
|
|
|
22
|
|
|
|
18
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Addition to fixed assets due to asset retirement obligations
|
|
|
7
|
|
|
|
15
|
|
|
|
4
|
|
Addition to treasury stock for the maximum purchase price
adjustment
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
(a)
|
|
2007 income taxes paid is net of
$6 million federal tax refund received.
|
Note 25 Guarantees
NRG and its subsidiaries enter into various contracts that
include indemnification and guarantee provisions as a routine
part of the Companys business activities. Examples of
these contracts include asset purchase and sale agreements,
commodity sale and purchase agreements, joint venture
agreements, operations and maintenance agreements, service
agreements, settlement agreements, and other types of
contractual agreements with vendors and other third parties.
These contracts generally indemnify the counter-party for tax,
environmental liability, litigation, and other matters, as well
as breaches of representations, warranties, and covenants set
forth in the agreements. In many cases, the Companys
maximum potential liability cannot be estimated, since some of
the underlying agreements contain no limits on potential
liability. In accordance with FIN 45, NRG has estimated
that the current fair value for issuing these guarantees was
approximately $9 million as of December 31, 2007, and
the liability in this amount is included in the Companys
non-current liabilities.
The following table summarizes NRGs estimated guarantees,
indemnity, and other contingent liability obligations by
maturity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
|
2007
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2006
|
|
Guarantees
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Synthetic letters of credit
|
|
$
|
475
|
|
|
$
|
268
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
743
|
|
|
$
|
967
|
|
Unfunded letters of credit and surety bonds
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
153
|
|
Asset sales guarantee obligations
|
|
|
13
|
|
|
|
|
|
|
|
113
|
|
|
|
22
|
|
|
|
148
|
|
|
|
144
|
|
Commercial sales arrangements
|
|
|
93
|
|
|
|
134
|
|
|
|
|
|
|
|
564
|
|
|
|
791
|
|
|
|
604
|
|
Other guarantees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
32
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total guarantees
|
|
$
|
589
|
|
|
$
|
402
|
|
|
$
|
113
|
|
|
$
|
618
|
|
|
$
|
1,722
|
|
|
$
|
1,897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letters of credit and surety bonds As of
December 31, 2007, NRG and its consolidated subsidiaries
were contingently obligated for a total of approximately
$751 million under letters of credit and surety bonds. Most
of these letters of credit and surety bonds are issued in
support of the Companys obligations to perform under
commodity agreements, financing or other arrangements. A
majority of these letters of credit and surety bonds expire
within one year of issuance, and it is typical for the Company
to renew them on similar terms.
200
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Asset sale guarantees NRG is typically
requested to provide certain assurances to the counter-parties
of the Companys asset sale agreements. Such assurances may
take the form of a guarantee issued by the Company on behalf of
a directly or indirectly held majority-owned subsidiary which
include certain indemnifications to a third party, usually the
buyer, as described below. Due to the inter-company nature of
such arrangements, NRG is essentially guaranteeing its own
performance, and the nature of the guarantee being provided. It
is not the Companys policy to recognize the value of such
an obligation in its consolidated financial statements. Most of
these guarantees provide an explicit cap on the Companys
maximum liability, as well as an expiration period, exclusive of
breach of representations and warranties.
On December 18, 2007, NRG entered into a share and purchase
agreement to sell its 100% interest in Tosli to Brookfield Power
Inc. NRG has guaranteed the payment and performance of its
wholly owned subsidiarys Sterling Luxemburg (No. 4)
obligations under the share and purchase agreement. The maximum
liability of NRG is limited to the sale price of
$288 million.
Commercial sales arrangements In connection
with the purchase and sale of fuel, emission allowances and
power generation products to and from third parties with respect
to the operation of some of NRGs generation facilities in
the U.S., the Company may be required to guarantee a portion of
the obligations of certain of its subsidiaries. These
obligations may include liquidated damages payments or other
unscheduled payments.
Other guarantees NRG has issued guarantees of
obligations that its subsidiaries may incur as a provision for
environmental site remediation, payment of debt obligations,
rail car leases, performance under purchase, EPC and operating
and maintenance agreements. In 2007, NRG executed a guarantee
related to its obligations as construction manager under its
agreements related to a wind farm project. In addition, NRG
entered into a guarantee under an EPC contract related to a
repowering project. The Company does not believe that it will be
required to perform under this guarantee.
The material indemnities, within the scope of FIN 45, are
as follows:
Asset purchases and divestitures The purchase
and sale agreements, which govern NRGs asset or share
investments and divestitures, customarily contain
indemnifications of the transaction to third parties. The
contracts indemnify the parties for liabilities incurred as a
result of a breach of a representation or warranty by the
indemnifying party, or as a result of a change in tax laws.
These obligations generally have a discrete term and are
intended to protect the parties against risks that are difficult
to predict or estimate at the time of the transaction. In
several cases, the contract limits the liability of the
indemnifier. For those indemnities in which liability is capped,
the minimum exposures range from $1 million to
$288 million. NRG has no reason to believe that the Company
currently has any material liability relating to such routine
indemnification obligations.
Other indemnities Other indemnifications NRG
has provided cover operational, tax, litigation and breaches of
representations, warranties and covenants. NRG has also
indemnified, on a routine basis in the ordinary course of
business, consultants or other vendors who have provided
services to the Company. NRGs maximum potential exposure
under these indemnifications can range from a specified dollar
amount to an indeterminate amount, depending on the nature of
the transaction. Total maximum potential exposure under these
indemnifications is not estimable due to uncertainty as to
whether claims will be made or how they will be resolved. NRG
does not have any reason to believe that the Company will be
required to make any material payments under these indemnity
provisions.
Because many of the guarantees and indemnities NRG issues to
third parties do not limit the amount or duration of its
obligations to perform under them, there exists a risk that the
Company may have obligations in excess of the amounts described
above. For those guarantees and indemnities that do not limit
the Companys liability exposure, it may not be able to
estimate what the Companys liability would be, until a
claim is made for payment or performance, due to the contingent
nature of these contracts.
201
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 26 Jointly
Owned Plants
Certain NRG subsidiaries own undivided interests in certain
jointly-owned plants, described below. These plants are
maintained and operated pursuant to their joint ownership
participation and operating agreements. NRG is responsible for
its subsidiaries share of operating costs and direct
expense and includes its proportionate share of the facilities
and related revenues and direct expenses in these jointly-owned
plants in the corresponding balance sheet, and income statement
captions of the Companys consolidated financial statements.
The following table summarizes NRGs proportionate
ownership interest in the Companys jointly-owned
facilities as of December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
|
Property, Plant &
|
|
|
Accumulated
|
|
|
Construction in
|
|
As of December 31,
2007
|
|
Interest
|
|
|
Equipment
|
|
|
Depreciation
|
|
|
Progress
|
|
|
|
(In millions unless otherwise stated)
|
|
|
South Texas Project Units 1 and 2, Bay City, TX
|
|
|
44.00
|
%
|
|
$
|
2,914
|
|
|
$
|
(345
|
)
|
|
$
|
19
|
|
Big Cajun II Unit 3, New Roads, LA
|
|
|
58.00
|
|
|
|
173
|
|
|
|
(39
|
)
|
|
|
10
|
|
Cedar Bayou Unit 4, Baytown, TX
|
|
|
50.00
|
|
|
|
|
|
|
|
|
|
|
|
71
|
|
Keystone, Shelocta, PA
|
|
|
3.70
|
|
|
|
61
|
|
|
|
(12
|
)
|
|
|
6
|
|
Conemaugh, New Florence, PA
|
|
|
3.72
|
|
|
|
72
|
|
|
|
(15
|
)
|
|
|
1
|
|
202
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Note 27 Unaudited
Quarterly Financial Data
Summarized unaudited quarterly financial data is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended 2007
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
|
(In millions, except per share data)
|
|
|
Operating revenues
|
|
$
|
1,382
|
|
|
$
|
1,772
|
|
|
$
|
1,536
|
|
|
$
|
1,299
|
|
Operating income
|
|
|
320
|
|
|
|
546
|
|
|
|
427
|
|
|
|
267
|
|
Income from continuing operations, net of income taxes
|
|
|
100
|
|
|
|
265
|
|
|
|
143
|
|
|
|
61
|
|
Income from discontinued operations, net of income taxes
|
|
|
4
|
|
|
|
3
|
|
|
|
6
|
|
|
|
4
|
|
Net income
|
|
$
|
104
|
|
|
$
|
268
|
|
|
$
|
149
|
|
|
$
|
65
|
|
Weighted average number of common shares outstanding
basic
|
|
|
239
|
|
|
|
239
|
|
|
|
240
|
|
|
|
244
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
0.36
|
|
|
$
|
1.06
|
|
|
$
|
0.54
|
|
|
$
|
0.19
|
|
Income from discontinued operations per weighted average common
share basic
|
|
$
|
0.02
|
|
|
$
|
0.01
|
|
|
$
|
0.02
|
|
|
$
|
0.02
|
|
Net income per weighted average common share basic
|
|
$
|
0.38
|
|
|
$
|
1.07
|
|
|
$
|
0.56
|
|
|
$
|
0.21
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
270
|
|
|
|
285
|
|
|
|
288
|
|
|
|
271
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
0.34
|
|
|
$
|
0.92
|
|
|
$
|
0.49
|
|
|
$
|
0.19
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
0.02
|
|
|
|
0.01
|
|
Net income per weighted average common share diluted
|
|
$
|
0.35
|
|
|
$
|
0.93
|
|
|
$
|
0.51
|
|
|
$
|
0.20
|
|
203
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended 2006
|
|
|
|
December 31
|
|
|
September 30
|
|
|
June 30
|
|
|
March 31
|
|
|
|
(In millions, except per share data)
|
|
|
Operating revenues
|
|
$
|
1,135
|
|
|
$
|
1,932
|
|
|
$
|
1,492
|
|
|
$
|
1,026
|
|
Operating income
|
|
|
96
|
|
|
|
713
|
|
|
|
404
|
|
|
|
205
|
|
Income/(loss) from continuing operations, net of income taxes
|
|
|
(35
|
)
|
|
|
367
|
|
|
|
198
|
|
|
|
13
|
|
Income from discontinued operations, net of income taxes
|
|
|
5
|
|
|
|
55
|
|
|
|
5
|
|
|
|
13
|
|
Net income/(loss)
|
|
$
|
(30
|
)
|
|
$
|
422
|
|
|
$
|
203
|
|
|
$
|
26
|
|
Weighted average number of common shares outstanding
basic
|
|
|
250
|
|
|
|
272
|
|
|
|
274
|
|
|
|
235
|
|
Income/(loss) from continuing operations per weighted average
common share basic
|
|
$
|
(0.19
|
)
|
|
$
|
1.30
|
|
|
$
|
0.67
|
|
|
$
|
0.01
|
|
Income/(loss) from discontinued operations per weighted average
common share basic
|
|
|
0.02
|
|
|
|
0.20
|
|
|
|
0.02
|
|
|
|
0.05
|
|
Net income/(loss) per weighted average common share
basic
|
|
$
|
(0.17
|
)
|
|
$
|
1.50
|
|
|
$
|
0.69
|
|
|
$
|
0.06
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
250
|
|
|
|
317
|
|
|
|
319
|
|
|
|
238
|
|
Income/(loss) from continuing operations per weighted average
common share diluted
|
|
$
|
(0.19
|
)
|
|
$
|
1.15
|
|
|
$
|
0.61
|
|
|
$
|
0.01
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
0.02
|
|
|
|
0.17
|
|
|
|
0.02
|
|
|
|
0.05
|
|
Net income/(loss) per weighted average common share
diluted
|
|
$
|
(0.17
|
)
|
|
$
|
1.32
|
|
|
$
|
0.63
|
|
|
$
|
0.06
|
|
Note 28 Condensed
Consolidating Financial Information
As of December 31, 2007, the Company had $1.2 billion
of 7.25% Senior Notes due 2014, $2.4 billion of
7.375% Senior Notes due 2016 and $1.1 billion Senior
Notes due 2017 outstanding. These notes are guaranteed by
certain of NRGs current and future wholly-owned domestic
subsidiaries, or guarantor subsidiaries.
Each of the following guarantor subsidiaries fully and
unconditionally guaranteed the Senior Notes as of
December 31, 2007:
|
|
|
Arthur Kill Power LLC
|
|
NRG Construction LLC
|
Astoria Gas Turbine Power LLC
|
|
NRG Devon Operations Inc.
|
Berrians I Gas Turbine Power LLC
|
|
NRG Dunkirk Operations Inc.
|
Big Cajun II Unit 4 LLC
|
|
NRG El Segundo Operations Inc.
|
Cabrillo Power I LLC
|
|
NRG Generation Holdings, Inc.
|
Cabrillo Power II LLC
|
|
NRG Huntley Operations Inc.
|
Chickahominy River Energy Corp.
|
|
NRG International LLC
|
Commonwealth Atlantic Power LLC
|
|
NRG Kaufman LLC
|
Conemaugh Power LLC
|
|
NRG Mesquite LLC
|
Connecticut Jet Power LLC
|
|
NRG MidAtlantic Affiliate Services Inc.
|
Devon Power LLC
|
|
NRG Middletown Operations Inc.
|
Dunkirk Power LLC
|
|
NRG Montville Operations Inc.
|
Eastern Sierra Energy Company
|
|
NRG New Jersey Energy Sales LLC
|
204
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
El Segundo Power, LLC
|
|
NRG New Roads Holdings LLC
|
El Segundo Power II LLC
|
|
NRG North Central Operations Inc.
|
GCP Funding Company, LLC
|
|
NRG Northeast Affiliate Services Inc.
|
Hanover Energy Company
|
|
NRG Norwalk Harbor Operations Inc.
|
Hoffman Summit Wind Project, LLC
|
|
NRG Operating Services, Inc.
|
Huntley IGCC LLC
|
|
NRG Oswego Harbor Power Operations Inc.
|
Huntley Power LLC
|
|
NRG Power Marketing LLC
|
Indian River IGCC LLC
|
|
NRG Rocky Road LLC
|
Indian River Operations Inc.
|
|
NRG Saguaro Operations Inc.
|
Indian River Power LLC
|
|
NRG South Central Affiliate Services Inc.
|
James River Power LLC
|
|
NRG South Central Generating LLC
|
Kaufman Cogen LP
|
|
NRG South Central Operations Inc.
|
Keystone Power LLC
|
|
NRG South Texas LP
|
Lake Erie Properties Inc.
|
|
NRG Texas LLC
|
Louisiana Generating LLC
|
|
NRG Texas Power LLC
|
Middletown Power LLC
|
|
NRG West Coast LLC
|
Montville IGCC LLC
|
|
NRG Western Affiliate Services Inc.
|
Montville Power LLC
|
|
Oswego Harbor Power LLC
|
NEO Chester-Gen LLC
|
|
Padoma Wind Power, LLC
|
NEO Corporation
|
|
Saguaro Power LLC
|
NEO Freehold-Gen LLC
|
|
San Juan Mesa Wind Project II, LLC
|
NEO Power Services Inc.
|
|
Somerset Operations Inc.
|
New Genco GP, LLC
|
|
Somerset Power LLC
|
Norwalk Power LLC
|
|
Texas Genco Financing Corp.
|
NRG Affiliate Services Inc.
|
|
Texas Genco GP, LLC
|
NRG Arthur Kill Operations Inc.
|
|
Texas Genco Holdings, Inc.
|
NRG Asia-Pacific, Ltd.
|
|
Texas Genco LP, LLC
|
NRG Astoria Gas Turbine Operations Inc.
|
|
Texas Genco Operating Services, LLC
|
NRG Bayou Cove LLC
|
|
Texas Genco Services, LP
|
NRG Cabrillo Power Operations Inc.
|
|
Vienna Operations Inc.
|
NRG Cadillac Operations Inc.
|
|
Vienna Power LLC
|
NRG California Peaker Operations LLC
|
|
WCP (Generation) Holdings LLC
|
NRG Cedar Bayou Development Company, LLC
|
|
West Coast Power LLC
|
NRG Connecticut Affiliate Services Inc
|
|
|
The non-guarantor subsidiaries include all of NRGs foreign
subsidiaries and certain domestic subsidiaries. NRG conducts
much of its business through and derives much of its income from
its subsidiaries. Therefore, the Companys ability to make
required payments with respect to its indebtedness and other
obligations depends on the financial results and condition of
its subsidiaries and NRGs ability to receive funds from
its subsidiaries. Except for NRG Bayou Cove, LLC, which is
subject to certain restrictions under the Companys Peaker
financing agreements,
205
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
there are no restrictions on the ability of any of the guarantor
subsidiaries to transfer funds to NRG. In addition, there may be
restrictions for certain non-guarantor subsidiaries.
The following condensed consolidating financial information
presents the financial information of NRG Energy, Inc., the
guarantor subsidiaries and the non-guarantor subsidiaries in
accordance with
Rule 3-10
under the Securities and Exchange Commissions
Regulation S-X.
The financial information may not necessarily be indicative of
results of operations or financial position had the guarantor
subsidiaries or non-guarantor subsidiaries operated as
independent entities.
In this presentation, NRG Energy, Inc. consists of parent
company operations. Guarantor subsidiaries and non-guarantor
subsidiaries of NRG are reported on an equity basis. For
companies acquired, the fair values of the assets and
liabilities acquired have been presented on a push-down
accounting basis.
206
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF OPERATIONS
For the
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,614
|
|
|
$
|
375
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,131
|
|
|
|
247
|
|
|
|
|
|
|
|
|
|
|
|
3,378
|
|
Depreciation and amortization
|
|
|
630
|
|
|
|
24
|
|
|
|
4
|
|
|
|
|
|
|
|
658
|
|
General and administrative
|
|
|
101
|
|
|
|
19
|
|
|
|
189
|
|
|
|
|
|
|
|
309
|
|
Development costs
|
|
|
66
|
|
|
|
2
|
|
|
|
33
|
|
|
|
|
|
|
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,928
|
|
|
|
292
|
|
|
|
226
|
|
|
|
|
|
|
|
4,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/(loss) on sale of assets
|
|
|
18
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,704
|
|
|
|
83
|
|
|
|
(227
|
)
|
|
|
|
|
|
|
1,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
204
|
|
|
|
|
|
|
|
986
|
|
|
|
(1,190
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
(3
|
)
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
Gain on sale of equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Other income, net
|
|
|
9
|
|
|
|
13
|
|
|
|
33
|
|
|
|
|
|
|
|
55
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
(35
|
)
|
Interest expense
|
|
|
(250
|
)
|
|
|
(64
|
)
|
|
|
(375
|
)
|
|
|
|
|
|
|
(689
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
(40
|
)
|
|
|
7
|
|
|
|
609
|
|
|
|
(1,190
|
)
|
|
|
(614
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
1,664
|
|
|
|
90
|
|
|
|
382
|
|
|
|
(1,190
|
)
|
|
|
946
|
|
Income tax expense/(benefit)
|
|
|
576
|
|
|
|
5
|
|
|
|
(204
|
)
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
1,088
|
|
|
|
85
|
|
|
|
586
|
|
|
|
(1,190
|
)
|
|
|
569
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
1,088
|
|
|
$
|
102
|
|
|
$
|
586
|
|
|
$
|
(1,190
|
)
|
|
$
|
586
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
207
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
BALANCE SHEETS
December 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
Consolidated
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy Inc.
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
(In millions)
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
(4
|
)
|
|
$
|
124
|
|
|
$
|
1,012
|
|
$
|
|
|
|
$
|
1,132
|
Restricted cash
|
|
|
1
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
29
|
Accounts receivable-trade, net
|
|
|
445
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
482
|
Inventory
|
|
|
439
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
451
|
Deferred income taxes
|
|
|
139
|
|
|
|
(18
|
)
|
|
|
3
|
|
|
|
|
|
|
124
|
Derivative instruments valuation
|
|
|
1,034
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,034
|
Collateral on deposit in support of energy risk management
activities
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
|
Prepayments and other current assets
|
|
|
96
|
|
|
|
35
|
|
|
|
195
|
|
|
(152
|
)
|
|
|
174
|
Current assets discontinued operations
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,235
|
|
|
|
269
|
|
|
|
1,210
|
|
|
(152
|
)
|
|
|
3,562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
10,828
|
|
|
|
470
|
|
|
|
22
|
|
|
|
|
|
|
11,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
610
|
|
|
|
|
|
|
|
9,787
|
|
|
(10,397
|
)
|
|
|
|
Equity investments in affiliates
|
|
|
28
|
|
|
|
397
|
|
|
|
|
|
|
|
|
|
|
425
|
Notes receivable
|
|
|
360
|
|
|
|
126
|
|
|
|
3,779
|
|
|
(4,139
|
)
|
|
|
126
|
Capital lease, less current portion
|
|
|
|
|
|
|
365
|
|
|
|
|
|
|
|
|
|
|
365
|
Goodwill
|
|
|
1,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,786
|
Intangible assets, net
|
|
|
859
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
873
|
Intangible assets held-for-sale
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
Nuclear decommissioning trust fund
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384
|
Derivative instruments valuation
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150
|
Other non-current assets
|
|
|
11
|
|
|
|
1
|
|
|
|
164
|
|
|
|
|
|
|
176
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
4,202
|
|
|
|
996
|
|
|
|
13,730
|
|
|
(14,536
|
)
|
|
|
4,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
17,265
|
|
|
$
|
1,735
|
|
|
$
|
14,962
|
|
$
|
(14,688
|
)
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
83
|
|
|
$
|
282
|
|
|
$
|
184
|
|
$
|
(83
|
)
|
|
$
|
466
|
Accounts payable trade
|
|
|
(699
|
)
|
|
|
352
|
|
|
|
731
|
|
|
|
|
|
|
384
|
Derivative instruments valuation
|
|
|
916
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
917
|
Accrued expenses and other current liabilities
|
|
|
335
|
|
|
|
62
|
|
|
|
145
|
|
|
(69
|
)
|
|
|
473
|
Current liabilities discontinued operations
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
635
|
|
|
|
734
|
|
|
|
1,060
|
|
|
(152
|
)
|
|
|
2,277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
3,773
|
|
|
|
571
|
|
|
|
7,690
|
|
|
(4,139
|
)
|
|
|
7,895
|
Nuclear decommissioning reserve
|
|
|
307
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
307
|
Nuclear decommissioning trust liability
|
|
|
326
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
326
|
Deferred income taxes
|
|
|
598
|
|
|
|
(138
|
)
|
|
|
383
|
|
|
|
|
|
|
843
|
Derivative instruments valuation
|
|
|
690
|
|
|
|
16
|
|
|
|
53
|
|
|
|
|
|
|
759
|
Non-current out-of-market contracts
|
|
|
628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
628
|
Other non-current liabilities
|
|
|
377
|
|
|
|
10
|
|
|
|
25
|
|
|
|
|
|
|
412
|
Non-current liabilities discontinued operations
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
6,699
|
|
|
|
535
|
|
|
|
8,151
|
|
|
(4,139
|
)
|
|
|
11,246
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
7,334
|
|
|
|
1,269
|
|
|
|
9,211
|
|
|
(4,291
|
)
|
|
|
13,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
247
|
Stockholders Equity
|
|
|
9,931
|
|
|
|
466
|
|
|
|
5,504
|
|
|
(10,397
|
)
|
|
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
17,265
|
|
|
$
|
1,735
|
|
|
$
|
14,962
|
|
$
|
(14,688
|
)
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
208
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
NRG Energy,
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,088
|
|
|
$
|
102
|
|
|
$
|
586
|
|
|
$
|
(1,190
|
)
|
|
$
|
586
|
|
Adjustments to reconcile net income to net cash provided/(used)
by operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions in excess/(less than) equity in earnings of
unconsolidated affiliates
|
|
|
101
|
|
|
|
(36
|
)
|
|
|
(684
|
)
|
|
|
586
|
|
|
|
(33
|
)
|
Depreciation and amortization of nuclear fuel
|
|
|
688
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
719
|
|
Amortization and write-of of deferred financing costs and debt
discount/premiums
|
|
|
|
|
|
|
6
|
|
|
|
60
|
|
|
|
|
|
|
|
66
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(160
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
(156
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
Gains on sale of equity method investments
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
(Gain)/loss on sale assets
|
|
|
(18
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
(17
|
)
|
Impairment charges and asset write downs
|
|
|
9
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
20
|
|
Changes in derivatives
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
|
|
Changes in deferred income taxes
|
|
|
112
|
|
|
|
(31
|
)
|
|
|
271
|
|
|
|
|
|
|
|
352
|
|
Gain on sale of emission allowances
|
|
|
(30
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(31
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(125
|
)
|
Cash provided/(used) by changes in other working capital, net of
disposition affects
|
|
|
214
|
|
|
|
100
|
|
|
|
(305
|
)
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
1,988
|
|
|
|
170
|
|
|
|
(37
|
)
|
|
|
(604
|
)
|
|
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany loans to subsidiaries
|
|
|
655
|
|
|
|
|
|
|
|
2,109
|
|
|
|
(2,764
|
)
|
|
|
|
|
Capital expenditures
|
|
|
(389
|
)
|
|
|
(84
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
(481
|
)
|
Decrease in restricted cash, net
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Decrease in trust fund balances
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Purchases of emission allowances
|
|
|
(161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(161
|
)
|
Proceeds from sale of emission allowances
|
|
|
271
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
272
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(265
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
233
|
|
Proceeds from sale of investment and equipment
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Purchase of securities
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
(49
|
)
|
Proceeds from sale of discontinued operations and assets
|
|
|
29
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
392
|
|
|
|
(35
|
)
|
|
|
2,080
|
|
|
|
(2,764
|
)
|
|
|
(327
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
(55
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
(353
|
)
|
Payments from intercompany loans
|
|
|
(2,101
|
)
|
|
|
(38
|
)
|
|
|
(625
|
)
|
|
|
2,764
|
|
|
|
|
|
Payments from intercompany dividends
|
|
|
(302
|
)
|
|
|
(302
|
)
|
|
|
|
|
|
|
604
|
|
|
|
|
|
Proceeds from issuance of common stock
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
|
|
|
|
1,411
|
|
|
|
|
|
|
|
1,411
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
Payments of short and long-term debt
|
|
|
(1
|
)
|
|
|
(64
|
)
|
|
|
(1,754
|
)
|
|
|
|
|
|
|
(1,819
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(2,404
|
)
|
|
|
(404
|
)
|
|
|
(1,374
|
)
|
|
|
3,368
|
|
|
|
(814
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(decrease) in Cash and Cash Equivalents
|
|
|
(24
|
)
|
|
|
(290
|
)
|
|
|
669
|
|
|
|
|
|
|
|
355
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
20
|
|
|
|
414
|
|
|
|
343
|
|
|
|
|
|
|
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
(4
|
)
|
|
$
|
124
|
|
|
$
|
1,012
|
|
|
$
|
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
209
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,282
|
|
|
$
|
303
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,040
|
|
|
|
223
|
|
|
|
2
|
|
|
|
|
|
|
|
3,265
|
|
Depreciation and amortization
|
|
|
562
|
|
|
|
23
|
|
|
|
5
|
|
|
|
|
|
|
|
590
|
|
General and administrative
|
|
|
83
|
|
|
|
13
|
|
|
|
180
|
|
|
|
|
|
|
|
276
|
|
Development costs
|
|
|
32
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,717
|
|
|
|
259
|
|
|
|
191
|
|
|
|
|
|
|
|
4,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,565
|
|
|
|
44
|
|
|
|
(191
|
)
|
|
|
|
|
|
|
1,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
134
|
|
|
|
|
|
|
|
996
|
|
|
|
(1,130
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
2
|
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
60
|
|
Write downs and gains/(losses) on sales of equity method
investments
|
|
|
(5
|
)
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
Other income, net
|
|
|
20
|
|
|
|
115
|
|
|
|
41
|
|
|
|
(20
|
)
|
|
|
156
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
(187
|
)
|
|
|
|
|
|
|
(187
|
)
|
Interest expense
|
|
|
(232
|
)
|
|
|
(56
|
)
|
|
|
(322
|
)
|
|
|
20
|
|
|
|
(590
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
(81
|
)
|
|
|
130
|
|
|
|
528
|
|
|
|
(1,130
|
)
|
|
|
(553
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
1,484
|
|
|
|
174
|
|
|
|
337
|
|
|
|
(1,130
|
)
|
|
|
865
|
|
Income tax expense
|
|
|
549
|
|
|
|
42
|
|
|
|
(269
|
)
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
935
|
|
|
|
132
|
|
|
|
606
|
|
|
|
(1,130
|
)
|
|
|
543
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
63
|
|
|
|
15
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
935
|
|
|
$
|
195
|
|
|
$
|
621
|
|
|
$
|
(1,130
|
)
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
210
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG Energy
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
20
|
|
|
$
|
414
|
|
|
$
|
343
|
|
|
$
|
|
|
|
$
|
777
|
|
Restricted cash
|
|
|
1
|
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
Accounts receivable-trade, net
|
|
|
332
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
369
|
|
Inventory
|
|
|
408
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
420
|
|
Deferred income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments valuation
|
|
|
1,230
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,230
|
|
Collateral on deposit in support of energy risk management
activities
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
Prepayments and other current assets
|
|
|
173
|
|
|
|
33
|
|
|
|
736
|
|
|
|
(747
|
)
|
|
|
195
|
|
Current assets discontinued operations
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,191
|
|
|
|
560
|
|
|
|
1,079
|
|
|
|
(747
|
)
|
|
|
3,083
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
11,178
|
|
|
|
349
|
|
|
|
19
|
|
|
|
|
|
|
|
11,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
730
|
|
|
|
|
|
|
|
9,163
|
|
|
|
(9,893
|
)
|
|
|
|
|
Equity investments in affiliates
|
|
|
31
|
|
|
|
313
|
|
|
|
|
|
|
|
|
|
|
|
344
|
|
Notes receivable, less current portion
|
|
|
1,015
|
|
|
|
114
|
|
|
|
5,503
|
|
|
|
(6,518
|
)
|
|
|
114
|
|
Capital lease, less current portion, net
|
|
|
|
|
|
|
365
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
Goodwill
|
|
|
1,789
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,789
|
|
Intangible assets, net
|
|
|
977
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
981
|
|
Intangible assets held-for-sale
|
|
|
78
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
79
|
|
Nuclear decommissioning trust fund
|
|
|
352
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
352
|
|
Derivative instruments valuation
|
|
|
424
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
439
|
|
Deferred income taxes
|
|
|
27
|
|
|
|
(27
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other non-current assets
|
|
|
24
|
|
|
|
56
|
|
|
|
182
|
|
|
|
|
|
|
|
262
|
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
82
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
5,447
|
|
|
|
907
|
|
|
|
14,864
|
|
|
|
(16,411
|
)
|
|
|
4,807
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
18,816
|
|
|
$
|
1,816
|
|
|
$
|
15,962
|
|
|
$
|
(17,158
|
)
|
|
$
|
19,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
460
|
|
|
$
|
94
|
|
|
$
|
37
|
|
|
$
|
(468
|
)
|
|
$
|
123
|
|
Accounts payable trade
|
|
|
(682
|
)
|
|
|
284
|
|
|
|
727
|
|
|
|
|
|
|
|
329
|
|
Derivative instruments valuation
|
|
|
964
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
964
|
|
Deferred income taxes
|
|
|
23
|
|
|
|
7
|
|
|
|
134
|
|
|
|
|
|
|
|
164
|
|
Accrued expenses and other current liabilities
|
|
|
509
|
|
|
|
35
|
|
|
|
160
|
|
|
|
(280
|
)
|
|
|
424
|
|
Current liabilities discontinued operations
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,274
|
|
|
|
448
|
|
|
|
1,058
|
|
|
|
(748
|
)
|
|
|
2,032
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
5,504
|
|
|
|
825
|
|
|
|
8,791
|
|
|
|
(6,517
|
)
|
|
|
8,603
|
|
Nuclear decommissioning reserve
|
|
|
289
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
289
|
|
Nuclear decommissioning trust liability
|
|
|
324
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
324
|
|
Deferred income taxes
|
|
|
494
|
|
|
|
(104
|
)
|
|
|
164
|
|
|
|
|
|
|
|
554
|
|
Derivative instruments valuation
|
|
|
325
|
|
|
|
6
|
|
|
|
20
|
|
|
|
|
|
|
|
351
|
|
Non-current out-of-market contracts
|
|
|
897
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
897
|
|
Other non-current liabilities
|
|
|
385
|
|
|
|
8
|
|
|
|
24
|
|
|
|
|
|
|
|
417
|
|
Non-current liabilities discontinued operations
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
8,218
|
|
|
|
799
|
|
|
|
8,999
|
|
|
|
(6,517
|
)
|
|
|
11,499
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
9,492
|
|
|
|
1,247
|
|
|
|
10,057
|
|
|
|
(7,265
|
)
|
|
|
13,531
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority Interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
247
|
|
Stockholders Equity
|
|
|
9,324
|
|
|
|
569
|
|
|
|
5,658
|
|
|
|
(9,893
|
)
|
|
|
5,658
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
18,816
|
|
|
$
|
1,816
|
|
|
$
|
15,962
|
|
|
$
|
(17,158
|
)
|
|
$
|
19,436
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
211
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
935
|
|
|
$
|
195
|
|
|
$
|
621
|
|
|
$
|
(1,130
|
)
|
|
$
|
621
|
|
Adjustments to reconcile net income to net cash provided/(used)
by operating activities Distributions in excess/(less than)
equity in earnings of unconsolidated affiliates
|
|
|
(136
|
)
|
|
|
(31
|
)
|
|
|
(996
|
)
|
|
|
1,130
|
|
|
|
(33
|
)
|
Depreciation and amortization of nuclear fuel
|
|
|
609
|
|
|
|
35
|
|
|
|
10
|
|
|
|
|
|
|
|
654
|
|
Amortization and write-of of deferred financing costs and debt
discount/premiums
|
|
|
|
|
|
|
6
|
|
|
|
73
|
|
|
|
|
|
|
|
79
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(487
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
(490
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
|
|
|
|
14
|
|
Write down and gains on sale of equity method investments
|
|
|
5
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
Loss on sale of equipment
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
Changes in derivatives
|
|
|
(151
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
(149
|
)
|
Changes in deferred income taxes
|
|
|
474
|
|
|
|
19
|
|
|
|
(166
|
)
|
|
|
|
|
|
|
327
|
|
Gain on legal settlement
|
|
|
|
|
|
|
(67
|
)
|
|
|
|
|
|
|
|
|
|
|
(67
|
)
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(71
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
(76
|
)
|
Gain on sale of emission allowances
|
|
|
(64
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(64
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
454
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
454
|
|
Settlement of out-of-market power contracts
|
|
|
(1,073
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,073
|
)
|
Cash provided by changes in other working capital, net of
acquisition and disposition affects
|
|
|
(554
|
)
|
|
|
213
|
|
|
|
538
|
|
|
|
|
|
|
|
197
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
34
|
|
|
|
285
|
|
|
|
89
|
|
|
|
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
I/C loans to subsidiaries
|
|
|
(939
|
)
|
|
|
|
|
|
|
(4,106
|
)
|
|
|
5,045
|
|
|
|
|
|
Acquisition of Texas Genco LLC, WCP and Padoma, net of cash
acquired
|
|
|
|
|
|
|
|
|
|
|
(4,333
|
)
|
|
|
|
|
|
|
(4,333
|
)
|
Capital expenditures
|
|
|
(195
|
)
|
|
|
(21
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
(221
|
)
|
Decrease in restricted cash, net
|
|
|
2
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
Purchases of emission allowances
|
|
|
(135
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(135
|
)
|
Proceeds from sale of emission allowances
|
|
|
146
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
146
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(227
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(227
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
214
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
214
|
|
Proceeds from sale of investments
|
|
|
53
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
86
|
|
Proceeds from sale of discontinued operations
|
|
|
|
|
|
|
239
|
|
|
|
22
|
|
|
|
|
|
|
|
261
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
(1,081
|
)
|
|
|
282
|
|
|
|
(8,422
|
)
|
|
|
5,045
|
|
|
|
(4,176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
(50
|
)
|
Payment of financing element of acquired derivatives
|
|
|
(296
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(296
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
(500
|
)
|
|
|
(232
|
)
|
|
|
|
|
|
|
(732
|
)
|
Funded letter of credit
|
|
|
|
|
|
|
|
|
|
|
350
|
|
|
|
|
|
|
|
350
|
|
Proceeds from Intercompany loans
|
|
|
4,106
|
|
|
|
|
|
|
|
939
|
|
|
|
(5,045
|
)
|
|
|
|
|
Proceeds from issuance of common stock, net
|
|
|
|
|
|
|
|
|
|
|
986
|
|
|
|
|
|
|
|
986
|
|
Proceeds from issuance of preferred shares, net
|
|
|
|
|
|
|
|
|
|
|
486
|
|
|
|
|
|
|
|
486
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
333
|
|
|
|
8,286
|
|
|
|
|
|
|
|
8,619
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(199
|
)
|
|
|
|
|
|
|
(199
|
)
|
Payments of short and long-term debt
|
|
|
(2,736
|
)
|
|
|
(62
|
)
|
|
|
(2,313
|
)
|
|
|
|
|
|
|
(5,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
1,074
|
|
|
|
(229
|
)
|
|
|
8,253
|
|
|
|
(5,045
|
)
|
|
|
4,053
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
2
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(decrease) in Cash and Cash Equivalents
|
|
|
27
|
|
|
|
343
|
|
|
|
(79
|
)
|
|
|
|
|
|
|
291
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
(7
|
)
|
|
|
71
|
|
|
|
422
|
|
|
|
|
|
|
|
486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
20
|
|
|
$
|
414
|
|
|
$
|
343
|
|
|
$
|
|
|
|
$
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
212
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
2,095
|
|
|
$
|
310
|
|
|
$
|
|
|
|
$
|
(5
|
)
|
|
$
|
2,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
1,600
|
|
|
|
234
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
1,829
|
|
Depreciation and amortization
|
|
|
133
|
|
|
|
20
|
|
|
|
5
|
|
|
|
|
|
|
|
158
|
|
General and administrative
|
|
|
39
|
|
|
|
14
|
|
|
|
123
|
|
|
|
|
|
|
|
176
|
|
Other charges
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,778
|
|
|
|
268
|
|
|
|
134
|
|
|
|
(5
|
)
|
|
|
2,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
317
|
|
|
|
42
|
|
|
|
(134
|
)
|
|
|
|
|
|
|
225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
101
|
|
|
|
|
|
|
|
274
|
|
|
|
(375
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
35
|
|
|
|
69
|
|
|
|
|
|
|
|
|
|
|
|
104
|
|
Write downs and gains/(losses) on sales of equity method
investments
|
|
|
(47
|
)
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
(31
|
)
|
Other income, net
|
|
|
16
|
|
|
|
46
|
|
|
|
13
|
|
|
|
(21
|
)
|
|
|
54
|
|
Refinancing expense
|
|
|
|
|
|
|
1
|
|
|
|
(66
|
)
|
|
|
|
|
|
|
(65
|
)
|
Interest expense
|
|
|
(1
|
)
|
|
|
(56
|
)
|
|
|
(141
|
)
|
|
|
21
|
|
|
|
(177
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income
|
|
|
104
|
|
|
|
76
|
|
|
|
80
|
|
|
|
(375
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) From Continuing Operations Before Income
Taxes
|
|
|
421
|
|
|
|
118
|
|
|
|
(54
|
)
|
|
|
(375
|
)
|
|
|
110
|
|
Income tax expense/(benefit)
|
|
|
155
|
|
|
|
17
|
|
|
|
(130
|
)
|
|
|
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
266
|
|
|
|
101
|
|
|
|
76
|
|
|
|
(375
|
)
|
|
|
68
|
|
Income from discontinued operations, net of income taxes
|
|
|
5
|
|
|
|
3
|
|
|
|
8
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
271
|
|
|
$
|
104
|
|
|
$
|
84
|
|
|
$
|
(375
|
)
|
|
$
|
84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
213
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
271
|
|
|
$
|
104
|
|
|
$
|
84
|
|
|
$
|
(375
|
)
|
|
$
|
84
|
|
Adjustments to reconcile net income to net cash provided/ (used)
by operating activities Distributions in excess/(less than)
equity in earnings of unconsolidated affiliates
|
|
|
(64
|
)
|
|
|
(45
|
)
|
|
|
453
|
|
|
|
(352
|
)
|
|
|
(8
|
)
|
Depreciation and amortization of nuclear fuel
|
|
|
133
|
|
|
|
52
|
|
|
|
10
|
|
|
|
|
|
|
|
195
|
|
Amortization and write-of of deferred financing costs and debt
discount/premiums
|
|
|
|
|
|
|
(4
|
)
|
|
|
18
|
|
|
|
|
|
|
|
14
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(2
|
)
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Amortization of unearned equity compensation
|
|
|
3
|
|
|
|
1
|
|
|
|
8
|
|
|
|
|
|
|
|
12
|
|
Write down and (gains)/losses on sale of equity method
investments
|
|
|
47
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
31
|
|
Loss on sale of equipment
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Impairment charges
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Changes in derivatives
|
|
|
150
|
|
|
|
(10
|
)
|
|
|
3
|
|
|
|
|
|
|
|
143
|
|
Changes in deferred income taxes
|
|
|
71
|
|
|
|
13
|
|
|
|
(82
|
)
|
|
|
|
|
|
|
2
|
|
Gain on legal settlement
|
|
|
|
|
|
|
(14
|
)
|
|
|
|
|
|
|
|
|
|
|
(14
|
)
|
Gain on sale of discontinued operations
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(405
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(405
|
)
|
Cash provided by changes in other working capital, net of
acquisition and disposition affects
|
|
|
(421
|
)
|
|
|
10
|
|
|
|
404
|
|
|
|
|
|
|
|
(7
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
(213
|
)
|
|
|
110
|
|
|
|
898
|
|
|
|
(727
|
)
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return of capital from subsidiaries
|
|
|
|
|
|
|
|
|
|
|
1,398
|
|
|
|
(1,398
|
)
|
|
|
|
|
Intercompany loans to subsidiaries
|
|
|
|
|
|
|
|
|
|
|
(2,181
|
)
|
|
|
2,181
|
|
|
|
|
|
Proceeds from intercompany loans with parents and subsidiaries
|
|
|
327
|
|
|
|
|
|
|
|
325
|
|
|
|
(652
|
)
|
|
|
|
|
Capital expenditures
|
|
|
(78
|
)
|
|
|
(22
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
(106
|
)
|
Decrease in restricted cash, net
|
|
|
1
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
45
|
|
Decrease in notes receivable
|
|
|
5
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
107
|
|
Deferred acquisition costs
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
Proceeds from sale of investments
|
|
|
9
|
|
|
|
70
|
|
|
|
|
|
|
|
|
|
|
|
79
|
|
Proceeds on sale of discontinued operations
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
Return of capital from equity method investments and projects
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
300
|
|
|
|
196
|
|
|
|
(469
|
)
|
|
|
131
|
|
|
|
158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Return of capital payments to parent
|
|
|
(1,398
|
)
|
|
|
|
|
|
|
|
|
|
|
1,398
|
|
|
|
|
|
Proceeds from parent intercompany loans
|
|
|
2,181
|
|
|
|
|
|
|
|
|
|
|
|
(2,181
|
)
|
|
|
|
|
Payments for parent intercompany loans
|
|
|
(325
|
)
|
|
|
(327
|
)
|
|
|
|
|
|
|
652
|
|
|
|
|
|
Payments of dividends to preferred stockholders
|
|
|
(704
|
)
|
|
|
(23
|
)
|
|
|
(20
|
)
|
|
|
727
|
|
|
|
(20
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(250
|
)
|
|
|
|
|
|
|
(250
|
)
|
Repayment of minority interest obligations
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
Proceeds from issuance of preferred stock
|
|
|
|
|
|
|
|
|
|
|
246
|
|
|
|
|
|
|
|
246
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
249
|
|
|
|
|
|
|
|
|
|
|
|
249
|
|
Deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(46
|
)
|
|
|
|
|
|
|
(46
|
)
|
Payments for short and long-term debt
|
|
|
(4
|
)
|
|
|
(352
|
)
|
|
|
(649
|
)
|
|
|
|
|
|
|
(1,005
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used by Financing Activities
|
|
|
(250
|
)
|
|
|
(457
|
)
|
|
|
(719
|
)
|
|
|
596
|
|
|
|
(830
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
36
|
|
|
|
1
|
|
|
|
|
|
|
|
37
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in Cash and Cash equivalents
|
|
|
(163
|
)
|
|
|
(117
|
)
|
|
|
(289
|
)
|
|
|
|
|
|
|
(569
|
)
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
156
|
|
|
|
188
|
|
|
|
711
|
|
|
|
|
|
|
|
1,055
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
(7
|
)
|
|
$
|
71
|
|
|
$
|
422
|
|
|
$
|
|
|
|
$
|
486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
214
NRG
ENERGY, INC.
SCHEDULE II.
VALUATION AND QUALIFYING ACCOUNTS
For the
Years Ended December 31, 2007, 2006, and 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions
|
|
|
|
|
|
|
|
|
Balance at
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
|
|
|
Beginning of
|
|
Costs and
|
|
|
Other
|
|
|
|
|
|
Balance at
|
|
|
Period
|
|
Expenses
|
|
|
Accounts
|
|
|
Deductions
|
|
|
End of Period
|
|
|
(In millions)
|
|
Allowance for doubtful accounts, deducted from accounts
receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2007
|
|
$
|
1
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1
|
Year ended December 31, 2006
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
Year ended December 31, 2005
|
|
|
1
|
|
|
2
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
2
|
Income tax valuation allowance, deducted from deferred tax
assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2007
|
|
$
|
581
|
|
$
|
6
|
|
|
$
|
8
|
|
|
$
|
(56
|
)
|
|
$
|
539
|
Year ended December 31, 2006
|
|
|
836
|
|
|
(10
|
)
|
|
|
(81
|
)
|
|
|
(164
|
)
|
|
|
581
|
Year ended December 31, 2005
|
|
|
788
|
|
|
22
|
|
|
|
85
|
|
|
|
(59
|
)
|
|
|
836
|
215
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned
thereunto duly authorized.
NRG Energy, Inc.
(Registrant)
David W. Crane,
Chief Executive Officer
(Principal Executive Officer)
Robert C. Flexon,
Chief Financial Officer
(Principal Financial Officer)
Carolyn J. Burke,
Controller
(Principal Accounting Officer)
Date: February 28, 2008
216
POWER OF
ATTORNEY
Each person whose signature appears below constitutes and
appoints David W. Crane, J. Andrew Murphy, Tanuja M. Dehne and
Brian Curci, each or any of them, such persons true and
lawful attorney-in-fact and agent with full power of
substitution and resubstitution for such person and in such
persons name, place and stead, in any and all capacities,
to sign any and all amendments to this report on
Form 10-K,
and to file the same with all exhibits thereto, and other
documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and
agents, and each of them, full power and authority to do and
perform each and every act and thing necessary or desirable to
be done in and about the premises, as fully to all intents and
purposes as such person, hereby ratifying and confirming all
that said attorneys-in-fact and agents, or any of them or his or
their substitute or substitutes, may lawfully do or cause to be
done by virtue hereof.
In accordance with the Exchange Act, this report has been signed
by the following persons on behalf of the registrant in the
capacities indicated on February 28, 2008.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ David
W. Crane
David
W. Crane
|
|
President, Chief Executive Officer and Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Howard
E. Cosgrove
Howard
E. Cosgrove
|
|
Chairman of the Board
|
|
February 28, 2008
|
|
|
|
|
|
/s/ John
F. Chlebowski
John
F. Chlebowski
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Lawrence
S. Coben
Lawrence
S. Coben
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Stephen
L. Cropper
Stephen
L. Cropper
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ William
E. Hantke
William
E. Hantke
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Paul
W. Hobby
Paul
W. Hobby
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Maureen
Miskovic
Maureen
Miskovic
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Anne
C. Schaumburg
Anne
C. Schaumburg
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Herbert
H. Tate
Herbert
H. Tate
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Thomas
H. Weidemeyer
Thomas
H. Weidemeyer
|
|
Director
|
|
February 28, 2008
|
|
|
|
|
|
/s/ Walter
R. Young
Walter
R. Young
|
|
Director
|
|
February 28, 2008
|
217
EXHIBIT INDEX
|
|
|
|
|
|
2
|
.1
|
|
Third Amended Joint Plan of Reorganization of NRG Energy, Inc.,
NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company
I LLC, and NRGenerating Holdings (No. 23) B.V.(5)
|
|
2
|
.2
|
|
First Amended Joint Plan of Reorganization of NRG Northeast
Generating LLC (and certain of its subsidiaries), NRG South
Central Generating (and certain of its subsidiaries) and
Berrians I Gas Turbine Power LLC.(5)
|
|
2
|
.3
|
|
Acquisition Agreement, dated as of September 30, 2005, by
and among NRG Energy, Inc., Texas Genco LLC and the Direct and
Indirect Owners of Texas Genco LLC.(11)
|
|
3
|
.1
|
|
Amended and Restated Certificate of Incorporation.(16)
|
|
3
|
.2
|
|
Amended and Restated By-Laws.(1)
|
|
3
|
.3
|
|
Certificate of Designation of 4.0% Convertible Perpetual
Preferred Stock, as filed with the Secretary of State of the
State of Delaware on December 20, 2004.(7)
|
|
3
|
.4
|
|
Certificate of Designations of 3.625% Convertible Perpetual
Preferred Stock, as filed with the Secretary of State of the
State of Delaware on August 11, 2005.(17)
|
|
3
|
.5
|
|
Certificate of Designations of 5.75% Mandatory Convertible
Preferred Stock, as filed with the Secretary of State of the
State of Delaware on January 27, 2006.(19)
|
|
3
|
.6
|
|
Certificate of Designations relating to the Series 1
Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance I LLC, as filed with the Secretary of
State of Delaware on August 14, 2006.(27)
|
|
3
|
.7
|
|
Certificate of Designations relating to the Series 1
Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance II LLC, as filed with the
Secretary of State of Delaware on August 14, 2006.(27)
|
|
4
|
.1
|
|
Supplemental Indenture dated as of December 30, 2005, among
NRG Energy, Inc., the subsidiary guarantors named on
Schedule A thereto and Law Debenture Trust Company of
New York, as trustee.(13)
|
|
4
|
.2
|
|
Amended and Restated Common Agreement among XL Capital Assurance
Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law
Debenture Trust Company of New York, as Trustee, The Bank
of New York, as Collateral Agent, NRG Peaker Finance Company LLC
and each Project Company Party thereto dated as of
January 6, 2004, together with Annex A to the Common
Agreement.(2)
|
|
4
|
.3
|
|
Amended and Restated Security Deposit Agreement among NRG Peaker
Finance Company, LLC and each Project Company party thereto, and
the Bank of New York, as Collateral Agent and Depositary Agent,
dated as of January 6, 2004.(2)
|
|
4
|
.4
|
|
NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of
New York, as Collateral Agent, dated as of January 6,
2004.(2)
|
|
4
|
.5
|
|
Indenture dated June 18, 2002, between NRG Peaker Finance
Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun
I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC
and Sterlington Power LLC, as Guarantors, XL Capital Assurance
Inc., as Insurer, and Law Debenture Trust Company, as
Successor Trustee to the Bank of New York.(3)
|
|
4
|
.6
|
|
Registration Rights Agreement, dated December 21, 2004, by
and among NRG Energy, Inc., Citigroup Global Markets Inc. and
Deutsche Bank Securities Inc.(6)
|
|
4
|
.7
|
|
Specimen of Certificate representing common stock of NRG Energy,
Inc.(26)
|
|
4
|
.8
|
|
Indenture, dated February 2, 2006, among NRG Energy, Inc.
and Law Debenture Trust Company of New York.(19)
|
|
4
|
.9
|
|
First Supplemental Indenture, dated February 2, 2006, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(20)
|
|
4
|
.10
|
|
Second Supplemental Indenture, dated February 2, 2006,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2016.(20)
|
|
4
|
.11
|
|
Form of 7.250% Senior Note due 2014.(20)
|
|
4
|
.12
|
|
Form of 7.375% Senior Note due 2016.(20)
|
218
|
|
|
|
|
|
4
|
.13
|
|
Third Supplemental Indenture, dated March 14, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.250% Senior Notes due 2014.(22)
|
|
4
|
.14
|
|
Fourth Supplemental Indenture, dated March 14, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.375% Senior Notes due 2016.(22)
|
|
4
|
.15
|
|
Fifth Supplemental Indenture, dated April 28, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.250% Senior Notes due 2014.(23)
|
|
4
|
.16
|
|
Sixth Supplemental Indenture, dated April 28, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.375% Senior Notes due 2016.(23)
|
|
4
|
.17
|
|
Seventh Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(28)
|
|
4
|
.18
|
|
Eighth Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(28)
|
|
4
|
.19
|
|
Ninth Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2017.(29)
|
|
4
|
.20
|
|
Tenth Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(33)
|
|
4
|
.21
|
|
Eleventh Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(33)
|
|
4
|
.22
|
|
Twelfth Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2017.(33)
|
|
4
|
.23
|
|
Thirteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.250% Senior Notes due 2014.(34)
|
|
4
|
.24
|
|
Fourteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2016.(34)
|
|
4
|
.25
|
|
Fifteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2017.(34)
|
|
4
|
.26
|
|
Form of 7.375% Senior Note due 2017.(29)
|
|
10
|
.1
|
|
Note Agreement, dated August 20, 1993, between NRG Energy,
Inc., Energy Center, Inc. and each of the purchasers named
therein.(4)
|
|
10
|
.2
|
|
Master Shelf and Revolving Credit Agreement, dated
August 20, 1993, between NRG Energy, Inc., Energy Center,
Inc., The Prudential Insurance Registrants of America and each
Prudential Affiliate, which becomes party thereto.(4)
|
|
10
|
.3*
|
|
Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Officers and Key Management.(15)
|
|
10
|
.4*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Directors.(15)
|
|
10
|
.5*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified
Stock Option Agreement.(8)
|
|
10
|
.6*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted
Stock Unit Agreement.(8)
|
|
10
|
.7*
|
|
Form of NRG Energy, Inc. Long Term Incentive Plan Performance
Unit Agreement.(15)
|
219
|
|
|
|
|
|
10
|
.8*
|
|
Annual Incentive Plan for Designated Corporate Officers.(9)
|
|
10
|
.9*
|
|
Letter Agreement, dated February 19, 2004, between NRG
Energy, Inc. and Robert C. Flexon.(8)
|
|
10
|
.10
|
|
Railroad Car Full Service Master Leasing Agreement, dated as of
February 18, 2005, between General Electric Railcar
Services Corporation and NRG Power Marketing Inc.(15)
|
|
11
|
.11
|
|
Commitment Letter, dated February 18, 2005, between General
Electric Railcar Services Corporation and NRG Power Marketing
Inc.(15)
|
|
10
|
.12
|
|
Purchase Agreement (West Coast Power) dated as of
December 27, 2005, by and among NRG Energy, Inc., NRG West
Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14)
|
|
10
|
.13
|
|
Purchase Agreement (Rocky Road Power), dated as of
December 27, 2005, by and among Termo Santander Holding,
L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG
Energy, Inc.(14)
|
|
10
|
.14*
|
|
Letter Agreement, dated June 21, 2005, between NRG Energy,
Inc. and Kevin T. Howell.(18)
|
|
10
|
.15
|
|
Stock Purchase Agreement, dated as of August 10, 2005, by
and between NRG Energy, Inc. and Credit Suisse First Boston
Capital LLC.(17)
|
|
10
|
.16
|
|
Accelerated Share Repurchase Agreement, dated as of
August 11, 2005, by and between NRG Energy, Inc. and Credit
Suisse First Boston Capital LLC.(17)
|
|
10
|
.17
|
|
Investor Rights Agreement, dated as of February 2, 2006, by
and among NRG Energy, Inc. and Certain Stockholders of NRG
Energy, Inc. set forth therein.(21)
|
|
10
|
.18
|
|
Terms and Conditions of Sale, dated as of October 5, 2005,
between Texas Genco II LP and Freight Car America, Inc.,
(including the Proposal Letter and Amendment thereto)
(portions of this document have been omitted pursuant to a
request for confidential treatment and filed separately with the
SEC).(25)
|
|
10
|
.19*
|
|
Employment Agreement, dated March 3, 2006, between NRG
Energy, Inc. and David Crane.(25)
|
|
10
|
.20*
|
|
CEO and CFO Compensation Table.(30)
|
|
10
|
.21*
|
|
NRG Energy, Inc. Director Compensation Table.(24)
|
|
10
|
.22
|
|
Limited Liability Company Agreement of NRG Common Stock Finance
I LLC.(27)
|
|
10
|
.23
|
|
Limited Liability Company Agreement of NRG Common Stock
Finance II LLC.(27)
|
|
10
|
.24
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG
Common Stock Finance I LLC, Credit Suisse International and
Credit Suisse Securities (USA) LLC.(27)
|
|
10
|
.25
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG
Common Stock Finance II LLC, Credit Suisse International
and Credit Suisse Securities (USA) LLC, as agent.(27)
|
|
10
|
.26
|
|
Preferred Interest Purchase Agreement, dated August 4,
2006, between NRG Common Stock Finance I LLC, Credit Suisse
Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27)
|
|
10
|
.27
|
|
Preferred Interest Purchase Agreement, dated August 4,
2006, between NRG Common Stock Finance II LLC, Credit
Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as
agent.(27)
|
|
10
|
.28
|
|
Common Interest Purchase Agreement, dated August 4, 2006,
between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(27)
|
|
10
|
.29
|
|
Common Interest Purchase Agreement, dated August 4, 2006,
between NRG Energy, Inc. and NRG Common Stock Finance II
LLC.(27)
|
|
10
|
.30
|
|
Second Amended and Restated Credit Agreement, dated June 8,
2007, by and among NRG Energy, Inc., the lenders party thereto,
Citigroup Global Markets Inc., Credit Suisse Securities (USA)
LLC, Citicorp North America Inc. and Credit Suisse.(32)
|
|
10
|
.31
|
|
Credit Agreement dated June 8, 2007 by and among NRG
Holdings, Inc., the lenders party thereto, Credit Suisse
Securities (USA) LLC, Credit Suisse and Citigroup Global Markets
Inc.(32)
|
|
10
|
.32*
|
|
Amended and Restated Long-Term Incentive Plan, dated
December 8, 2006.(31)
|
|
10
|
.33*
|
|
Named Executive Officer Compensation.(1)
|
|
10
|
.34*
|
|
NRG Energy, Inc. Executive and Key Management
Change-in-Control
and General Severance Agreement, dated May 24, 2006.(31)
|
|
12
|
.1
|
|
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed
Charges.(1)
|
|
12
|
.2
|
|
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed
Charges and Preferred Stock Dividend Requirements.(1)
|
220
|
|
|
|
|
|
21
|
|
|
Subsidiaries of NRG Energy. Inc.(1)
|
|
23
|
.1
|
|
Consent of KPMG LLP.(1)
|
|
31
|
.1
|
|
Rule 13a-14(a)/15d-14(a)
certification of David W. Crane.(1)
|
|
31
|
.2
|
|
Rule 13a-14(a)/15d-14(a)
certification of Robert C. Flexon.(1)
|
|
31
|
.3
|
|
Rule 13a-14(a)/15d-14(a)
certification of Carolyn J. Burke.(1)
|
|
32
|
|
|
Section 1350 Certification.(1)
|
|
|
|
* |
|
Exhibit relates to compensation arrangements. |
|
(1) |
|
Filed herewith. |
|
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 16, 2004. |
|
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 31, 2003. |
|
(4) |
|
Incorporated herein by reference to NRG Energy Inc.s
Registration Statement on
Form S-1,
as amended, Registration
No. 333-33397. |
|
(5) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 19, 2003. |
|
(6) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 27, 2004. |
|
(7) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 27, 2004. |
|
(8) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended September 30, 2004. |
|
(9) |
|
Incorporated herein by reference to NRG Energy, Inc.s 2004
proxy statement on Schedule 14A filed on July 12, 2004. |
|
(10) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended March 31, 2004. |
|
(11) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on October 3, 2005. |
|
(12) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended June 30, 2005. |
|
(13) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on January 4, 2006. |
|
(14) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 28, 2005. |
|
(15) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 30, 2005. |
|
(16) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 24, 2005. |
|
(17) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 11, 2005. |
|
(18) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 3, 2005. |
|
(19) |
|
Incorporated herein by reference to NRG Energy, Inc.s
Form 8-A
filed on January 27, 2006. |
|
(20) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on February 6, 2006. |
|
(21) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on February 8, 2006. |
|
(22) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on March 16, 2006. |
|
(23) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 3, 2006. |
|
(24) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 4, 2006. |
|
(25) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 7, 2006. |
|
(26) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on August 4, 2006. |
|
(27) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 10, 2006. |
|
(28) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 14, 2006. |
221
|
|
|
(29) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 27, 2006. |
|
(30) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 26, 2007. |
|
(31) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on May 2, 2007. |
|
(32) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on June 13, 2007. |
|
(33) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on July 20, 2007. |
|
(34) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on September 4, 2007. |
222