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, 2008.
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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
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08540
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(Address of principal executive
offices)
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(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
5.75% Mandatory Convertible Preferred Stock
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New York Stock Exchange
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 Rule
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
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Smaller
reporting
company o
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(Do not check if a smaller reporting company)
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
$10,001,849,139 based on the closing sale price of $42.90 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 9, 2009
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Common Stock, par value $0.01 per share
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236,232,031
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Documents Incorporated by Reference:
Portions of the Proxy Statement for the 2009 Annual Meeting
of Stockholders
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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AB32 |
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Assembly Bill 32 California Global Warming Solutions
Act of 2006 |
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ABWR |
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Advanced Boiling Water Reactor |
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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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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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APB 23 |
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APB Opinion No. 23, Accounting for Income
Taxes-Special Areas |
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ARO |
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Asset Retirement Obligation |
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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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BP |
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BP Wind Energy North America Inc. |
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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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CAGR |
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Compound annual growth rate |
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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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Capital Allocation Plan |
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Share repurchase program |
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Capital Allocation Program |
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NRGs plan of allocating capital between debt reduction,
reinvestment in the business, and share repurchases through the
Capital Allocation Plan. |
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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 of 1980 |
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CL&P |
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The Connecticut Light & Power Company |
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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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CS |
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Credit Suisse Group |
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CSF I |
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NRG Common Stock Finance I LLC |
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CSF II |
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NRG Common Stock Finance II LLC |
2
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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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Annual Equivalent Availability Factor, which 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 |
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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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EITF 04-6 |
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EITF Issue
No. 04-6,
Accounting for Stripping Costs Incurred during
Production in the Mining Industry |
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EITF 07-5 |
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EITF
No. 07-5,
Determining Whether an Instrument (or Embedded Feature)
Is Indexed to an Entitys Own Stock |
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EITF 08-5 |
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EITF 08-5,
Issuers Accounting for Liabilities Measured at
Fair Value with a Third-Party Credit Enhancement |
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EITF 08-6 |
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EITF 08-6,
Equity Method Investment Accounting
Considerations |
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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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ESPP |
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Employee Stock Purchase Plan |
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EWG |
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Exempt Wholesale Generator |
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Exchange Act |
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The Securities Exchange Act of 1934, as amended |
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Expected Baseload Generation |
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The net baseload generation 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 |
3
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FIN 46R |
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FIN No. 46(R), Consolidation of Variable
Interest Entities |
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FIN 47 |
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FIN No. 47, Accounting for Conditional Asset
Retirement Obligations |
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FIN 48 |
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FIN No. 48, Accounting for Uncertainty in
Income Taxes |
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FPA |
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Federal Power Act |
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Fresh Start |
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Reporting requirements as defined by
SOP 90-7 |
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FSP |
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FASB Staff Position |
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FSP APB 14-1 |
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FSP No. APB
14-1,
Accounting for Convertible Debt Instruments That May Be
Settled in Cash upon Conversion (Including Partial Cash
Settlement) |
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FSP
FIN 39-1 |
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FSP
No. FIN 39-1,
Amendment of Financial Interpretation
No. 39 |
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FSP
FAS 132R-1 |
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FSP No. FAS 132(R)-1 Employers
Disclosures about Postretirement Benefit Plan Assets |
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FSP
FAS 133-1
and
FIN 45-4 |
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FSP
No. FAS 133-1
and
FIN No. 45-4,
Disclosures about Credit Derivatives and Certain
Guarantees: An Amendment of FASB Statement No. 133 and
Financial Interpretation Number 45; and Clarification of the
Effective Date of FASB Statement No. 161 |
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FSP
FAS 140-4
and FIN 46(R)-8 |
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FSP
No. FAS 140-4
and FIN 46(R)-8, Disclosures by Public Entities
(Enterprises) about Transfers of Financial assets and Interests
in Variable Interest Entities |
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FSP
FAS 142-3 |
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FSP
No. FAS 142-3,
Determination of the Useful Life of Intangible
Asset |
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FSP
FAS 157-3 |
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FSP
No. FAS 157-3,
Determining the Fair Value of a Financial Asset When
the Market for That Asset Is Not Active |
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GHG |
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Greenhouse Gases |
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Gross Generation |
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The total amount of electric energy produced by generating units
and measured at the generating terminal in kWhs or
MWhs |
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Heat Rate |
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A measure of thermal efficiency computed by dividing the total
BTU content of the fuel burned by the resulting kWhs
generated. Heat rates can be expressed as either gross or net
heat rates, depending whether the electricity output measured is
gross or net generation and is generally expressed as BTU per
net kWh |
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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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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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kV |
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Kilovolts |
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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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LTIP |
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Long-Term Incentive Plan |
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MADEP |
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Massachusetts Department of Environmental Protection |
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MACT |
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Maximum Achievable Control Technology |
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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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MOU |
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Memorandum of Understanding |
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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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MWt |
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Megawatts Thermal |
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NAAQS |
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National Ambient Air Quality Standards |
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NEPOOL |
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New England Power Pool |
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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, 2008 |
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Net Capacity Factor |
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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. |
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Net Exposure |
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Counterparty credit exposure to NRG, net of collateral |
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Net Generation |
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The net amount of electricity produced, expressed in kWhs
or MWhs, that is the total amount of electricity generated
(gross) minus the amount of electricity used during generation. |
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New York Rest of State |
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New York State excluding New York City |
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NINA |
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Nuclear Innovation North America LLC |
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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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NPNS |
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Normal Purchase Normal Sale |
5
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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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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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Padoma |
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Padoma Wind Power LLC |
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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 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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PPM |
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Parts per Million |
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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 of 2005 |
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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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Revolving Credit Facility |
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NRGs $1 billion senior secured credit facility which
matures on February 2, 2011 |
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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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RPM |
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Reliability Pricing Model term for capacity market
in PJM market |
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RTO |
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Regional Transmission Organization, also referred to as an
Independent System Operators, or ISO |
6
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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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Securities Act |
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The Securities Act of 1933, as amended |
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Senior Credit Facility |
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NRGs senior secured facility, which is comprised of a Term
Loan Facility and a $1.3 billion Synthetic Letter of Credit
Facility which matures on February 1, 2013, and a
$1 billion Revolving Credit Facility, which matures on
February 2, 2011. |
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Senior Notes |
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The Companys $4.7 billion outstanding unsecured
senior notes consisting of $1.2 billion of
7.25% senior notes due 2014, $2.4 billion of
7.375% senior notes due 2016 and $1.1 billion of
7.375% senior notes due 2017 |
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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 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 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 141 |
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SFAS No. 141, Business Combinations |
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SFAS 141R |
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SFAS No. 141 (revised 2007), Business
Combinations |
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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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SFAS 159 |
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SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities including
an amendment of FASB Statement No. 115 |
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SFAS 160 |
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SFAS No. 160, Noncontrolling Interest in
Consolidated Financial Statements |
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SFAS 161 |
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SFAS No. 161, Disclosure about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133 |
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Sherbino |
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Sherbino I Wind Farm LLC |
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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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Synthetic Letter of Credit Facility |
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NRGs $1.3 billion senior secured synthetic letter of
credit facility which matures on February 1, 2013 |
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TCEQ |
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Texas Commission on Environmental Quality |
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Term Loan Facility |
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A senior first priority secured term loan which matures on
February 1, 2013, and is included as part of NRGs
Senior Credit Facility. |
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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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Tosli |
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Tosli Acquisition B.V. |
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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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US 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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WCP |
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WCP (Generation) Holdings, Inc. |
8
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 regional markets in the US
and select international markets where its generating assets are
located.
As of December 31, 2008, NRG had a total global portfolio
of 189 active operating fossil fuel and nuclear generation
units, at 48 power generation plants, with an aggregate
generation capacity of approximately 24,005 MW, and
approximately 550 MW under construction which includes
partners interests of 275 MW. In addition, NRG has
ownership interests in two wind farms representing an aggregate
generation capacity of 270 MW, which includes partner
interests of 75 MW. Within the US, NRG has one of the
largest and most diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 22,925 MW of fossil fuel and nuclear
generation capacity in 177 active generating units at 43 plants
and ownership interests in two wind farms representing
195 MW of wind generation capacity. These power generation
facilities are primarily located in Texas (approximately
11,010 MW, including the 195 MW from the two wind
farms), the Northeast (approximately 7,020 MW), South
Central (approximately 2,845 MW), and West (approximately
2,130 MW) regions of the US, and 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, nuclear and wind facilities,
representing approximately 45%, 33%, 16%, 5% and 1% 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
intermittent, 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
Business Strategy
NRGs business strategy is designed to enhance the
Companys position as a leading wholesale power generation
company in the US. NRG will continue to utilize its asset base
as a platform for growth and development and as a source of cash
flow generation which can be used for the return of capital to
debt and equity holders. The Companys strategy is focused
on: (i) top decile operating performance of its existing
operating assets and enhanced operating performance of the
Companys commercial operations and hedging program;
(ii) repowering of power generation assets at existing
sites and development of new power generation projects; and
(iii) investment in energy-related new businesses and new
technologies where such investments create low to no carbon.
This strategy is supported by the Companys five major
initiatives (FORNRG, RepoweringNRG, econrg, Future
NRG and NRG Global Giving) which are designed to enhance the
Companys competitive advantages in these strategic areas
and allow the Company to surmount the challenges faced by the
power industry in the coming years. This strategy is being
implemented by focusing on the following principles:
9
Operational Performance The
Company is focused on increasing value from its existing assets.
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. FORNRG is a companywide effort designed to increase
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, monetize or reduce excess working capital and other
assets. The FORNRG accomplishments include both recurring
and one-time improvements measured from a prior base year. For
plant operations, the program measures cumulative current year
benefits using current gross margins multiplied by 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.
In addition to the FORNRG initiative, the Company seeks
to maximize profitability and manage cash flow volatility
through the Companys commercial operations strategy. The
Company 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.
Finally, 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 during business downturns,
including a regular return of capital to its shareholders. NRG
will continue to focus on maintaining operational and financial
controls designed to ensure that the Companys financial
position remains strong.
Development 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.
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 capacity that is expected to be supported by
long-term hedging programs, including Power Purchase Agreements,
or PPAs, 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
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.
New Businesses and New
Technology NRG is focused on the
development and investment in energy-related new businesses and
new technologies where the benefits of such investments
represent significant commercial opportunities and create a
comparative advantage for the Company, including low or no GHG
emitting energy generating sources, such as nuclear, wind, solar
thermal, photovoltaic, clean coal and gas, and
the employment of post-combustion carbon capture technologies.
In 2008, the Company began to increase its focus on ways to
invest in or support the development of new energy-related
businesses and technologies that could advance its multi-fuel,
multi-technology growth strategy and look for new ways to reduce
carbon emissions from its overall fleet, and we expect to
continue to do so in the future. Furthermore, the Company
intends to capitalize on the high growth opportunities presented
by government-mandated renewable portfolio standards, tax
incentives and loan
10
guaranties for renewable energy projects and new technologies
and expected future carbon regulation. A primary focus of this
strategy is supported by the econrg initiative whereby
NRG is 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. econrg represents NRGs
commitment to environmentally responsible power generation by
addressing the challenges of climate change, clean air and
water, and conservation of our natural resources while taking
advantage of business opportunities that may inure to NRG as a
result of our demonstration and deployment of green
technologies. Within NRG, econrg builds upon a 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 the
Companys employees.
Company-Wide Initiatives In
addition, the Companys overall strategy is also supported
by Future NRG and NRG Global Giving initiatives.
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,
training, development, staffing and recruiting needs. Included
under the Future NRG umbrella is NRG University, which provides
leadership, managerial, supervisory and technical training
programs and individual skill development courses. NRG Global
Giving is designed to enhance respect for the community, which
is one of NRGs core values. Our Global Giving Program
invests NRGs resources to strengthen the communities where
we do business and seeks to make community investments in four
focus areas: community and economic development, education,
environment and human welfare.
Finally, 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 US, with approximately 22,925 MW of fossil fuel and
nuclear generation capacity in 177 active generating units at 43
plants and ownership interests in two wind farms representing
195 MW of wind generation capacity, as of December 31,
2008. 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 US baseload facilities, which consist of
approximately 8,715 MW of generation capacity measured as
of December 31, 2008, provide the Company with a
significant source of stable cash flow, while its intermediate
and peaking facilities, with approximately 14,210 MW of
generation capacity as of December 31, 2008, 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. In 2008, NRG completed the construction of the
Sherbino (150 MW including partners interests of
75 MW) and Elbow Creek (120 MW) wind farms which
provide electricity to the Companys core region.
11
The following chart demonstrates the diversification of
NRGs domestic power generation assets as of
December 31, 2008:
Reliability of future cash flows NRG has
hedged a significant portion of its expected baseload generation
capacity with decreasing hedged levels through 2014. NRG also
has cooperative load contract obligations in South Central
region which expire over various dates through 2026. The Company
has the capacity and intent to enter into additional hedges when
market conditions are favorable. In addition, as of
December 31, 2008, the Company had purchased fuel forward
under fixed price contracts, with contractually-specified price
escalators, for approximately 51% of its expected baseload coal
generation output from 2009 to 2014. 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 2008, approximately 91% 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 the Electric Reliability Council of
Texas, or ERCOT, to generate power majority 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,
which experience from
time-to-time
and to varying degrees of 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. Also, these facilities are
often ideally situated for repowering or the addition of new
capacity, because their location and existing infrastructure
give them significant advantages over developed sites in their
regions that do not have process infrastructure.
12
Performance
Metrics
The following table contains a summary of NRGs operating
revenues by segment for the year ended December 31, 2008 as
discussed in Item 15 Note 17, Segment
Reporting, to the Consolidated Financial Statements.
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
Energy
|
|
|
Capacity
|
|
|
Management
|
|
|
Contract
|
|
|
Thermal
|
|
|
Other
|
|
|
Operating
|
|
Region
|
|
Revenues
|
|
|
Revenues
|
|
|
Activities
|
|
|
Amortization
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
|
(In millions)
|
|
|
Texas
|
|
$
|
2,870
|
|
|
$
|
493
|
|
|
$
|
318
|
|
|
$
|
255
|
|
|
$
|
|
|
|
$
|
90
|
|
|
$
|
4,026
|
|
Northeast
|
|
|
1,064
|
|
|
|
415
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
66
|
|
|
|
1,630
|
|
South Central
|
|
|
478
|
|
|
|
233
|
|
|
|
10
|
|
|
|
23
|
|
|
|
|
|
|
|
2
|
|
|
|
746
|
|
West
|
|
|
39
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
171
|
|
International
|
|
|
56
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
158
|
|
Thermal
|
|
|
12
|
|
|
|
7
|
|
|
|
5
|
|
|
|
|
|
|
|
114
|
|
|
|
16
|
|
|
|
154
|
|
Corporate and Eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,519
|
|
|
$
|
1,359
|
|
|
$
|
418
|
|
|
$
|
278
|
|
|
$
|
114
|
|
|
$
|
197
|
|
|
$
|
6,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, or NERC, 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 The gross heat rate for the
Companys fossil-fired power plants represents the average
amount of fuel in a BTU required to generate one kWh of
electricity divided 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.
13
The tables below present the North American power generation
performance metrics for the Companys power plants
discussed above for the years ended December 31, 2008 and
2007:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
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(a)
|
|
|
11,010
|
|
|
|
46,937
|
|
|
|
88.1
|
%
|
|
|
10,300
|
|
|
|
49.6
|
%
|
Northeast(b)
|
|
|
7,020
|
|
|
|
13,349
|
|
|
|
88.8
|
|
|
|
10,800
|
|
|
|
19.9
|
|
South Central
|
|
|
2,845
|
|
|
|
11,148
|
|
|
|
93.4
|
|
|
|
10,300
|
|
|
|
47.6
|
|
West
|
|
|
2,130
|
|
|
|
1,532
|
|
|
|
91.5
|
%
|
|
|
11,800
|
|
|
|
10.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
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|
|
|
|
|
|
|
|
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(b)
|
|
|
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
|
%
|
|
|
|
(a)
|
|
Net generation (MWh) does not
include Sherbino, which is accounted for under the equity method.
|
|
(b)
|
|
Factor data and heat rate do not
include the Keystone and Conemaugh facilities.
|
Employees
As of December 31, 2008, NRG had 3,526 employees,
approximately 1,663 of whom were covered by US bargaining
agreements. During 2008, the Company did not experience any
labor stoppages or labor disputes at any of its facilities.
14
Generation
Asset Overview
NRG has a significant power generation presence in major
competitive power markets of the US 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, 2008.
|
As of December 31, 2008, the Companys power
generation assets consisted of approximately 10,495 MW of
gas-fired; 7,540 MW of coal-fired; 3,715 MW of
oil-fired; 1,175 MW of nuclear; and 195 MW of wind
generating capacity in the US. In addition, NRG also owns
approximately 115 MW of thermal capacity domestically as
well as 1,080 MW of power generation capacity overseas. The
Companys US power generation portfolio by dispatch level
is comprised of approximately 38% baseload, 36% intermediate,
25% peaking and 1% intermittent units.
The following is a discussion of NRGs generation assets by
segment for the year ended December 31, 2008.
Texas Region As of December 31,
2008, NRGs generation assets in the Texas region consisted
of approximately 5,340 MW of baseload generation assets,
approximately 195 MW of intermittent wind generation
assets, excluding partner interests of 75 MW, in addition
to approximately 5,475 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 use lignite and coal, and an undivided 44%
interest in two nuclear generating units at South Texas Project,
or STP. In 2008, NRG announced the completion of the
construction of two wind farms, Sherbino Wind Farm and Elbow
Creek Wind Farm, which are also located in the ERCOT market.
Power plants are generally dispatched in order of lowest
operating cost and as of May 2008 approximately 64% of the net
generation capacity in the ERCOT market was natural gas-fired.
In the current natural gas price environment, NRGs three
solid fuel baseload facilities and two wind farms have
significantly lower operating costs than gas plants. NRG expects
these three solid-fuel facilities to operate the majority of the
time when available, subject to planned and forced outages.
15
Northeast Region As of
December 31, 2008, NRG generation assets in the Northeast
region of the US consisted of approximately 7,020 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
575 MW of southwest Connecticut generation capacity. As of
December 31, 2008, NRGs generation assets in the
Northeast region consisted of approximately 1,870 MW of
baseload generation assets and approximately 5,150 MW of
intermediate and peaking assets.
South Central Region As of
December 31, 2008, NRG generation assets in the South
Central region of the US consisted of approximately
2,845 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 Louisiana consist of its primary asset, Big
Cajun II, a coal-fired plant located near Baton Rouge, Louisiana
which has approximately 1,490 MW of baseload capacity and
905 MW of intermediate and peaking assets. A significant
portion of the regions generation capacity has been sold
to eleven cooperatives within the region through 2026. From time
to time, the Company may contract for intermediate generation
capacity to support its load obligations. In addition, the
region also operates 450 MW of peaking generation in
Rockford, Illinois under the PJM region.
West Region As of December 31,
2008, NRG generation assets in the West region of the US
consisted of approximately 2,130 MW of generation capacity,
primarily located in the California Independent System Operator,
or CAISO, control area. The Companys generation assets in
the West region are predominately intermediate and peaking duty
natural gas-fired plants located in southern California. In
addition, the region owns 50% interest in a 90 MW baseload,
gas-fired plant located in Nevada.
International Region As of
December 31, 2008, NRG had net ownership in approximately
1,080 MW of power generating capacity in Australia and
Germany. In addition to traditional power generation facilities,
NRG also owns equity interests in certain coal mines in Germany.
Thermal NRG owns thermal and chilled
water businesses that generate approximately 1,020 MW
thermal equivalents. In addition, NRGs thermal segment
owns certain power plants with approximately 115 MW of
power generating capacity located in Delaware and 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 PPAs
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, NRG uses hedging
strategies which may include power and natural gas forward sales
contracts to manage the commodity price risk primarily
associated with the Companys base load generation assets.
The objective of these hedging strategies is to stabilize the
cash flow generated by NRGs portfolio of assets.
16
The following table summarizes NRGs US baseload capacity
and the corresponding revenues and average natural gas prices
resulting from baseload hedge agreements extending beyond
December 31, 2008 and through 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average for
|
|
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
2009-2014
|
|
|
|
(Dollars in millions unless otherwise stated)
|
|
|
Net Baseload Capacity (MW)
|
|
|
8,701
|
|
|
|
8,539
|
|
|
|
8,459
|
|
|
|
8,432
|
|
|
|
8,432
|
|
|
|
8,432
|
|
|
|
8,499
|
|
Forecasted Baseload Capacity (MW)
|
|
|
7,497
|
|
|
|
7,229
|
|
|
|
7,164
|
|
|
|
7,232
|
|
|
|
7,324
|
|
|
|
7,395
|
|
|
|
7,307
|
|
Total Baseload Sales
(MW)(a)
|
|
|
7,156
|
|
|
|
5,686
|
|
|
|
4,825
|
|
|
|
3,272
|
|
|
|
1,988
|
|
|
|
789
|
|
|
|
3,953
|
|
Percentage Baseload Capacity Sold
Forward(b)
|
|
|
95
|
%
|
|
|
79
|
%
|
|
|
67
|
%
|
|
|
45
|
%
|
|
|
27
|
%
|
|
|
11
|
%
|
|
|
54
|
%
|
Total Forward Hedged
Revenues(c)(d)
|
|
$
|
3,851
|
|
|
$
|
2,905
|
|
|
$
|
2,200
|
|
|
$
|
1,670
|
|
|
$
|
958
|
|
|
$
|
368
|
|
|
$
|
1,992
|
|
Weighted Average Hedged Price ($ per
MWh)(c)
|
|
$
|
61
|
|
|
$
|
58
|
|
|
$
|
52
|
|
|
$
|
58
|
|
|
$
|
55
|
|
|
$
|
53
|
|
|
$
|
58
|
|
Weighted Average Hedged Price ($ per MWh) excluding South
Central
region(d)
|
|
$
|
65
|
|
|
$
|
62
|
|
|
$
|
54
|
|
|
$
|
65
|
|
|
$
|
66
|
|
|
$
|
|
|
|
$
|
62
|
|
Average Equivalent Natural Gas Price ($ per MMBtu)
|
|
$
|
8.06
|
|
|
$
|
7.92
|
|
|
$
|
7.09
|
|
|
$
|
7.85
|
|
|
$
|
7.43
|
|
|
$
|
7.24
|
|
|
$
|
7.72
|
|
Average Equivalent Natural Gas Price ($ per MMBtu) excluding
South Central region
|
|
$
|
8.37
|
|
|
$
|
8.16
|
|
|
$
|
7.27
|
|
|
$
|
8.60
|
|
|
$
|
8.86
|
|
|
$
|
|
|
|
$
|
8.13
|
|
|
|
|
(a)
|
|
Includes amounts under power sales
contracts and natural gas hedges. The forward natural gas
quantities are reflected in equivalent MWh based on forward
market implied heat rate as of December 31, 2008 and then
combined with power sales to arrive at equivalent MWh hedged
which is then divided by 8,760 hours (8,784 hours in
2012) 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 energy revenue and demand charge.
|
|
(d)
|
|
The South Central regions
weighted average hedged prices ranges from $43/MWh
$53/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.
|
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. The
preceding factors 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, 2008, NRG had
purchased forward contracts to provide fuel for approximately
51% of the Companys requirements from 2009 through 2014.
NRG arranges for the purchase, transportation and delivery of
coal for the Companys baseload coal plants via a variety
of coal purchase agreements, rail/barge transportation
agreements and rail car lease arrangements. The Company
purchased approximately 35 million tons of coal in 2008, of
which 94% is Power River Basin coal and lignite. The Company is
one of the largest coal purchasers in the US.
17
The following table shows the percentage of the Companys
coal and lignite requirements from 2009 through 2014 that have
been purchased forward:
|
|
|
|
|
|
|
Percentage of
|
|
|
|
Companys
|
|
|
|
Requirement(a)
|
|
|
2009
|
|
|
104
|
%
|
2010
|
|
|
69
|
%
|
2011
|
|
|
55
|
%
|
2012
|
|
|
47
|
%
|
2013
|
|
|
18
|
%
|
2014
|
|
|
12
|
%
|
|
|
|
(a)
|
|
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, 2008, NRG had approximately 6,349
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 up to
the next ten years.
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
for 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 thereafter. 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 October, when demand for
electricity is at its 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 delivered fuel prices
have tended to drive seasonal electricity prices. The preceding
factors 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.
18
To support RepoweringNRG environmental capital
expenditures and all major capital expenditure projects
initiatives, the Company organized its project execution process
into one centralized group consisting of Engineering,
Procurement and Construction, or EPC. This group combines
regional engineering functions with development project
engineering, project management, procurement and construction
functions to provide a consistent approach to the major capital
projects. 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 achieves
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.
FORNRG
Update
In 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 to
2008. Improvements in reliability throughout the baseload fleet
were the drivers of the year-to-date program performance. In
2008, the Company achieved $259 million of implemented
FORNRG 1.0 improvements which exceeded the established
$250 million goal. The FORNRG 1.0 program was
measured from a 2004 baseline, with the exception of the Texas
region where benefits were measured using 2005 as the base year.
Beginning in January 2009, the Company transitioned to
FORNRG 2.0 to target an incremental 100 basis point
improvement to the Companys ROIC by 2012. The initial
targets for FORNRG 2.0 were based upon improvements in
the Companys ROIC as measured by increased cash flow. The
economic goals of FORNRG 2.0 will focus on:
(i) revenue enhancement, (ii) cost savings, and
(iii) asset optimization, including reducing excess working
capital and other assets. The FORNRG 2.0 program will
measure its progress towards the FORNRG 2.0 goals by
using the Companys 2008 financial results as a baseline,
while plant performance calculations will be based upon the
average full-year plant key performance indicators for years the
2006-2008.
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2009
through 2013 to meet NRGs environmental commitments will
be approximately $1.2 billion. These capital expenditures,
in general, are related to installation of particulate,
SO2,
NOx,
and mercury controls to comply with federal and state air
quality rules and consent orders, 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. While this
estimate reflects schedules and controls to meet anticipated
reduction requirements, the full impact on the scope and timing
of environmental retrofits cannot be determined until issuance
of final rules by the United States Environmental Protection
Agency, or USEPA.
The following table summarizes the estimated environmental
capital expenditures for the referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2009
|
|
$
|
|
|
|
$
|
256
|
|
|
$
|
|
|
|
$
|
256
|
|
2010
|
|
|
8
|
|
|
|
213
|
|
|
|
57
|
|
|
|
278
|
|
2011
|
|
|
17
|
|
|
|
175
|
|
|
|
116
|
|
|
|
308
|
|
2012
|
|
|
29
|
|
|
|
67
|
|
|
|
114
|
|
|
|
210
|
|
2013
|
|
|
21
|
|
|
|
3
|
|
|
|
74
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
75
|
|
|
$
|
714
|
|
|
$
|
361
|
|
|
$
|
1,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
19
Carbon
Update
There is a marked shift towards federal action to address
climate change under the Obama administration, which has made
clear its intention to make climate change policy a priority for
the US through legislation, regulation, and global leadership.
President Obama reiterated this commitment in his inaugural
address. Congressman Waxman, who sees aggressive action on
climate change as a major priority, was elected chair of the
House Energy and Commerce Committee and announced that a climate
change bill would be delivered out of committee before Memorial
Day.
The fossil-fuel based electric generators contribute to GHG
emissions. In 2008, in the course of producing approximately
80 million MWh of electricity, NRGs power plants
emitted approximately 68 million tonnes
of CO2,
of which approximately 61 million tonnes were emitted in
the US, approximately 4 million tonnes in Germany, and
approximately 3 million tonnes in Australia.
The Company has a multifold strategy with respect to climate
change and related GHG regulation. First, the Company is seeking
to shape 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 effectively support the development, demonstration
and deployment of low and no
CO2
power generation technologies, and that it sets out a
transitional allocation approach that buffers initial net
compliance costs while transitioning to a full auction. The
Company is carrying out its efforts to influence public policy
on its own and as part of various collective efforts. For
example in January 2009, NRG joined with other members of the
United States Climate Action Partnership, or USCAP, to issue the
Blueprint for Legislative Action, a detailed
framework for legislation to slow, stop and reverse the growth
of GHG emissions to achieve an 80% reduction from 2005 levels by
2050.
Second, the Company is actively pursuing investments in new
generating facilities and technologies that will be highly
efficient and will employ technologies to minimize
CO2
emissions and other air emissions through its
RepoweringNRG program. The Company anticipates that these
investments will result in significant 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
STP units 3 and 4 nuclear project in Texas. NRG has formed
Nuclear Innovation North America, or NINA, a joint venture with
the Toshiba American Nuclear Energy Corporation, to facilitate
the development of STP 3 and 4 as well as additional nuclear
projects. Further, in 2008, NRGs subsidiary, Padoma Wind
Power, LLC, or Padoma, brought 270 MW of wind generating
capacity on-line in west Texas at two facilities: (i) the
150 MW Sherbino I Wind Farm LLC, or Sherbino, a 50/50 joint
venture with a subsidiary of BP Alternative Energy North America
Inc., or BP, and (ii) the wholly-owned, 120 MW Elbow
Creek Wind Power LLC facility. The Company is actively
developing low and no GHG emitting wind, solar, biomass and
natural gas projects. The extent to which these projects, and
the remaining coal projects under development, impact the
Companys overall climate change exposure will depend on
the Companys 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 climate
change risk associated with our development projects is
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
CO2
capture technologies. NRG is exploring a variety of
technologies, including one or more scaled up demonstrations at
a Company facility in Texas. The captured
CO2
would be sequestered through use for enhanced oil recovery or
otherwise in suitable geological formations.
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, including managing a
portfolio of GHG offsets and
CO2
allowances. For example, the Company is a member of the Chicago
Climate Exchange, a
CO2
emissions reduction, registry and trading system, and has been
active in both RGGI auctions to date.
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 climate change regulations. As a result, all
decisions with respect to acquisitions, repowerings, project
development and further investment in
20
our existing facilities will be made on the assumption that
there will be a cost associated with GHG emissions in the future.
Nuclear
Innovation North America
In March 2008, NRG formed NINA, an NRG subsidiary focused on
marketing, siting, developing, financing and investing in new
advanced design nuclear projects in select markets across North
America, including the planned STP units 3 and 4 that NRG is
developing on a 50/50 basis with City of San Antonios
agent City Public Service Board of San Antonio, or CPS
Energy, at the STP nuclear power station site. NRGs rights
to develop STP units 3 and 4 have been contributed to special
purpose subsidiaries of NINA. NINA will focus only on the
development of new projects and will not be involved in the
operations of the existing STP units 1 and 2.
Toshiba American Nuclear Energy Corporation, or TANE, a wholly
owned subsidiary of Toshiba Corporation, will serve as the prime
contractor on NINAs projects and is a minority shareholder
with NRG in the NINA venture. TANE is currently prime contractor
of the STP units 3 and 4 project and is providing licensing
support and leading all engineering and scheduling activities,
which ultimately will lead to responsibility for constructing
the project. TANE received a 12% equity ownership in NINA in
exchange for $300 million invested in NINA in six annual
installments of $50 million, the first of which was
received in 2008 and the last three of which are subject to
certain conditions. Half of this investment will be to fund
development activities related to STP units 3 and 4. The other
half will be targeted towards developing and deploying
additional Advanced Boiling Water Reactor, or ABWR, projects in
North America with other potential partners. TANE is also
extending pre-negotiated EPC terms to NINA for two additional
two-unit
nuclear projects similar to the terms being offered for the STP
unit 3 and 4 development.
NINA intends to use the Nuclear Regulatory Commission, or NRC,
certified ABWR design, with only a limited number of changes to
enhance safety and construction schedules. On November 30,
2007, the 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. On September 30, 2008, NINA
filed a revision to the COLA to list Toshiba as the primary
vendor. NINA received the combined license review schedule from
the NRC on February 11, 2009. Issuing the schedule marks
the continuation of NRCs review of the STP expansion
application as amended on September 2008. The Company expects to
achieve commercial operation for Unit 3 in 2015 and commercial
operation for Unit 4 approximately 12 months thereafter.
The total rated capacity of the new units, STP units 3 and 4, is
expected to equal or exceed 2,700 MW.
In October 2007, NRG and the City of San Antonio, acting
through CPS Energy, entered into an interim 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.
RepoweringNRG
Update
NRG has 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 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.
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.
21
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 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.
Currently, NRG has various projects in certain stages of
development that includes a new biomass project at Montville
Generating Station and the repowering of Big Cajun I and El
Segundo sites. As a result of permitting delays related to the
on-going Natural Resource Defense Council claims, the El Segundo
project is unlikely to reach its original completion date of
June 1, 2011.
The following is a summary of repowering projects that have
either been completed or are under construction. 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
Cos Cob On June 26, 2008, NRG
announced the completion of the repowering of its Cos Cob
generating station in Fairfield County, Connecticut which added
40 MW of power to the site. The Company funded and
developed this project which added two new gas turbine units,
between the existing three units, bringing total site output to
100 MW. All five units were retrofitted to use water
injection technology for NOx, resulting in a 50% net station
reduction in
NOx.
The site also converted to burn ultra-low sulfur distillated oil
resulting in a 97% reduction in
SO2
emissions.
Sherbino Wind Farm On October 22,
2008, NRG and its 50/50 joint venture partner, BP, announced the
completion of its Sherbino project in Pecos County, Texas. The
wind farm was developed by NRGs subsidiary Padoma together
with BP. Padoma managed the construction, which began in late
2007. BP will operate and dispatch the facility. Sherbino is a
150 MW wind farm consisting of 50 Vestas wind turbine
generators, each capable of generating up to 3 MW of power.
Since NRG has a 50 percent ownership, Sherbino will provide
the Company a net capacity of 75 MW.
Elbow Creek Wind Farm On
December 29, 2008, NRG, through Padoma, announced the
completion of its Elbow Creek project, a wholly-owned
120 MW wind farm in Howard County near Big Spring, Texas.
The Company funded and developed this wind farm which consists
of 53 Siemens wind turbine generators, each capable of
generating up to 2.3 MW of power.
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
Optim Energy, LLC, formally 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. 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. NRG provides construction management services and
will also provide various ongoing services related to plant
operations and maintenance, and use of existing NRG facilities
in return for a fixed fee plus reimbursement of the
Companys costs. NRG will also provide plant operations and
maintenance services and access to certain existing
infrastructure at the site on a cost reimbursement basis plus a
fixed fee. The construction of the project is on schedule and
the plant is expected to begin commercial operations in mid-2009.
22
GenConn Energy LLC In a procurement
process conducted by the Department of Public Utility Control,
or DPUC, and finalized in 2008, GenConn Energy LLC, or GenConn,
a 50/50 joint venture of NRG and The United Illuminating
Company, secured contracts in 2008 with Connecticut
Light & Power, or CL&P, for the construction and
operation of two 200 MW peaking facilities, at NRGs
Devon and Middletown sites in Connecticut. The contracts, which
are structured as contracts for differences for the full output
of the new power plants, have a
30-year term
and call for commercial operation of the Devon project by
June 1, 2010 and the Middletown project by June 1,
2011. GenConn has secured all state permits required for the
projects and has entered into contracts for engineering and for
the procurement of the 8 GE LM6000 combustion turbines required
for the projects. GenConn expects to close on financing for the
projects in the first half of 2009.
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, or Texas Genco.
Operating
Strategy
The Companys business in Texas is comprised of four sets
of assets: a nuclear plant, solid-fuel baseload plants,
gas-fired plants located in and around Houston, and wind farms.
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 or 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 specific to 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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
32,825
|
|
|
|
32,648
|
|
|
|
31,371
|
|
Gas
|
|
|
4,647
|
|
|
|
5,407
|
|
|
|
7,983
|
|
Nuclear(a)
|
|
|
9,456
|
|
|
|
9,724
|
|
|
|
9,385
|
|
Wind
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
46,937
|
|
|
|
47,779
|
|
|
|
48,739
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
MWh information reflects the
undivided interest in total MWh generated by STP.
|
23
Generation
Facilities
As of December 31, 2008, NRGs generation facilities
in Texas consisted of approximately 11,010 MW of generation
capacity. The following table describes NRGs electric
power generation plants and generation capacity as of
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)(c)
|
|
|
Fuel-type
|
|
Solid Fuel Baseload Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A.
Parish(a)
|
|
Thompsons, TX
|
|
|
100.0
|
|
|
|
2,475
|
|
|
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
|
|
|
|
|
|
|
|
|
5,340
|
|
|
|
Intermittent Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
Elbow Creek
|
|
Howard County, TX
|
|
|
100.0
|
|
|
|
120
|
|
|
Wind
|
Sherbino
|
|
Pecos County, TX
|
|
|
50.0
|
|
|
|
75
|
|
|
Wind
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intermittent Baseload
|
|
|
|
|
|
|
|
|
195
|
|
|
|
Operating Natural Gas-Fired Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cedar Bayou
|
|
Baytown, TX
|
|
|
100.0
|
|
|
|
1,495
|
|
|
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
|
|
|
|
|
|
|
|
|
5,475
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Capacity
|
|
|
|
|
|
|
|
|
11,010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. The 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 US 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 2,475 MW as of
December 31, 2008. Two of these units are 645 MW and
650 MW steam units that were placed in commercial service
in December 1977 and December 1978, respectively. The other two
units are 570 MW and 610 MW steam units that were
placed in commercial service in June 1980 and December 1982,
respectively. 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, 2008. 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
24
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 subsidiary of Westmoreland Coal
Company and the owner of a substantial portion of the remaining
lignite reserves. The contract, entered into August 1999, ended
on 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 US 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,
2008, STP had a zero percent forced outage rate and a 98% 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 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
historically fastest growing power markets. It represents
approximately 85% of the demand for power in Texas and covers
the entire 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 2.2%, compared to a compound annual rate of
growth of 1.9% in the US for the same period. For 2008, hourly
demand ranged from a low of 19,665 MW to a high of
62,190 MW. The ERCOT market has limited interconnections
compared to other markets in the US 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 has experienced significant construction of new
generation plants, with over 36,000 MW of new generation
capacity added to the market since 1999. As of December 31,
2008, installed generation capacity of approximately
83,000 MW existed in the ERCOT market, including
5,000 MW of generation that has suspended operations, or
been mothballed. Natural gas-fired generation
represents approximately 53,000 MW, or 64%. Approximately
22,400 MW, or 27%, was lower marginal cost generation
capacity such as coal, lignite and nuclear plants. NRGs
coal and nuclear fuel baseload plants represent approximately
5,340 MW net, or 24%, of the total
25
solid fuel baseload net generation capacity in the ERCOT market.
Additionally, NRG commenced commercial operations of the
Sherbino Wind Farm and Elbow Creek Wind Farm which represents
approximately 195 MW generation capacity for the Company.
Both Sherbino and Elbow Creek Wind Farms are located in the
physical control areas of the ERCOT market.
The ERCOT market has established a target equilibrium reserve
margin level of approximately 12.5%. The reserve margin for 2008
was 14% forecast to increase to 16% for 2009 per ERCOTs
latest Capacity Demand and Reserve Report. There are currently
plans being considered by the Public Utility Commission of
Texas, or 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 the ERCOT administers.
Published in August 2008, the 2007 State of the Market
Report for the ERCOT Wholesale Electricity Markets from
the Independent Market Monitor indicated that natural gas prices
were the primary driver of the trends in electricity prices from
2003 to 2007. 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
while the Sherbino and Elbow Creek wind farms are located in the
West Zone.
The ERCOT market operates under the reliability standards set by
the North American Electric Reliability Council. 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. The 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 the
ERCOT does not procure power on behalf of its members other than
to maintain the reliable operations of the transmission system.
The 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 the 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 the 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 now proposed to
take effect in December 2010. 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 the ERCOT may experience adverse pricing
effects due to their location on the transmission grid.
26
NORTHEAST
NRGs second largest asset base is located in the Northeast
region of the US 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 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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
11,506
|
|
|
|
11,527
|
|
|
|
11,042
|
|
Oil
|
|
|
349
|
|
|
|
1,169
|
|
|
|
1,217
|
|
Gas
|
|
|
1,494
|
|
|
|
1,467
|
|
|
|
1,050
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
13,309
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs Northeast region assets are located in or near load
centers and inside chronic transmission constraints such as New
York City, southwestern 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 has benefited from the
introduction of capacity market reforms in both the New England
Power Pool, or NEPOOL, and PJM. The Locational Forward Reserve
Markets, or LFRM, in the NEPOOL, became effective
October 1, 2006, and the transition capacity payments were
effective December 1, 2006. In all five 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. The LFRM and interim
capacity payments serve as a prelude to the full implementation
of the Forward Capacity Market, or FCM, which begins
June 1, 2010. PJMs Reliability Pricing Model, or RPM,
became effective June 1, 2007, and the Company has
participated in auctions providing capacity price certainty
through May 2012.
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
2008, Middletown, Montville and Norwalk Power (units 1 and
2) were covered by RMR agreements. Unless terminated
earlier, these agreements will terminate on June 1, 2010,
which coincides with the commencement of the FCM in NEPOOL.
Generation
Facilities
As of December 31, 2008, NRGs generation facilities
in the Northeast region consisted of approximately 7,020 MW
of generation capacity, including assets located in transmission
constrained areas, such as New York City
1,415 MW, and Southwest Connecticut 575 MW.
27
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(a)
|
|
Somerset, MA
|
|
|
100.0
|
|
|
|
125
|
|
|
Coal
|
Connecticut Remote Turbines
|
|
Four locations in CT
|
|
|
100.0
|
|
|
|
145
|
|
|
Oil/Natural Gas
|
Conemaugh
|
|
New Florence, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone
|
|
Shelocta, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast Region
|
|
|
|
|
|
|
|
|
7,020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Somerset had previously entered
into an agreement with the Massachusetts Department of
Environmental Protection, or MADEP, to retire or repower the
remaining coal-fired unit at Somerset by the end of 2009. In
connection with a repowering proposal approved by the MADEP, the
date for the shut-down of the unit was extended to
September 30, 2010.
|
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 505 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
10 MW and is activated when Consolidated Edison 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 a settlement agreement reached with
the New York Department of Environmental Conservation, or
NYSDEC, in January 2005, NRG committed to reducing
SO2
emissions from
28
Dunkirk and Huntley stations by 86.8% below baseline emissions
of 107,144 by 2013 and
NOx
emissions by 80.9% below baseline emission of 17,005 by 2012. In
order to comply with the NYSDEC settlement agreement, as well as
with various federal and state emissions standards, the Company
is in the process of installing back-end control facilities at
Dunkirk that are anticipated to be completed in the fall 2009.
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. To comply with
the January 2005 NYSDEC settlement agreement referenced above,
NRG retired Units 65 and 66 effective June 3, 2007, and as
of January 2009, has completed Huntleys back-end control
facilities.
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 1, 2, 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 and activated carbon injection systems to control
mercury. Units 1, 2 and 3 are fueled with 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 the Delaware Department of Natural Resources and
Environmental Control, or 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 Independent Systems
Operators, or 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.
SOUTH
CENTRAL
As of December 31, 2008, NRG owned approximately
2,845 MW of generating capacity in the South Central region
of the US. The region lacks a regional transmission organization
or ISO and, therefore, remains a bilateral market, which is not
able to take advantage of the large scale economic dispatch of
an ISO-administered energy market. 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
29
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
The South Central region maximizes its strategic position as a
significant coal-fired generator in a market that is highly
dependent on natural gas for power generation. South Central
also has long-term full service contracts with eleven rural
cooperatives serving load across Louisiana and makes incremental
wholesale energy sales when its coal-fired capacity exceeds the
cooperative contract requirements. The South Central region
works to expand its customer base within and beyond Louisiana
and works within the confines of the Entergy Transmission System
to obtain paths for 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
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
10,912
|
|
|
|
10,812
|
|
|
|
10,968
|
|
Gas
|
|
|
236
|
|
|
|
118
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
11,148
|
|
|
|
10,930
|
|
|
|
11,036
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, 2008, 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 and 4
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
210
|
|
|
Natural Gas
|
Big Cajun I Units 1 and 2
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
220
|
|
|
Natural Gas/Oil
|
Rockford I
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Rockford II
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
150
|
|
|
Natural Gas
|
Sterlington
|
|
Sterlington, LA
|
|
|
100.0
|
|
|
|
175
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total South Central
|
|
|
|
|
|
|
|
|
2,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
NRG owns 100% of Units 1 & 2;
58% of Unit 3
|
30
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. 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.
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, 2008, 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, Southwestern Electric
Power Company and CLECO, which collectively comprised an
additional 10% 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 either employs its owned or leased gas-fired
assets or 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 and
until certain of these load obligations expire, 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 to
date successfully prevented the addition of large industrial or
municipal loads at below-market 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.
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, as well as the preservation and
ultimate realization of the commercial value of the underlying
real estate. There are three principal components to this
strategy: (1) capturing the value of the portfolios
generation assets through a combination of forward contracts and
market sales of capacity, energy, and ancillary services;
(2) leveraging existing site control and emission
allowances to permit new, more efficient generating units at
existing sites; 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 stations Resource Adequacy, or RA,
capacity and consequently the RMR contract with the CAISO on the
Encina units was terminated effective December 31, 2007.
For calendar year 2008, the El Segundo station has entered into
a combination of tolling and RA contracts with multiple
load-serving entities and power marketers. The RA contacts
covered 387 MW of the available 670 MW and the tolls
covered 670 MWs during all available months. For calendar
year 2009, El Segundo station entered into approximately
548 MWs RA contracts and is placing the capacity in the
market through a portfolio of forward contracts.
Cabrillo II sold 28 MW of RA capacity for calendar
year 2008, 188 MW of RA capacity for calendar year 2009,
and for the
31
period January 1, 2010 through November 30, 2013,
88 MW. The Cabrillo II RMR agreement was terminated on
December 31 2008. Units with RA contracts also sell into energy
and ancillary services markets consistent with unit availability.
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, 2008 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 use
natural gas. Also located at the Encina Station is a combustion
turbine that provides peaking and black-start 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. Low NOx burner modifications and SCR equipment have
been installed on all the steam units.
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 gas-fired generating capacity at its Long
Beach Generating Station. Generation from Long Beach provides
needed support for the summer peak and during transmission
contingencies to load serving entities and the California
Independent System Operator. This project is backed by a
10-year PPA
executed with SCE in November 2006 and effective through
July 31, 2017. The new generation consists of refurbished
gas turbines with SCR equipment.
Cabrillo II Cabrillo II consists of 12
combustion turbines located on 4 sites throughout San Diego
County with an aggregate generating capacity of approximately
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.
32
Market
Framework
Except for the Saguaro facility, NRGs generation assets in
the West region operate within the balancing authority of CAISO.
CAISOs current market allows NRGs CAISO assets to
serve multiple load serving entities, or LSEs, and operates a
zonal balancing market and congestion clearing mechanism. CAISO
also has a locational capacity requirement, which requires LSEs
to procure a significant portion of load from defined local
reliability areas. All of NRGs CAISO assets are in the Los
Angeles or San Diego local reliability areas. It is
expected that on April 1, 2009, CAISOs new market,
known as Market Redesign and Technology Upgrade, or MRTU, will
become operational. MRTU will establish a day-ahead market for
energy and ancillary services and will settle prices
locationally. NRGs CAISO assets are all peaking and
intermediate in nature and are well positioned to capitalize on
the higher locational prices that may result from LMPs in
location constrained areas and will continue to satisfy local
distribution company capacity requirements. Longer term,
NRGs California portfolios locational advantage may
be impacted by new transmission, which may affect load pocket
procurement requirements. So far, however, the impacts of
increasing demand and need for flexible cycling capability
combined with delays in the online date of new transmission have
muted the impact of this long-term threat.
Californias resource mix will be significantly shaped in
the years ahead by Californias renewable portfolio
standard and its greenhouse gas reduction rules promulgated
pursuant to Assembly Bill 32 California Global
Warming Solutions Act of 2006, or AB32. In particular, the
states renewable portfolio standard is currently targeted
at 20% for 2010 and has been set for 33% by 2020 via Executive
Order. While the target requires ratification via legislation,
the goal has been widely supported and is expected to create
greater demand for low emission resources. The intermittent and
remote nature of most renewable resources will still leave a
strong demand for flexible load pocket resources. NRGs
California portfolio may also be impacted by any mechanism, such
as cap-and-trade, that places a price on incremental carbon
emissions. NRGs expectation is that the emission costs
will be reflected in the market price of power and that the net
cost to our existing portfolio of intermediate and peaking
resources will be manageable.
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 obtaining necessary
permits 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, 2008, NRG, through certain foreign
subsidiaries, had investments in power generation projects
located in Australia and Germany with approximately
1,080 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 concentrate
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, 2008, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
|
|
|
|
|
|
1,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
33
Australia The Gladstone power station is
owned by an unincorporated joint venture. As a member of the
venture, the Company owns an undivided 37.5% interest in assets
of the power station and a 37.5% interest in its output. A
wholly owned subsidiary, NRG Gladstone Operating Services,
serves as the stations sole operator. Because NRG is
neither the majority owner nor the joint venture manager, NRG
does not have unilateral control over the operation,
maintenance, and management of this asset. Gladstone
stations output is fully contracted through 2029 to Boyne
Smelter Limited and Stanwell Corporation Limited. Boyne Smelter
is owned by a consortium whose members include all the members
of the Gladstone joint venture other than NRG. Its business is
to refine alumina into aluminum. Stanwell is a state owned
corporation that generates power, purchases power from other
generators such as Gladstone, trades power in the Australian
National Electricity Market, and delivers power to retail
customers.
On June 8, 2006, NRG announced the sale of the
Companys 37.5% interest in the joint venture and its 100%
interest in NRG Gladstone Operating Services to Transfield
Services Infrastructure B.V, or Transfield Services, of
Australia. On October 9, 2008, Transfield Services
terminated the Gladstone sale and purchase agreement at no cost
or expense to the parties, other than transaction costs which
are immaterial as to NRG, because of its inability to achieve
necessary third party consents. Subsequent negotiations over a
plan to reorganize the Gladstone project to facilitate
NRGs exit stalled due to a precipitous decline in aluminum
prices and asset prices in the second half of 2008. With
aluminum demand predicted by some to show little or no growth in
2009 and asset prices showing no signs of recovery, NRGs
stay in Australia may be extended. Fortunately, the long term
off-take agreements will insulate the Gladstone project from the
effects of the recession. The Company will aggressively pursue
other options to preserve, protect and enhance the value of this
investment.
Germany NRGs interests in Germany
include a 50% equity interest in Mitteldeutsche
Braunkohlengesellschaft mbH, or MIBRAG, which mines
approximately 19 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 82% 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.
Brazil On April 28, 2008, NRG completed
the sale of its 100% interest in Tosli Acquisition B.V., or
Tosli, which held all NRGs 99.2% voting equity interest in
a 156 MW hydroelectric power plant through Itiquira
Energetica S.A., or ITISA, to Brookfield Renewable Power Inc.
(previously Brookfield Power Inc.), a wholly-owned subsidiary of
Brookfield Asset Management Inc. In addition, the purchase price
adjustment contingency under the sale agreement was resolved on
August 7, 2008. In connection with the sale, NRG received
$300 million of cash proceeds from Brookfield, and removed
$163 million of assets, including $59 million of cash,
$122 million of liabilities, including $63 million of
debt, and $15 million in foreign currency translation
adjustment from its 2008 consolidated balance sheet. As
discussed in Item 15 Note 3,
Discontinued Operations Business Acquisitions and
Dispositions, to the Consolidated Financial Statements, the
activities of Tosli and ITISA has 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
1,020 megawatts thermal equivalent, or MWt. As of
December 31, 2008, NRG Thermal provided steam heating to
approximately 505 customers and chilled water to 100
customers in five cities in the US. 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 15 MW
coal-fired cogeneration facility in Dover,
34
Delaware as well as a 12 MW gas-fired project in
Harrisburg, Pennsylvania. Approximately 39% 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
the CFTC, FERC, NRC, PUCT and other public utility commissions
in certain states where NRGs generating or thermal assets
are located. In addition, NRG is subject to the market rules,
procedures, and protocols of the various ISO markets in which it
participates. NRG must also comply with the mandatory
reliability requirements imposed by the North American Electric
Reliability Corporation, or NERC, and the regional reliability
councils in the regions where the Company operates.
The operations of, and wholesale electric sales from, NRGs
Texas region are not subject to rate regulation by the 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
The 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. The 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
The 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, the 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. The FERC also determines whether a
generation facility meets the ownership and technical criteria
of a Qualifying Facility, or QF, under Public Utility Regulatory
Policies Act of 1978, or PURPA. Each of NRGs US generating
facilities has either been determined by the 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 the FERC
exclusive rate-making jurisdiction over the wholesale sale of
electricity and transmission of electricity in interstate
commerce. Under the FPA, the 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 the FERC jurisdiction to review
certain transactions and numerous other activities of public
utilities. NRGs QFs are currently exempt from the
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 the
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 US make sales of electricity pursuant to
market-based rates authorized by the FERC. 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 the 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
35
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 the 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 the FERC any material changes in status
that would reflect a departure from the characteristics that the
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 the 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.
On June 30, 2008 and December 31, 2008, NRG filed with
the FERC its updated market power analyses for its Northeast and
South Central assets, respectively. Such updates are a
requirement of the Commissions grant of market-based rate
authority. The Companys updates remain pending.
Section 203 of the FPA requires the FERCs prior
approval for the transfer of control of assets subject to the
FERCs jurisdiction. Section 204 of the FPA gives the
FERC jurisdiction over a public utilitys issuance of
securities or assumption of liabilities. However, the 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 the FERC.
In compliance with Section 215 of the Energy Policy Act of
2005, or EPAct of 2005, the FERC has approved the 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 the 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 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 the PUHCA of 2005.
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 the 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 the 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 contract 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
36
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, 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. See also Item 15 Note 6,
Nuclear Decommissioning Trust Fund, to the
Consolidated Financial Statements for additional discussion.
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 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 the 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 the ERCOT.
Regional
Regulatory Developments
In New England, New York, the Mid-Atlantic region, the Midwest
and California, the FERC has approved regional transmission
organizations, also commonly referred to as ISOs. Most of these
ISOs administer a wholesale centralized bid-based spot market in
their regions pursuant to tariffs approved by the 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 the 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
37
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
The 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 was scheduled to
begin in 2008. On May 20, 2008, the ERCOT announced that it
would delay the implementation of the Texas Nodal Protocols, and
is now targeting a December 2010 implementation.
In May 2008, the ERCOT real-time energy market experienced
periods of high prices as a result of limited intervals during
which two zonal constraints were simultaneously binding, and
this congestion was irresolvable through the dispatch of
available resources. In response, the ERCOT enacted revised
protocols, effective June 9, 2008, for addressing such
zonal congestion, providing the ERCOT with greater authority to
manage such congestion through the use of out-of-market
mechanisms towards the goal of lowering prices. In addition, on
June 17, 2008, the ERCOT enacted revisions to its price cap
procedures in order to further dampen the volatility and high
prices. Thus, it is unlikely that the circumstances contributing
to the price spikes of May 2008 will be repeated.
On July 17, 2008, as part of its determination of
Competitive Renewable Energy Zones, or CREZ, the PUCT approved a
significant transmission expansion plan to provide for the
delivery of approximately 18,500 MW of energy from the
western region of Texas, primarily wind generation. The schedule
for construction of the transmission upgrades (approximately
2,300 miles of new 345 kV lines and 42 miles of new
138 kV lines) will be determined in subsequent PUCT proceedings.
If completed as currently approved, the transmission upgrades
and associated wind generation could impact wholesale energy and
ancillary service prices in the ERCOT. The PUCT issued its
written order on August 15, 2008.
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 FCM as discussed
below. NRGs Norwalk Power facility units 1 and 2 continue
to be operated pursuant to an RMR agreement that was accepted by
the Commission on July 16, 2007 (effective June 19,
2007). On December 4, 2008, Norwalk Power filed a
Settlement Agreement resolving the RMR agreement eligibility and
rate issues. The Settlement Agreement provides for an Annual
Fixed Revenue Requirement of $34 million for 2008 and
$32 million for 2009, continuing at a rate of
$32 million per year until FCM is implemented on
June 1, 2010. The FERC accepted the Settlement Agreement on
December 30, 2008. In the FCM auction for delivery year
2010/2011, the Company sought to de-list Norwalk Powers
units 1 and 2. ISO-NE declined to accept that de-list bid on the
grounds these units were needed for reliability. The FERC has
determined that the units should be compensated at their de-list
bid of $5.99 per kW-month. The Company did not seek to de-list
Norwalk Powers units 1 and 2 in the FCM auction for
delivery year 2011/2012.
On December 28, 2006, the Attorneys General of the State of
Connecticut and Commonwealth of Massachusetts filed in the US
Court of Appeals for the District of Columbia, or D.C., Circuit
an appeal of the FERC orders accepting 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, the 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
38
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.
On October 20, 2008, Northeast Utilities Service Company,
or NU, the parent company of CL&P filed an application with
the Connecticut Siting Council for the Greater Springfield
Reliability component of the New England East-West
Solution, or NEEWS, transmission project, four distinct projects
that together represent a significant reinforcement of the 345
kV transmission system. If constructed, the NEEWS projects will
increase the import capacity into Connecticut by approximately
1,100 MW.
New York On March 7, 2008, the FERC
issued an order accepting the NYISOs proposed market
reforms to the in-city Installed Capacity, or ICAP, market, with
only minor modifications. The NYISO proposal retains the
existing ICAP market structure, but imposes 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
imposes a new reference price on pivotal suppliers and requires
bids to be submitted at or below the reference price. The new
reference price is derived from 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
NYISOs proposed reforms became effective March 27,
2008.
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. The
NYSRC approved a 2009 IRM of 16.5%, which is an increase of 1.5%
from the 2008 requirement and should have a modest positive
effect on capacity prices. Additionally, on January 29,
2008, the FERC accepted the NYISOs installed capacity
demand curves for 2008/2009, 2009/2010, and 2010/2011. The
demand curves are a critical determinant of capacity market
prices, and these revised curves will contribute to the
continuation of the current depressed prices, all other factors
remaining constant.
PJM On December 12, 2008, PJM filed with
the FERC a number of proposed revisions to the RPM capacity
market design. PJM has proposed to implement many of the more
significant changes in the next RPM Base Residual Auction,
scheduled for May 2009 for planning year 2012/2013. On
February 9, 2009 PJM filed an Offer of Settlement revising
its December 12, 2008 filing with respect to the
determination of several of the key inputs for the RPM auctions.
West
Region
California has transitioned to a market structure where 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. Cabrillo Power II LLC terminated
its RMR agreement with CAISO effective December 31, 2008.
See also the Regional Business Description for a
discussion of the contracting activities that have occurred on
the units pursuant to the states RA program.
CAISO has indicated that MRTU is scheduled to commence
April 1, 2009. 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. On October 18, 2008, the FERC
accepted the CAISOs Interim Capacity Procurement
Mechanism, scheduled to go into effect contemporaneously with
the implementation of MRTU. This mechanism is not a capacity
market, but rather allows the CAISO to acquire generation
capacity if LSEs do not satisfy their Resource Adequacy
Obligations.
On October 22, 2008, the FERC issued a definitive order
regarding the provision of station power in California. The
FERCs order reaffirmed the right of generators to engage
in monthly netting of their station power needs and, further,
clarified that local transmission-owning utilities are preempted
from imposing state-based charges on such generators. This order
should allow the Company to engage in monthly netting and thus
avoid buying power at retail for many of its stations and,
further, to avoid the other charges that the local
transmission-owning utilities have been
39
imposing. The Company has submitted a station power plan to the
California Public Utilities Commission, or CPUC, and expects to
realize savings in operation costs as a result of this order.
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 USEPA
published the Clean Air Mercury Rule, or CAMR, and the Clean Air
Interstate Rule, or CAIR, market-based
cap-and-trade
programs to reduce mercury,
SO2
and NOx emissions from coal-fired power plants. On
February 8, 2008, the US Court of Appeals for the D.C.
Circuit vacated the USEPAs rule delisting coal- and
oil-fired electric generating units on which CAMR was based.
Power plant mercury emissions are now subject to
Section 112 of the Clean Air Act, or CAA, which requires
installation of maximum achievable control technology, or MACT,
to reduce emissions. On October 17, 2008, the USEPA filed a
petition with the US Supreme Court to reconsider the vacatur
which was immediately followed by a petition to force EPA to
issue the MACT standard from environmental groups. Certain
states in which NRG operates coal plants, such as the states of
Delaware, Massachusetts and New York, adopted state
implementation plans in lieu of the CAMR federal implementation
plan. These state rules remain unchanged by the Courts
ruling and are likely to meet any new standard for MACT
requirements at existing generating units.
CAIR applied to 28 eastern states and D.C., and capped both
SO2
and NOx emissions from power plants in two phases. CAIR applies
to most of the Companys power plants in the states of New
York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois,
Pennsylvania, Maryland and Texas. Following a finding to vacate
CAIR in its entirety in July 2008, the D.C. Circuit Court
reversed its opinion in December 2008 and remanded CAIR to the
USEPA without vacatur. As a result, the effective date for the
CAIR NOx trading program remains January 1, 2009.
NRGs
SO2
and NOx control plans are driven primarily by state requirements
and consent orders. NRGs estimate for environmental
capital expenditures reflects changes in schedule and design
related to the current status of both CAIR and CAMR. The timing
and substantive provisions of any ensuing revised or replacement
regulations or legislation may alter the composition
and/or rate
of spending for environmental retrofits at the Companys
facilities.
In a ruling on December 22, 2006, the D.C. Circuit
overturned portions of the USEPAs Phase I implementation
rule for the new
8-hour ozone
standard. Specifically, the court ruled that the 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 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 Los Angeles, New York City Area
and Houston.
The USEPA strengthened the primary and secondary ground level
ozone National Ambient Air Quality Standards, or NAAQS, (eight
hour average) from 0.08 ppm to 0.075 ppm on
March 12, 2008. The USEPA plans to finalize ozone
non-attainment regions by March 2010 and states would likely
submit plans to come into attainment
40
by 2013. The Company is unable to predict with certainty the
impact of the states future recommendations on NRGs
operations.
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 a
Notice of Violation, or 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.
Climate Change 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
US Supreme Court found that
CO2,
the most common GHG, could be regulated as a pollutant and that
the USEPA, under the CAA, could regulate
CO2
emissions from mobile sources and by extension, stationary
sources. The USEPA gathered input from stakeholders in the fall
of 2008, but has not taken any action to regulate
CO2
under the CAA. Since power plants, particularly coal-fired
plants, are a significant source of GHG emissions both in the US
and globally, it is almost certain that GHG legislative or
regulatory actions will encompass power plants as well as other
GHG emitting stationary sources.
In 2008, 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 US,
4 million tonnes in Germany and 3 million tonnes in
Australia. The impact from federal, regional or state regulation
of GHGs 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
CO2
emissions allowances without having to purchase them in an
auction or on the open market. Thereafter, under any such
legislation or regulation, the impact on NRG would depend on the
Companys level of success in developing and deploying low
and no carbon technologies such as those being pursued as part
of the RepoweringNRG and econrg initiatives.
Additionally, NRGs current contracts with its South
Central regions cooperative customers allows for the
recovery of emission-based costs.
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 Second
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. 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 Second Circuit Court of Appeals
decision has been challenged in the US Supreme Court. 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 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 US 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 US
Nuclear Waste Policy Act of 1982, owners of nuclear plants,
including the owners of STP, entered into contracts setting out
the obligations of the owners and the US 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
41
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. 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.
Regional
US Environmental Initiatives
Northeast
Region
NRG operates electric generating units located in Connecticut,
Delaware, Maryland, Massachusetts and New York which are
subject to RGGI. These units will have to surrender one
allowance for every US ton of
CO2
emitted with true up for
2009-2011
occurring in 2012. Allowances will be partially allocated in the
state of Delaware only. In 2008, NRG emitted approximately
12 million tonnes of
CO2
in RGGI states.
West
Region
Under AB32, which was enacted in 2007, the state of California
will launch a multi sector climate change program which likely
will include, among other things, a phased
cap-and-trade
approach starting in 2012 and an increased use of renewable
energy. The AB32 scoping document, adopted by the California Air
Resources Board or CARB in December 2008 is consistent with the
trading approach of the Western Climate Initiative or WCI, made
up of seven states and four Canadian Provinces. NRG does not
expect any implementation of
cap-and-trade
under AB32 in California to 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 CAA from the USEPA seeking
information primarily related to physical changes made at the
Big Cajun II plant, and subsequently received a 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. NRG has evaluated the original and subsequent
claims and believes they have no merit. Nonetheless, NRG has had
discussions with the USEPA about resolving the claims and the
Company cannot predict with certainty the outcome of this matter.
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
42
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 the DNREC
stating that it may be a potentially responsible party with
respect to a historic captive landfill. On October 1, 2007,
NRG signed an agreement with the DNREC to investigate the site
through the Voluntary
Clean-up
Program. On February 4, 2008, the DNREC issued findings
that 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
are completed, the Company is unable to predict the impact of
any required remediation.
On May 29, 2008, the DNREC issued an invitation to
NRGs Indian River Operations, Inc. to participate in the
development and performance of a Natural Resource Damage
Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG
is currently working with the DNREC and other Trustees to close
out the property.
Further details regarding the Companys Domestic Site
Remediation obligations can be found in Item 15
Note 23, Environmental 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 US, 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 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 Under the German
National
CO2
Allocation Plan 2008 2012, MIBRAG was granted
CO2
allocations that are less than the needs of its three generating
plants. MIBRAG has minimized the impact of the short allocation
by coordinated forward selling of electricity and purchase of
CO2
certificates at times when the
CO2 / electricity
spread is profitable. Additionally, MIBRAG has 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 passed through to
its off-taker of energy under terms of 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, or Exchange Act, 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 SEC.
43
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Item 1A
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Risk
Factors Related to NRG Energy, Inc.
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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 natural gas-fired power plants that
currently have substantially higher variable costs than
NRGs coal-fired baseload power plants. This 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 that 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 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, 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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changes 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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electric supply disruptions, including plant outages and
transmission disruptions;
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changes in power transmission infrastructure;
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fuel transportation capacity constraints;
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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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44
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 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.
45
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 2014, 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 could deteriorate over
time if the rural cooperatives significantly grow their customer
base during the remaining terms of these contracts unless the
Company is able to amend or renegotiate its contracts with the
cooperatives or add generating capacity.
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. The
Company also relies on counterparty performance under its
hedging agreements and is exposed to the credit quality of its
counterparties under those agreements. 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.
46
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 first or 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.
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. All
economic hedges may not necessarily qualify for cash flow hedge
accounting treatment. As a result, the Companys quarterly
and annual results are subject to significant fluctuations
caused by changes in market prices.
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
47
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.
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.
48
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
emission 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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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
49
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.
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 it 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.
50
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 CAISO, NYISO and NE-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
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 US
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 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 US
make sales of electricity in interstate commerce and are public
utilities for purposes of the FPA. The 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 the 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 the FERCs acceptance of a
cost-of-service rate schedule and could become
51
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 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 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
US Nuclear Waste Policy Act of 1982 to accept and dispose of
STPs spent nuclear fuel. See also Environmental
Matters US Federal Environmental
Initiatives Nuclear Waste in Item 1
for further discussion. 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 US 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
52
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.
Environmental laws and regulations have generally become more
stringent over time, and the Company expects this trend to
continue. Regulations currently under revision by USEPA,
including CAIR, MACT, standards to control Mercury and the 316
(b) rule to mitigate impact by once through cooling, could
result in tighter standards or reduced compliance flexibility.
While the NRG fleet employs advanced controls and utilizes
industrys best practices, new regulations to address
tightened National Ambient Air Quality Standards for Ozone and
PM 2.5 or new rules to further restrict ash handling at
coal-fired power plants could also further restrict plant
operations.
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.
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 the EPA
is giving consideration to control of
CO2
emissions from power plants via existing sections of the CAA.
Since power plants, particularly coal-fired plants, are a
significant source of GHG emissions both in the US and globally,
it is almost certain that GHG regulatory actions will encompass
power plants as well as other GHG emitting stationary sources.
In 2008, 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 US,
4 million tonnes in Germany and 3 million tonnes in
Australia.
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
CO2
emissions allowances without having to purchase them in an
auction or on the open market.
Of the approximately 61 million tonnes of
CO2
emitted by NRG in the US in 2008, approximately 12 million
tonnes were emitted from the Companys generating units in
Connecticut, Delaware, Maryland, Massachusetts, and New York
that are subject to RGGI starting 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
CO2
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.
53
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, 2008, approximately 66% of NRGs
employees at its US 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, 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 US investments do not have.
NRG has investments in power projects in Australia and Germany.
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
occurrences 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
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54
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preferred or common stock or to use its cash flow to fund its
operations, capital expenditures and future business
opportunities;
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limiting NRGs ability to enter into long-term power sales
or fuel purchases which require credit support;
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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;
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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
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limiting NRGs ability to adjust to changing market
conditions and placing it at a competitive disadvantage compared
to its competitors who have less debt.
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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:
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general economic and capital market conditions;
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credit availability from banks and other financial institutions;
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investor confidence in NRG, its partners and the regional
wholesale power markets;
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NRGs financial performance and the financial performance
of its subsidiaries;
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NRGs level of indebtedness and compliance with covenants
in debt agreements;
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maintenance of acceptable credit ratings;
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cash flow; and
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provisions of tax and securities laws that may impact raising
capital.
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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 the Financial Accounting Standards Board, or
FASB, Accounting Standard Number 142, Goodwill and Other
Intangible Assets, or SFAS 142, 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.
Exelon
Corporations unsolicited acquisition proposal and tender
offer for all the Companys outstanding common stock is
disruptive to the Companys management and business and
creates uncertainty that may adversely affect our
business.
On October 19, 2008, the Company received an unsolicited
proposal from Exelon Corporation to acquire all of the
outstanding shares of the Company and on November 12, 2008,
Exelon announced a tender offer, referred to as the Exelon
tender offer, for all of the Companys outstanding common
stock. NRGs Board of Directors, after carefully reviewing
the proposal, unanimously concluded that the proposal was not in
the best interests of the
55
stockholders and has recommended that NRG stockholders not
tender their shares. On January 30, 2009 Exelon also
announced a proposed slate of nine nominees for election to
NRGs Board of Directors at the 2009 Annual Meeting of
Stockholders, together with a proposal to increase the number of
NRG directors from 12 to 19 with two vacancies, referred to as
the Exelon proxy contest. The review and consideration of the
Exelon tender offer and proxy contest, have been, and may
continue to be, a significant distraction for our management and
employees and have required, and may continue to require, the
expenditure of significant time and resources by the Company.
Exelons tender offer and proxy contest have also created
uncertainty for the Companys employees and this
uncertainty may adversely affect the Companys ability to
retain key employees and to hire new talent. Exelons
tender offer and proxy contest may also create uncertainty for
current and potential business partners, which may cause them to
terminate, or not to renew or enter into, arrangements with the
Company. In addition, if the Exelon nominees are elected to
NRGs Board of Directors, the ability of management to work
effectively and efficiently with NRGs Board of Directors
with respect to the day to day operations and development of the
Company may be restricted, and as a result, may harm the
Companys business. Furthermore, the Company and its Board
of Directors are defendants in three purported stockholder class
action complaints relating to the Exelon proposal as more fully
described in Part I, Item 3 Legal
Proceedings of this Annual Report on
Form 10-K.
These lawsuits or any future similar or related lawsuits may
become time consuming and expensive. These consequences, alone
or in combination, may harm the Companys business.
Exelon
Corporations proxy contest, board expansion and director
nominations could result in a Change of Control, as that term is
used in the Companys Senior Credit Facility and Senior
Notes, which may adversely affect our business.
A default under the Companys Senior Credit Facility and a
mandatory change in control offer under the Senior Notes may be
triggered if the Exelon nominees compose a majority of
NRGs Board of Directors at any time. A Change of Control
under the Companys Senior Credit Facility and Senior Notes
could occur if the two vacancies on NRGs Board of
Directors (created only if the Companys shareholders
approve Exelons proposal to the expand NRGs Board of
Directors to 19 members) are not filled by directors
nominated by the current NRG Board. A Change of Control may also
be triggered by other future events where the resulting
composition of NRGs Board of Directors consists of a
majority of Exelon nominated directors, such as the retirement
or death of any non-Exelon nominated Board member. If a Change
of Control is triggered under the Senior Credit Facility and
Senior Notes this could have a material and significant impact
on the Companys business.
56
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 of 1933, as amended, or
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 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 this report and the
following:
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General economic conditions, changes in the wholesale power
markets and fluctuations in the cost of fuel;
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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;
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The effectiveness of NRGs risk management policies and
procedures, and the ability of NRGs counterparties to
satisfy their financial commitments;
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Counterparties collateral demands and other factors
affecting NRGs liquidity position and financial condition;
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NRGs ability to operate its businesses efficiently, manage
capital expenditures and costs tightly, and generate earnings
and cash flows from its asset-based businesses in relation to
its debt and other obligations;
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NRGs ability to enter into contracts to sell power and
procure fuel on acceptable terms and prices;
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The liquidity and competitiveness of wholesale markets for
energy commodities;
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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;
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Price mitigation strategies and other market structures employed
by ISOs or RTOs that result in a failure to adequately
compensate NRGs generation units for all of its costs;
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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;
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Operating and financial restrictions placed on NRG and its
subsidiaries that are 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;
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NRGs ability to implement its RepoweringNRG
strategy of developing and building new power generation
facilities, including new nuclear units and wind projects;
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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.
57
|
|
Item 1B
|
Unresolved
Staff Comments
|
None.
Listed below are descriptions of NRGs interests in
facilities, operations
and/or
projects owned as of December 31, 2008. 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, 2008. The following table summarizes
NRGs power production and cogeneration facilities by
region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Power
|
|
|
|
|
Generation
|
|
|
Primary
|
Name and Location of
Facility
|
|
Market
|
|
% Owned
|
|
|
Capacity (MW)
|
|
|
Fuel-type
|
|
Texas Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A. Parish, Thompsons, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
2,475
|
|
|
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
|
|
|
|
1,495
|
|
|
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
|
Elbow Creek Wind Farm, Howard County, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
120
|
|
|
Wind
|
Sherbino Wind Farm, Pecos County, Texas
|
|
ERCOT
|
|
|
50.0
|
|
|
|
75
|
|
|
Wind
|
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
|
Connecticut Jet Power, Connecticut (four sites)
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
145
|
|
|
Oil/Natural Gas
|
Conemaugh, New Florence, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone, Shelocta, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Power
|
|
|
|
|
Generation
|
|
|
Primary
|
Name and Location of
Facility
|
|
Market
|
|
% Owned
|
|
|
Capacity (MW)
|
|
|
Fuel-type
|
|
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
|
|
|
|
150
|
|
|
Natural Gas
|
Sterlington, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
175
|
|
|
Natural Gas
|
West Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Encina, Carlsbad, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
965
|
|
|
Natural Gas
|
El Segundo Power, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
670
|
|
|
Natural Gas
|
Long Beach, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
260
|
|
|
Natural Gas
|
San Diego Combustion Turbines, California (three sites)
|
|
CAISO
|
|
|
100.0
|
|
|
|
190
|
|
|
Natural Gas
|
Saguaro Power Co., Henderson, Nevada
|
|
WECC
|
|
|
50.0
|
|
|
|
45
|
|
|
Natural Gas
|
International Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gladstone Power Station, Queensland, Australia
|
|
Enertrade/Boyne
Smelter
|
|
|
37.5
|
|
|
|
605
|
|
|
Coal
|
Schkopau Power Station, Germany
|
|
Vattenfall Europe
|
|
|
41.9
|
|
|
|
400
|
|
|
Lignite
|
MIBRAG,
Germany(c)
|
|
Schkopau, Lippendorf &
ENVIA
|
|
|
50.0
|
|
|
|
75
|
|
|
Lignite
|
|
|
|
(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
|
59
The following table summarizes NRGs thermal facilities as
of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
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: 1,143 MMBtu/hr. (335 MWt) Chilled Water: 40,630
tons (143 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. 210 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: 296 MMBtu/hr. (87 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. and Procter & Gamble Company
|
|
|
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 and various other office space.
60
|
|
Item 3
|
Legal
Proceedings
|
Exelon Corporation and Exelon Xchange Corporation v.
Howard E. Cosgrove et al., Court of Chancery of the State of
Delaware, Case
No. 4155-VCL
(filed November 11, 2008)
On November 11, 2008, Exelon
Corporation, or Exelon, and its wholly-owned subsidiary, Exelon
Xchange, filed a complaint against NRG and NRGs Board of
Directors. The complaint alleges, among other things, that
NRGs Board of Directors failed to give due consideration
and to take appropriate action in response to the acquisition
proposal announced by Exelon on October 19, 2008, in which
Exelon offered to acquire all of the outstanding shares of NRG
common stock at an exchange ratio of 0.485 Exelon shares for
each NRG common share. The complaint seeks, among other things,
declaratory and injunctive relief: (1) declaring that
NRGs Board of Directors has breached its fiduciary duties
to the NRG stockholders by rejecting and refusing to consider
Exelons acquisition proposal and by failing to exempt the
proposed transaction from application of Section 203 of the
Delaware General Corporation Law; (2) compelling NRGs
Board of Directors to approve Exelons acquisition proposal
for purposes of Section 203 of the Delaware General
Corporations Law; (3) declaring that the adoption of any
measure that would have the effect of impeding or interfering
with Exelons acquisition proposal constitutes a breach of
NRGs Board of Directors fiduciary duties; and
(4) enjoining the defendants from adopting any measures
that would have the effect of impeding or interfering with
Exelons acquisition proposal. On November 14, 2008,
NRG and NRGs Board of Directors filed a motion to dismiss
Exelons complaint on the grounds that it fails to state a
claim upon which relief can be granted. On January 28,
2009, NRG and NRGs Board of Directors filed their brief in
support of their motion to dismiss.
Louisiana Sheriffs Pension & Relief Fund
and City of St. Claire Shores Police & Fire Retirement
System, on Behalf of Themselves and All Others Similarly
Situated v. David Crane, et al., Court of Chancery of the
State of Delaware, Case
No. 4193-VCL
(filed November 25, 2008; served
December 11, 2008) The complaint
alleges, among other things, that NRGs Board of Directors
failed to give due consideration and to take appropriate action
in response to the acquisition proposal announced by Exelon on
October 19, 2008, in which Exelon offered to acquire all of
the outstanding shares of NRG common stock at an exchange ratio
of 0.485 Exelon shares for each NRG common share. The complaint
seeks, among other things, declaratory and injunctive relief:
(1) declaring that the action is a class action and
certifying plaintiff as class plaintiff and plaintiffs
counsel as class counsel; (2) declaring that NRGs
Board of Directors has breached its fiduciary duties to the NRG
stockholders by rejecting and refusing to consider Exelons
acquisition proposal; (3) entering a mandatory injunction
requiring NRG to exempt Exelons offer from
Section 203 of the Delaware General Corporation Law; and
(4) to the extent injunctive relief is not granted,
awarding compensatory damages in favor of the Plaintiffs and
other members of the class. On December 23, 2008, NRG and
NRGs Board of Directors filed a motion to dismiss the
complaint on the grounds that it fails to state a claim upon
which relief can be granted. On January 28, 2009, NRG and
NRGs Board of Directors filed their brief in support of
their motion to dismiss.
Evelyn Greenberg, on Behalf of Herself and All Others
Similarly Situated v. David Crane, et al.,
(filed October 20, 2008); Joel A. Gerber and
Raphael Nach & Jaqueline Nach Co-Trustee The Nach
Family Trust U/A, Individually and on behalf of All Others
Similarly Situated v. NRG Energy, Inc., et al. (filed
November 10, 2008); Walter H. Stansbury Individually and
on behalf of All Others Similarly Situated v. NRG Energy,
Inc., et al., (filed October 24, 2008), Superior
Court of New Jersey-Law Division, Mercer County, Docket
No. MER-C-137-08
Plaintiffs filed three separate
complaints against NRG and NRGs Board of Directors
alleging, among other things, that NRGs Board of Directors
breached its fiduciary duties to NRG stockholders by failing to
take action regarding the acquisition proposal announced by
Exelon on October 19, 2008, in which Exelon offered to
acquire all of the outstanding shares of NRG common stock at an
exchange ratio of 0.485 Exelon shares for each NRG common share.
On January 6, 2009, the three cases were consolidated and
transferred to the Law Division of the Mercer County Superior
Court. On January 21, 2009, the plaintiffs filed an Amended
Consolidated Complaint in which they allege a single count of
breach of fiduciary duty against NRGs Board of Directors
and seek injunctive relief: (1) declaring that the action
is a class action and certifying plaintiffs as class plaintiffs
and counsel as class counsel; (2) declaring that defendants
breached their fiduciary duties by summarily rejecting the
Exelon offer; (3) ordering defendants to negotiate with
respect to the Exelon offer or with respect to another
transaction to maximize shareholder value; (4) ordering
defendants to exempt Exelons offer from Section 203
of the Delaware General Corporation Law; (5) awarding
compensatory damages including interest; (6) awarding
plaintiffs costs and fees; and (7) granting other relief
the Court deems proper. A response is due on or before
February 20, 2009.
61
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)
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 (Generation) Holdings, Inc., or 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 of California. For WCP, the
alleged overcharges totaled approximately $940 million for
2001 and 2002. The complaint demanded that the FERC abrogate the
CDWR contract and sought refunds associated with revenues
collected under the contract. In 2003, the FERC rejected this
complaint, denied rehearing, and the case was appealed to the US
Court of Appeals for the Ninth Circuit, or Ninth Circuit, where
oral argument was held on December 8, 2004. On
December 19, 2006, the Ninth Circuit decided that in the
FERCs review of the contracts at issue, the FERC could not
rely on the Mobil-Sierra standard presumption of just and
reasonable rates, where such contracts were not reviewed by the
FERC with full knowledge of the then existing market conditions.
WCP and others sought review by the US Supreme Court. WCPs
appeal was not selected, but instead held by the Supreme Court.
In the appeal that was selected by the Supreme Court, on
June 26, 2008, the Supreme Court ruled (1) that the
Mobil-Sierra public interest standard of review applied
to contracts made under a sellers market-based rate
authority; (2) that the public interest bar
required to set aside a contract remains a very high one to
overcome; and (3) that the Mobil-Sierra presumption
of contract reasonableness applies when a contract is formed
during a period of market dysfunction unless (a) such
market conditions were caused by the illegal actions of one of
the parties or (b) the contract negotiations were tainted
by fraud or duress. In this related case, the US Supreme Court
affirmed the Ninth Circuits decision, agreeing that the
case should be remanded to FERC to clarify FERCs 2003
reasoning regarding its rejection of the original complaint
relating to the financial burdens under the contracts at issue
and to alleged market manipulation at the time these contracts
were formed. As a result, the US Supreme Court then reversed and
remanded the WCP CDWR case to the Ninth Circuit for treatment
consistent with its June 26, 2008, decision in the related
case. On October 20, 2008, the Ninth Circuit asked the
parties in the remanded CDWR case, including WCP and the FERC,
whether that Court should answer a question the US Supreme Court
did not address in its June 26, 2008, decision; whether the
Mobil-Sierra doctrine applies to a third-party that was
not a signatory to any of the wholesale power contracts,
including the CDWR contract, at issue in the case. Without
answering that reserved question, on December 4, 2008, the
Ninth Circuit vacated its prior opinion and remanded the WCP
CDWR case back to the FERC for proceedings consistent with the
US Supreme Courts June 26, 2008 decision. On
December 15, 2008, WCP and the other seller-defendants
filed with FERC a Motion of Order Governing Proceedings on
Remand. On January 14, 2009, the Public Utilities
Commission of the State of California filed an Answer and Cross
Motion for an Order Governing Procedures on Remand, and on
January 28, 2009, WCP and the other seller-defendants filed
their reply.
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 the 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.
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.
62
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. On
December 18, 2008, NRG filed with the US Bankruptcy Courts
for the Southern District of New York a Closing Report and an
Application for Final Decree Closing the Chapter 11 Case
for NRG Energy, Inc. et al and on December 29, 2008,
the court entered the Final Decree. As of December 21,
2008, the reserve held $9,776,880 in cash and
1,282,783 shares of common stock. On December 21,
2008, the Company issued an instruction letter to The Bank of
New York Mellon to distribute all remaining cash and stock in
the Disputed Claims Reserve to NRGs creditors. On
January 12, 2009, The Bank of New York Mellon commenced the
distribution of all remaining cash and stock in the Disputed
Claim Reserve to the Companys creditors pursuant to
NRGs Chapter 11 bankruptcy plan.
|
|
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% Convertible
Perpetual Preferred Stock, (ii) 3.625% Convertible
Perpetual Preferred Stock, and (iii) 5.75% Mandatory
Convertible Preferred Stock.
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 2008 and 2007 (after giving retroactive
effect to the two-for-one stock split effective May 25,
2007) are set forth below:
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|
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|
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|
|
|
|
|
|
|
|
|
|
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|
|
Fourth
|
|
|
Third
|
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|
Second
|
|
|
First
|
|
|
Fourth
|
|
|
Third
|
|
|
Second
|
|
|
First
|
|
Common Stock
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
Price
|
|
2008
|
|
|
2008
|
|
|
2008
|
|
|
2008
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
|
2007
|
|
|
High
|
|
$
|
25.40
|
|
|
$
|
43.95
|
|
|
$
|
45.78
|
|
|
$
|
43.96
|
|
|
$
|
47.19
|
|
|
$
|
45.08
|
|
|
$
|
45.93
|
|
|
$
|
37.10
|
|
Low
|
|
|
14.39
|
|
|
|
22.20
|
|
|
|
38.36
|
|
|
|
34.56
|
|
|
|
38.79
|
|
|
|
34.76
|
|
|
|
35.98
|
|
|
|
27.22
|
|
Closing
|
|
$
|
23.33
|
|
|
$
|
24.75
|
|
|
$
|
42.90
|
|
|
$
|
38.99
|
|
|
$
|
43.34
|
|
|
$
|
42.29
|
|
|
$
|
41.57
|
|
|
$
|
36.02
|
|
NRG had 234,356,717 shares outstanding as of
December 31, 2008, and as of February 9, 2009, there
were 236,232,031 shares outstanding. As of February 9,
2009, there were approximately 72,000 common stockholders
of record.
Dividends
NRG has not declared or paid dividends on its common stock. To
the extent NRG declares such a dividend, 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, 2008, were as follows:
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|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Number
|
|
|
|
|
|
|
|
|
|
|
|
|
of Shares
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchased as
|
|
|
Dollar Value of
|
|
|
|
|
|
|
|
|
|
Part of Publicly
|
|
|
Shares that may be
|
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|
|
Total Number of
|
|
|
Average Price
|
|
|
Announced Plans
|
|
|
Purchased Under the
|
|
For the Year Ended December 31, 2008
|
|
Shares Purchased
|
|
|
Paid per Share
|
|
|
or Programs
|
|
|
Plans or Programs
|
|
|
First quarter
|
|
|
1,281,600
|
|
|
$
|
42.73
|
|
|
|
1,281,600
|
|
|
$
|
160,008,401
|
|
Second quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
160,008,401
|
|
Third quarter
|
|
|
3,410,283
|
|
|
|
38.06
|
|
|
|
3,410,283
|
|
|
|
30,226,541
|
|
Fourth quarter
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,226,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total for 2008
|
|
|
4,691,883
|
|
|
$
|
39.33
|
|
|
|
4,691,883
|
|
|
$
|
30,226,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In December 2007, the Company initiated its 2008 Capital
Allocation Plan, discussed in Item 15
Note 13, Capital Structure, with the repurchase of
2,037,700 shares of NRG common stock during that month for
approximately $85 million. In February 2008, the
Companys Board of Directors authorized an additional
$200 million in common share repurchases that would raise
the total 2008 Capital Allocation Plan to approximately
64
$300 million. In the first quarter 2008, the Company
repurchased 1,281,600 shares of NRG common stock for
approximately $55 million. In the third quarter 2008, the
Company repurchased an additional 3,410,283 of NRG common stock
in the open market for approximately $130 million. As of
December 31, 2008, NRG had repurchased a total of
6,729,583 shares of NRG common stock at a cost of
approximately $270 million as part of its 2008 Capital
Allocation Plan. On October 30, 2008, the Company announced
its 2009 Capital Allocation Plan to purchase an additional
$300 million in common stock. Share repurchase under the
Capital Allocation Plans may be made from time to time at market
prices as permitted by securities laws and other requirements,
are subject to market conditions and other factors, and may be
discontinued at any time.
Securities
Authorized for Issuance under Equity Compensation
Plans
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c)
|
|
|
|
|
|
|
(b)
|
|
|
Number of Securities
|
|
|
|
(a)
|
|
|
Weighted-Average Exercise
|
|
|
Remaining Available
|
|
|
|
Number of Securities
|
|
|
Price of Outstanding
|
|
|
for Future Issuance
|
|
|
|
to be Issued Upon
|
|
|
Options, Warrants and
|
|
|
Under Compensation
|
|
|
|
Exercise of
|
|
|
Rights (Excluding
|
|
|
Plans (Excluding
|
|
|
|
Outstanding Options,
|
|
|
Securities Reflected in
|
|
|
Securities Reflected
|
|
Plan Category
|
|
Warrants and Rights
|
|
|
Column (a)
|
|
|
in Column (a))
|
|
|
Equity compensation plans approved by security holders
|
|
|
6,650,080
|
|
|
$
|
25.84
|
|
|
|
6,798,074
|
(a)
|
Equity compensation plans not approved by security holders
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
6,650,080
|
|
|
$
|
25.84
|
|
|
|
6,798,074
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Consists of NRG Energy, Inc.s
Long-Term Incentive Plan, or the LTIP, and NRG Energy,
Inc.s Employee Stock Purchase Plan, or the ESPP. 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 6,798,074 and 7,941,758 shares of common
stock remaining available for grants of awards under NRGs
LTIP as of December 31, 2008 and 2007, respectively. The
ESPP was approved by the Companys stockholders on
May 14, 2008. There were 500,000 shares reserved from
the Companys treasury shares for the ESPP. There were
500,000 shares remaining under the ESPP as of
December 31, 2008. In January 2009, 41,706 shares were
issued to employees accounts from the treasury stock reserve for
the ESPP.
|
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, 2008 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
|
|
|
|
Dec-2004
|
|
|
|
Dec-2005
|
|
|
|
Dec-2006
|
|
|
|
Dec-2007
|
|
|
|
Dec-2008
|
|
NRG Energy, Inc.
|
|
|
$
|
100.00
|
|
|
|
$
|
160.58
|
|
|
|
$
|
209.89
|
|
|
|
$
|
249.49
|
|
|
|
$
|
386.10
|
|
|
|
$
|
207.84
|
|
S&P 500
|
|
|
|
100.00
|
|
|
|
|
111.22
|
|
|
|
|
116.68
|
|
|
|
|
135.11
|
|
|
|
|
142.53
|
|
|
|
|
89.80
|
|
UTY
|
|
|
$
|
100.00
|
|
|
|
$
|
126.23
|
|
|
|
$
|
149.50
|
|
|
|
$
|
179.67
|
|
|
|
$
|
213.76
|
|
|
|
$
|
155.45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 as well as the retroactive
effect of the two-for-one stock split effective May 25,
2007. For additional information refer to
Item 15 Note 3, Discontinued Operations
Business Acquisition and Disposition, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In millions unless otherwise noted)
|
|
|
Statement of income data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,885
|
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
$
|
2,080
|
|
Total operating costs and expenses
|
|
|
5,156
|
|
|
|
5,060
|
|
|
|
4,720
|
|
|
|
2,290
|
|
|
|
1,848
|
|
Income from continuing operations, net
|
|
|
1,016
|
|
|
|
569
|
|
|
|
543
|
|
|
|
68
|
|
|
|
157
|
|
Income from discontinued operations, net
|
|
|
172
|
|
|
|
17
|
|
|
|
78
|
|
|
|
16
|
|
|
|
29
|
|
Net income
|
|
|
1,188
|
|
|
|
586
|
|
|
|
621
|
|
|
|
84
|
|
|
|
186
|
|
Common share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic shares outstanding average
|
|
|
235
|
|
|
|
240
|
|
|
|
258
|
|
|
|
169
|
|
|
|
199
|
|
Diluted shares outstanding average
|
|
|
275
|
|
|
|
288
|
|
|
|
301
|
|
|
|
171
|
|
|
|
201
|
|
Shares outstanding end of year
|
|
|
234
|
|
|
|
237
|
|
|
|
245
|
|
|
|
161
|
|
|
|
174
|
|
Per share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations basic
|
|
|
4.09
|
|
|
|
2.14
|
|
|
|
1.90
|
|
|
|
0.28
|
|
|
|
0.78
|
|
Income from continuing operations diluted
|
|
|
3.66
|
|
|
|
1.95
|
|
|
|
1.78
|
|
|
|
0.28
|
|
|
|
0.78
|
|
Net income basic
|
|
|
4.82
|
|
|
|
2.21
|
|
|
|
2.21
|
|
|
|
0.38
|
|
|
|
0.93
|
|
Net income diluted
|
|
|
4.29
|
|
|
|
2.01
|
|
|
|
2.04
|
|
|
|
0.38
|
|
|
|
0.93
|
|
Book value
|
|
|
26.69
|
|
|
|
19.48
|
|
|
|
19.48
|
|
|
|
11.31
|
|
|
|
13.14
|
|
Business metrics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations
|
|
$
|
1,434
|
|
|
$
|
1,517
|
|
|
$
|
408
|
|
|
$
|
68
|
|
|
$
|
645
|
|
Liquidity position
|
|
|
4,124
|
(a)
|
|
|
2,715
|
|
|
|
2,227
|
|
|
|
758
|
|
|
|
1,600
|
|
Ratio of earnings to fixed charges
|
|
|
3.62
|
|
|
|
2.28
|
|
|
|
2.38
|
|
|
|
1.57
|
|
|
|
1.93
|
|
Ratio of earnings to fixed charges and preference dividends
|
|
|
3.17
|
|
|
|
2.02
|
|
|
|
2.09
|
|
|
|
1.32
|
|
|
|
1.92
|
|
Return on equity
|
|
|
16.71
|
%
|
|
|
10.65
|
%
|
|
|
10.98
|
%
|
|
|
3.77
|
%
|
|
|
6.91
|
%
|
Ratio of debt to total capitalization
|
|
|
47.57
|
%
|
|
|
55.70
|
%
|
|
|
57.38
|
%
|
|
|
44.91
|
%
|
|
|
44.57
|
%
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
8,492
|
|
|
$
|
3,562
|
|
|
$
|
3,083
|
|
|
$
|
2,197
|
|
|
$
|
2,119
|
|
Current liabilities
|
|
|
6,581
|
|
|
|
2,277
|
|
|
|
2,032
|
|
|
|
1,357
|
|
|
|
1,090
|
|
Property, plant and equipment, net
|
|
|
11,545
|
|
|
|
11,320
|
|
|
|
11,546
|
|
|
|
2,559
|
|
|
|
2,639
|
|
Total assets
|
|
|
24,808
|
|
|
|
19,274
|
|
|
|
19,436
|
|
|
|
7,467
|
|
|
|
7,906
|
|
Long-term debt, including current maturities and capital leases
|
|
|
8,168
|
|
|
|
8,361
|
|
|
|
8,726
|
|
|
|
2,456
|
|
|
|
3,220
|
|
Total stockholders equity
|
|
$
|
7,109
|
|
|
$
|
5,504
|
|
|
$
|
5,658
|
|
|
$
|
2,231
|
|
|
$
|
2,692
|
|
N/A Not applicable
|
|
|
(a)
|
|
Includes Funds deposited by
counterparties of $754 as of December 31, 2008, which
represents cash held as collateral from hedge counterparties in
support of energy risk management activities and for which it is
the Companys intention as of December 31, 2008 to
limit the use of these funds.
|
67
The following table provides the details of NRGs operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
|
(In millions)
|
|
|
Energy
|
|
$
|
4,519
|
|
|
$
|
4,265
|
|
|
$
|
3,155
|
|
|
$
|
1,840
|
|
|
$
|
1,181
|
|
Capacity
|
|
|
1,359
|
|
|
|
1,196
|
|
|
|
1,516
|
|
|
|
563
|
|
|
|
612
|
|
Risk management activities
|
|
|
418
|
|
|
|
4
|
|
|
|
124
|
|
|
|
(292
|
)
|
|
|
61
|
|
Contract amortization
|
|
|
278
|
|
|
|
242
|
|
|
|
628
|
|
|
|
9
|
|
|
|
(6
|
)
|
Thermal
|
|
|
114
|
|
|
|
125
|
|
|
|
124
|
|
|
|
124
|
|
|
|
112
|
|
Hedge Reset
|
|
|
|
|
|
|
|
|
|
|
(129
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
197
|
|
|
|
157
|
|
|
|
167
|
|
|
|
156
|
|
|
|
120
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,885
|
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
$
|
2,080
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 includes fair value changes of
economic hedges that did not qualify for cash flow hedge
accounting, ineffectiveness on cash flow hedges and trading
activities. 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 and Texas Genco purchase accounting 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. See
also Item 15 Note 5, Accounting for
Derivative Instruments 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, 2008 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 presents the
results of the Companys operations for the years ended
December 31, 2008, 2007 and 2006. 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 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
regional markets in the United States and select international
markets where its generating assets are located.
As of December 31, 2008, NRG had a total global portfolio
of 189 active operating fossil fuel and nuclear generation
units, at 48 power generation plants, with an aggregate
generation capacity of approximately 24,005 MW, and
approximately 550 MW under construction which includes
partners interests of 275 MW. In addition, NRG has
ownership interests in two wind farms representing an aggregate
generation capacity of 270 MW, which includes partner
interests of 75 MW. Within the US, NRG has one of the
largest and most diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 22,925 MW of fossil fuel and nuclear
generation capacity in 177 active generating units at 43 plants
and ownership interests in two wind farms representing
195 MW of wind generation capacity. These power generation
facilities are primarily located in Texas (approximately
11,010 MW, including the 195 MW from the two wind
farms), the Northeast (approximately 7,020 MW), South
Central (approximately 2,845 MW), and West (approximately
2,130 MW) regions of the US, and approximately 115 MW
of additional generation capacity from the Companys
thermal assets.
69
NRGs principal domestic power plants consist of a mix of
natural gas-, coal-, oil-fired, nuclear and wind facilities,
representing approximately 45%, 33%, 16%, 5% and 1% 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
intermittent, 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
Business Strategy
NRGs business strategy is designed to enhance the
Companys position as a leading wholesale power generation
company in the US. NRG will continue to utilize its asset base
as a platform for growth and development and as a source of cash
flow generation which can be used for the return of capital to
debt and equity holders. The Companys strategy is focused
on: (i) top decile operating performance of its existing
operating assets and enhanced operating performance of the
Companys commercial operations and hedging program;
(ii) repowering of power generation assets at existing
sites and development of new power generation projects; and
(iii) investment in energy-related new businesses and new
technologies where such investments create low to no carbon.
This strategy is supported by the Companys five major
initiatives (FORNRG, RepoweringNRG, econrg, Future
NRG and NRG Global Giving) which are designed to enhance the
Companys competitive advantages in these strategic areas
and allow the Company to surmount the challenges faced by the
power industry in the coming years. This strategy is being
implemented by focusing on the following principles:
Operational Performance The
Company is focused on increasing value from its existing assets.
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. FORNRG is a companywide effort designed to increase
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, monetize or reduce excess working capital and other
assets. The FORNRG accomplishments include both recurring
and one-time improvements measured from a prior base year. For
plant operations, the program measures cumulative current year
benefits using current gross margins multiplied by 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.
In addition to the FORNRG initiative, the Company seeks
to maximize profitability and manage cash flow volatility
through the Companys commercial operations strategy. The
Company 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.
Finally, 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 during business downturns,
including a regular return of capital to its shareholders. NRG
will continue to focus on maintaining operational and financial
controls designed to ensure that the Companys financial
position remains strong.
70
Development 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.
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 capacity that is expected to be supported by
long-term hedging programs, including PPAs, 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 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.
New Businesses and New Technology
NRG is focused on the development and
investment in energy-related new businesses and new technologies
where the benefits of such investments represent significant
commercial opportunities and create a comparative advantage for
the Company, including low or no GHG emitting energy generating
sources, such as nuclear, wind, solar thermal, photovoltaic,
clean coal and gas, and the employment of
post-combustion carbon capture technologies. In 2008, the
Company began to increase its focus on ways to invest in or
support the development of new energy-related businesses and
technologies that could advance its multi-fuel, multi-technology
growth strategy and look for new ways to reduce carbon emissions
from its overall fleet, and we expect to continue to do so in
the future. Furthermore, the Company intends to capitalize on
the high growth opportunities presented by government-mandated
renewable portfolio standards, tax incentives and loan
guaranties for renewable energy projects and new technologies
and expected future carbon regulation. A primary focus of this
strategy is supported by the econrg initiative whereby
NRG is 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. econrg represents NRGs
commitment to environmentally responsible power generation by
addressing the challenges of climate change, clean air and
water, and conservation of our natural resources while taking
advantage of business opportunities that may inure to NRG as a
result of our demonstration and deployment of green
technologies. Within NRG, econrg builds upon a 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 the
Companys employees.
Company-Wide Initiatives In
addition, the Companys overall strategy is also supported
by Future NRG and NRG Global Giving initiatives.
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,
training, development, staffing and recruiting needs. Included
under the Future NRG umbrella is NRG University, which provides
leadership, managerial, supervisory and technical training
programs and individual skill development courses. NRG Global
Giving is designed to enhance respect for the community, which
is one of NRGs core values. Our Global Giving Program
invests NRGs resources to strengthen the communities where
we do business and seeks to make community investments in four
focus areas: community and economic development, education,
environment and human welfare.
Finally, 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.
71
Business
Environment
General Industry Trends impacting the power
industry include (i) the continued constrained credit and
capital markets along with deepening recessionary environment,
and (ii) increased regulatory and political scrutiny. The
industry dynamics and external influences that will affect the
Company and the power generation industry in 2009 and for the
medium term include:
Financial Credit Market Availability and Domestic
Recession A sharp economic downturn in the US
and overseas during 2008 was prompted by a combination of
factors: tight credit markets, speculation and fear regarding
the health of the US and global financial systems, and weaker
economic activity including a global economic recession. Power
generation companies are capital intensive and, as such, rely on
the credit markets for liquidity and for the financing of power
generation investments. In addition, economic recessions
historically result in lower power demand, power prices, and
fuel prices. NRG has a diversified liquidity program, with
$3.4 billion in total liquidity, excluding funds deposited
by counterparties, and a first and second lien structure that
enables significant strategic hedging while reducing
requirements for the posting of cash or letters of credit as
collateral. NRG expects to continue to manage commodity price
volatility through its strategic hedging program, under which
the Company expects to hedge revenues and fuel costs. This
program should provide the Company with the flexibility to enter
into hedges opportunistically, such as when gas prices are
increasing, while at the same time protecting NRG against
longer-term volatility in the commodity markets. The Company
believes that an economic recession is unlikely to have material
impact on the Companys cash generation in the near term
due to the hedged position of its portfolio. NRG transacts with
a diversified pool of counterparties and actively manages our
exposure to any single counterparty. See also Part II,
Item 7 Liquidity and Capital Resources, and
Part II, Item 7a Quantitative and
Qualitative Disclosures about Market Risk for a further
discussion.
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.
Climate Change There is a marked shift
towards federal action to address climate change under the Obama
administration, which has made clear its intention to make
climate change policy a priority for the US through legislation,
regulation, and global leadership. President Obama reiterated
this commitment in his inaugural address. Congressman Waxman,
who sees aggressive action on climate change as a major
priority, was elected chair of the House Energy and Commerce
Committee and announced that a climate change bill would be
delivered out of committee before Memorial Day.
Regional efforts have gained momentum as well. The RGGI
CO2
cap-and-trade program for electric generating units went into
effect on January 1, 2009. California, the Western Climate
Initiative, and the Midwest GHG Accord continue to develop
market based programs in their respective jurisdictions.
Since fossil fueled power plants, particularly coal-fired
plants, are a significant source of GHG emissions both in the US
and globally, it is almost certain that future GHG legislative
and regulatory actions will encompass power plants as well as
other GHG emitting stationary sources. In 2008, 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 US,
4 million tonnes in Germany, and 3 million tonnes in
Australia. NRG emissions subject to RGGI were 12 million
tonnes in 2008. 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 degree to which offsets may be used for
compliance and their price and availability, 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. 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.
72
Infrastructure Development In response to
record peak power demand, tightening reserve margins, and
volatile natural gas prices experienced in recent years, the
power generation industry has added significant capacity for
both transmission and generation. In addition to traditional
gas-fired capacity, much of the new generation would be from
non-fossil fuel sources, including nuclear and renewable
sources. 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. During 2007, 18 gigawatts of previously announced
pulverized coal generation projects were canceled due to
increasing public and political concern regarding carbon
emissions limiting the pace of development. During 2008, the
credit market crisis severely constrained the industrys
ability to finance power projects. Despite the challenges
presented by financing availability and carbon legislation
constraints, NRG believes the long-term demand for power
generation will continue to require new generation.
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 US 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;
|
|
|
|
capability and reliability of the physical electricity and gas
systems;
|
73
|
|
|
|
|
local transportation systems; and
|
|
|
|
the nature and extent of electricity deregulation.
|
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, 2008, 2007 and 2006, 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 Program
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.
|
On October 30, 2008, the Company announced its 2009 Capital
Allocation Plan to purchase an additional $300 million in
common stock, subject to restrictions under the US securities
laws. As part of the 2009 program, the Company will invest over
$511 million in maintenance and environmental capital
expenditures in the existing assets in 2009 and
$256 million in investment in projects under
RepoweringNRG that are currently under construction or
for which there exists current obligations. Finally, in addition
to scheduled debt amortization payment, in the first quarter
2009 the Company will offer its first lien lenders
$197 million of its 2008 excess cash flow (as defined in
the Senior Credit Facility).
74
Significant
events during the year ended December 31, 2008
Results
of Operations and Financial Condition
|
|
|
|
|
Mark-to-market gains The Companys risk
management activities recognized $414 million in
mark-to-market gains driven by lower energy prices due to the
downward trend in natural gas prices during the second half
2008. High price volatility in energy related commodities during
2008 drove the extreme volatility reported in NRG interim
results of operations and consolidated balance sheets during the
second and third quarters of 2008, due to the commodities
impact on the fair value of our derivative contracts.
|
|
|
|
Liquidity Position The Companys total
liquidity rose $1.4 billion as the declining natural gas
prices increased funds deposited by counterparties by
$754 million. Cash balances grew by $362 million since
the end of 2007 as $1.4 billion of cash provided by
operating activities exceeded cash used for all phases of the
Companys Capital Allocation Program, including
$899 million of capital expenditures, $185 million in
treasury share payments and a $214 million net debt
reduction.
|
|
|
|
Higher energy prices Energy revenues rose 6%
as a result of strong operating performance at the power plants
which allowed the Company to sell generation at higher energy
prices especially in the second quarter 2008.
|
|
|
|
Higher capacity revenues Capacity revenues
rose $163 million as a result of a greater portion of Texas
baseload contracts having a capacity component.
|
|
|
|
Sale of ITISA On April 28, 2008, NRG
completed the sale of its interest in a 156 MW
hydroelectric power plant to Brookfield Renewable Power Inc. The
Company recognized a $164 million after tax gain on the
sale and received $300 million of cash proceeds. See
Item 15 Note 3, Discontinued
Operations, Business Acquisition and Dispositions,
for a further discussion of the activities of ITISA that
have been classified as discontinued operations.
|
|
|
|
Reduced development costs As of
January 1, 2008, the company began to capitalize the STP
units 3 and 4 costs following the docketing of the COLA which
resulted in decline of development costs of $52 million.
|
|
|
|
Lower other income Interest income decreased
by $25 million as the result of lower market interest rates
on cash deposits. In addition, the Company recorded an
impairment charge of $23 million to restructure distressed
investments in commercial paper.
|
|
|
|
Lower interest expense Interest expense
decreased $69 million as the result of the interest savings
on the $531 million debt repayments beginning December 2007
accompanied by a reduction of variable interest rates on
long-term debt.
|
Other
|
|
|
|
|
NINA In March 2008, NRG formed NINA, an NRG
subsidiary focused on marketing, siting, developing, financing
and investing in new advanced design nuclear projects in select
markets across North America, including the planned STP units 3
and 4 that NRG is developing on a 50/50 basis with CPS Energy.
TANE will serve as the prime contractor on all of NINAs
projects, and has partnered with NRG on the NINA venture, and
received a 12% equity ownership in NINA in exchange for a
$300 million investment in NINA in six annual installments
of $50 million, the first of which was received during 2008
and the last three of which are subject to certain conditions.
On February 12, 2009, the Company announced that NINA
completed negotiations for the EPC agreement with TANE to build
the STP expansion. Concurrent with the execution of the EPC
agreement, NINA will enter into a $500 million credit
facility with Toshiba to finance the cost of long-lead materials
for STP 3 and 4.
|
75
|
|
|
|
|
Unsolicited Exelon Proposal On
October 19, 2008, the Company received an unsolicited
proposal from Exelon Corporation to acquire all of the
outstanding shares of the Company and on November 12, 2008,
Exelon announced a tender offer for all of the Companys
outstanding common stock. On January 7, 2009, Exelon
extended the tender offer to February 25, 2009, and
indicated that further extensions may follow. NRGs Board
of Directors, after carefully reviewing the proposal,
unanimously concluded that the proposal was not in the best
interests of the stockholders and has recommended that NRG
stockholders not tender their shares. In addition, on
January 30, 2009 Exelon announced a proposed slate of nine
nominees for election to the NRG Board at the 2009 Annual
Meeting of Stockholders, together with a proposal to increase
the number of NRG directors from 12 to 19.
|
|
|
|
Sherbino Wind Farm On October 22, 2008,
NRG and its 50/50 joint venture partner, BP, announced the
completion of its 150 MW Sherbino wind farm. Since NRG has
a 50 percent ownership, Sherbino will provide the Company a
net capacity of 75 MW.
|
|
|
|
Elbow Creek Wind Farm On December 29,
2008, NRG, through Padoma, announced the completion of its Elbow
Creek project, a wholly-owned 120 MW wind farm in Howard
County near Big Spring, Texas. The Company funded and developed
this wind farm which consists of 53 Siemens wind turbine
generators, each capable of generating up to 2.3 MW of
power.
|
76
Consolidated
Results of Operations
2008
compared to 2007
The following table provides selected financial information for
NRG Energy, Inc., for the years ended December 31, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change%
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
4,519
|
|
|
$
|
4,265
|
|
|
|
6
|
%
|
Capacity revenue
|
|
|
1,359
|
|
|
|
1,196
|
|
|
|
14
|
|
Risk management activities
|
|
|
418
|
|
|
|
4
|
|
|
|
N/A
|
|
Contract amortization
|
|
|
278
|
|
|
|
242
|
|
|
|
15
|
|
Thermal revenue
|
|
|
114
|
|
|
|
125
|
|
|
|
(9
|
)
|
Other revenues
|
|
|
197
|
|
|
|
157
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
6,885
|
|
|
|
5,989
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,598
|
|
|
|
3,378
|
|
|
|
7
|
|
Depreciation and amortization
|
|
|
649
|
|
|
|
658
|
|
|
|
(1
|
)
|
General and administrative
|
|
|
319
|
|
|
|
309
|
|
|
|
3
|
|
Development costs
|
|
|
46
|
|
|
|
101
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,612
|
|
|
|
4,446
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets
|
|
|
|
|
|
|
17
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
2,273
|
|
|
|
1,560
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
59
|
|
|
|
54
|
|
|
|
9
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
(100
|
)
|
Other income, net
|
|
|
17
|
|
|
|
55
|
|
|
|
(69
|
)
|
Refinancing expenses
|
|
|
|
|
|
|
(35
|
)
|
|
|
(100
|
)
|
Interest expense
|
|
|
(620
|
)
|
|
|
(689
|
)
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(544
|
)
|
|
|
(614
|
)
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations before income tax
expense
|
|
|
1,729
|
|
|
|
946
|
|
|
|
83
|
|
Income tax expense
|
|
|
713
|
|
|
|
377
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
1,016
|
|
|
|
569
|
|
|
|
79
|
|
Income from discontinued operations, net of income tax expense
|
|
|
172
|
|
|
|
17
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
1,188
|
|
|
$
|
586
|
|
|
|
103
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMbtu)
|
|
|
8.85
|
|
|
|
7.12
|
|
|
|
24
|
%
|
N/A Not applicable
77
Operating
Revenues
Operating revenues increased by $896 million for the year
ended December 31, 2008, compared to 2007. This was due to:
|
|
|
|
|
Energy revenues increased $254 million
during the year ended December 31, 2008, compared to the
same period in 2007:
|
|
|
|
|
o
|
Texas increased $172 million, with
$219 million of this increase driven by higher prices,
offset by $47 million reduced generation. The price
variance was attributable to a more favorable mix of merchant
versus contract sales, as well as a 28% increase in merchant
prices partially offset by a 14% decrease in contract energy
prices. The 839 thousand MWh or 2% reduction in generation was
comprised of a 3% reduction from nuclear plant generation, a 14%
reduction from gas plant generation, offset by a 1% increase in
coal plant generation. The reduction in gas plant generation was
attributable to the effects of hurricane Ike in September 2008.
|
|
|
o
|
Northeast decreased $40 million, with
$66 million reduced generation offset by a $26 million
increase driven by higher energy prices. The decline due to
generation was driven by a net 6% reduction in the
regions generation, due to a decrease in oil-fired
generation as a result of higher average oil prices as well as
decrease in gas-fired generation related to a cooler summer in
2008 compared to 2007. The increase due to energy prices
reflects an average 6% rise in merchant energy prices offset by
lower contract revenue, driven by higher costs required to
service the PJM contracts, as a result of the increase in market
energy prices.
|
|
|
o
|
South Central increased $74 million,
attributable to higher merchant energy revenues. The growth in
merchant energy revenues reflected 577 thousand more merchant
MWh sold, as a decrease in contract load MWh allowed more sales
to the merchant market at higher prices.
|
|
|
o
|
West increased $35 million due to the
dispatch of the El Segundo plant outside of the tolling
agreement in 2008. In 2007, no such dispatch occurred.
|
|
|
|
|
|
Capacity revenues increased $163 million
during the year ended December 31, 2008, compared to the
same period in 2007:
|
|
|
|
|
o
|
Texas increased $130 million due to a
greater proportion of base-load contracts, which contain a
capacity component.
|
|
|
o
|
Northeast increased $13 million
reflecting $31 million higher capacity revenues in the PJM
and NEPOOL markets offset by a $18 million reduction in
capacity revenue in NYISO.
|
|
|
o
|
South Central increased $12 million due
to a $10 million higher capacity payment from the
regions cooperative customers and an $8 million rise
in RPM capacity payments from the PJM market. These increases
were offset by a $6 million reduction related to lower
contract volume to other customers.
|
|
|
o
|
West increased $3 million due to a
tolling arrangement at Long Beach plant offset by the reduction
of revenue from the El Segundo tolling arrangement.
|
|
|
|
|
|
Contract amortization revenues increased
$36 million during the year ended December 31, 2008,
compared to the same period in 2007 due to the volume of
contracted energy affected by a greater spread between contract
prices and market prices used in the Texas Genco purchase
accounting.
|
|
|
|
Other revenues increased by $40 million
during the year ended December 31, 2008, compared to the
same period in 2007. The increases arose from greater ancillary
services revenue of $28 million and increased activity in
the trading of emission allowances and carbon financial
instruments of $21 million. These increases were offset by
$14 million in lower gas and coal trading activities.
|
78
|
|
|
|
|
Risk management activities revenues from risk
management activities include economic hedges that did not
qualify for cash flow hedge accounting, ineffectiveness on cash
flow hedges and trading activities. Such revenues increased by
$414 million during the year ended December 31, 2008,
compared to the same period in 2007. The breakdown of changes by
region was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Thermal
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Net (losses)/gains on settled positions, or financial revenues
|
|
$
|
(95
|
)
|
|
$
|
3
|
|
|
$
|
(16
|
)
|
|
$
|
1
|
|
|
$
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
(25
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(38
|
)
|
Reversal of previously recognized unrealized losses/(gains) on
settled positions related to trading activity
|
|
|
1
|
|
|
|
(14
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
(32
|
)
|
Net unrealized gains on open positions related to economic hedges
|
|
|
400
|
|
|
|
96
|
|
|
|
|
|
|
|
4
|
|
|
|
500
|
|
Net unrealized gains on open positions related to trading
activity
|
|
|
37
|
|
|
|
13
|
|
|
|
45
|
|
|
|
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results
|
|
|
413
|
|
|
|
82
|
|
|
|
26
|
|
|
|
4
|
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gains
|
|
$
|
318
|
|
|
$
|
85
|
|
|
$
|
10
|
|
|
$
|
5
|
|
|
$
|
418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs 2008 gain is comprised of $525 million of
mark-to-market gains and $107 million in settled losses, or
financial revenue. Of the $525 million of mark-to-market
gains, the $38 million loss represents the reversal of
mark-to-market
gains recognized on economic hedges and the $32 million
loss represents the reversal of mark-to-market gains recognized
on trading activity. Both of these losses ultimately settled as
financial revenues during 2008. The $500 million gain from
economic hedge positions included a $524 million increase
in value of forward sales of electricity as the result of the
reduction in forward power and gas prices at the close of the
year-ended December 31, 2008. These hedges are considered
effective economic hedges that do not receive cash flow hedge
accounting treatment. In addition there was a $24 million
loss primarily from hedge accounting ineffectiveness related to
gas trades in the Texas region which was driven by decreasing
forward gas prices while forward power prices declined at a
slower pace. NRG also recognized a $95 million unrealized
gain associated with the companys trading activity. This
gain was primarily due to declining forward electricity and fuel
prices.
Since these hedging activities are intended to mitigate the risk
of commodity price movements on revenues the changes in such
results should not be viewed in isolation, but rather should be
taken together with the effects of pricing and cost changes on
energy revenues. During and throughout 2008, NRG hedged a
portion of the Companys 2008 through 2013 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.
Cost
of Operations
Cost of operations increased $220 million during the year
ended December 31, 2008, compared to the same period in
2007 but it decreased as a percentage of revenues from 56% for
the year ended 2007 compared to 52% for the year ended 2008.
|
|
|
|
|
Cost of energy increased $213 million during
the year ended December 31, 2008, compared to the same period in
2007 and as a percentage of revenue it decreased from 41% for
2007 as compared to 38% for 2008. This increase was due to :
|
|
|
|
|
o
|
Texas Cost of energy increased
$59 million due to a net increase in fuel expense and
ancillary service costs offset by reductions in nuclear fuel
expenses, purchased power expense and amortization of contracts
cost.
|
79
|
|
|
|
|
Fuel expense Natural gas costs rose
$99 million due to an increase of 28% in average natural
gas prices, offset by a 14% decrease in gas-fired generation. In
addition, coal costs increased by $44 million a result of
higher coal prices and the settlement payment related to a coal
contract dispute. These increases were offset by a decrease of
$19 million in nuclear fuel expense as amortization of
nuclear fuel inventory established under Texas Genco purchase
accounting ended in early 2008.
|
|
|
|
Purchased energy Purchased energy expense
decreased $26 million as a result of lower forced outage
rates at the regions base-load plants.
|
|
|
|
Ancillary service expense Ancillary services
and other costs increased by $14 million as a result of
higher ERCOT ISO fees offset by reduced purchased ancillary
services costs.
|
|
|
|
Fuel contract amortization Amortized contract
costs decreased by $59 million due to a $36 million
decrease in the amortization of water supply contracts which
ended in 2007. In addition, the amortization of coal contracts
decreased by a net $22 million as a result of a reduction
in expense related to in-the-money coal contract amortization.
These contracts were established under Texas Genco purchase
accounting.
|
|
|
|
|
o
|
Northeast Cost of energy increased
$54 million due to higher fuel costs. Coal costs increased
$61 million due to higher coal prices and fuel
transportation surcharges. Natural gas costs rose
$22 million as a result of 32% higher average natural gas
prices, despite 12% lower generation. These increases were
offset by a $27 million reduction in oil costs as a result
of 55% lower oil-fired generation.
|
|
|
o
|
South Central Cost of energy increased
$56 million due to higher fuel costs and increased
purchased energy expense.
|
|
|
|
|
|
Fuel expense Coal costs increased
$16 million resulting from an increase in coal consumption
and higher fuel transportation surcharges; natural gas costs
rose by $14 million as the regions peaker plants ran
extensively to support transmission system stability after
hurricane Gustav.
|
|
|
|
Purchased energy Higher purchased energy
expenses of $16 million reflected higher natural gas costs
for tolling contracts.
|
|
|
|
Transmission costs Increased by
$9 million due to additional point-to-point transmission
costs driven by an increase in merchant energy sales.
|
|
|
|
|
o
|
West Cost of energy increased
$30 million due to the dispatch of the El Segundo plant
outside of the tolling agreement in 2008. In 2007, no such
dispatch occurred.
|
|
|
|
|
|
Other operating costs increased
$7 million during the year ended December 31, 2008
compared to the same period in 2007. This increase was due to:
|
|
|
|
|
o
|
Texas increased $30 million due to a
second planned outage at STP and the acceleration of planned
outages at the base-load plants.
|
|
|
o
|
Northeast decreased $3 million due to
$18 million lower operating and maintenance expenses
resulting from less outage work at the Norwalk plants and Indian
River plants. This was offset by a $16 million increase in
utilities cost. The 2007 utilities cost included a benefit of
$19 million due to a lower than planned settlement of the
station service agreement with CL&P.
|
|
|
o
|
South Central decreased by $10 million
due to reduction in major maintenance expense. The 2007 expense
included more extensive outage work that was performed at Big
Cajun II plant.
|
|
|
o
|
West decreased by $4 million due to a
$3 million reduction in lease expenses and an environmental
liability of $2 million which was recognized in 2007
related to the El Segundo plant.
|
80
General
and Administrative
NRGs G&A costs for the year ended December 31,
2008, increased by $10 million compared to 2007, and as a
percentage of revenues was 5% in both 2008 and 2007.
|
|
|
|
|
Wage and benefit costs increased
$19 million attributable to higher wages and related
benefits cost increases.
|
|
|
|
Consultant cost increased by $3 million
resulting from $8 million spent on Exelons exchange
offer offset by a $5 million reduction in information
technology consultants.
|
|
|
|
Franchise tax The Companys Louisiana
state franchise tax decreased by approximately $4 million.
Prior year franchise tax was assessed based on the
Companys total debt and equity that increased
significantly following the acquisition of Texas Genco.
|
|
|
|
Insurance cost decreased by $4 million
due to favorable rates.
|
Development
Costs
NRGs development costs for the year ended
December 31, 2008 decreased by $55 million compared to
2007. These costs were due to the Companys
RepoweringNRG projects:
|
|
|
|
|
Texas STP units 3 and 4 projects No
development expense was reflected in results of operations for
2008 as NRG began to capitalize STP units 3 and 4 development
costs incurred after January 1, 2008, following the
NRCs docketing of the Companys COLA in late 2007.
The Company recorded $52 million in development expenses
during 2007.
|
|
|
|
Wind projects The Company incurred
$21 million in costs related to wind development which is a
$4 million decrease from the same period in 2007.
|
|
|
|
Other projects The Company incurred
$25 million in development costs related to other domestic
RepoweringNRG projects in 2008, which decreased
$7 million from the same period in 2007 as a result of the
capitalization of costs to develop the El Segundo Energy Center
in 2008.
|
Gain
on Sale of Assets
The Company reported no gains on sales of assets for 2008. For
2007, NRGs gain on the sale of assets was
$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 $18 million.
Equity
in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates for
the year ended December 31, 2008, increased by
$5 million compared to 2007. This increase was due to a
$9 million mark-to-market unrealized gain on a forward
contract for a natural gas swap executed to hedge the future
power generation of Sherbino, offset by a $4 million
reduction in earnings from international equity investments.
Other
Income, Net
NRGs other income, net decreased by $38 million for
2008 compared to the same period in 2007. The Company recorded a
further $23 million impairment charge in 2008 to
restructure distressed investments in commercial paper, for
which an $11 million impairment charge was taken in the
fourth quarter of 2007. This 2008 impairment charge, along with
cash receipts of $2 million, reduced the carrying value of
the commercial paper to $7 million. In addition, the 2008
results reflect reduced interest income of $25 million from
lower market interest rates on cash deposits.
81
Interest
Expense
NRGs interest expense decreased by $69 million for
2008 compared to the same period in 2007. This decrease was due
to interest savings on $531 million debt repayments
accompanied by a reduction on the variable interest rates on
long-term debt. The debt repayments included a $300 million
prepayment in December 2007 and an additional payment of
$143 million in March 2008 of the Term Loan Facility in
connection with the mandatory offer under the Senior Credit
Facility. Interest capitalized on RepoweringNRG projects
under construction also contributed to this decrease in interest
expense. Offsetting this decrease was the $45 million
payment made to the Credit Suisse Group, or CS, for the benefit
of NRG Common Stock Finance I LLC, or CSF I, in August 2008
to early settle the embedded derivative in the Companys
CSF I notes and preferred interests.
NRG has 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, 2008, NRG had a deferred loss of
$90 million in other comprehensive income compared to a
deferred loss of $31 million in 2007.
Refinancing
Expense
There was no refinancing activity in 2008. In 2007, NRG
completed a $4.4 billion refinancing of the Companys
Senior Credit Facility, resulting in a charge of
$35 million from the write-off of deferred financing costs
as the lenders for 45% of the Term Loan Facility either exited
the financing or reduced their holdings and were replaced by
other institutions.
Income
Tax Expense
Income tax expense increased by $336 million for the year
ended December 31, 2008, compared to 2007. The effective
tax rate was 41.2% and 39.9% for the year ended
December 31, 2008 and 2007, respectively
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions
|
|
|
|
except as otherwise stated)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,729
|
|
|
$
|
946
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
605
|
|
|
|
331
|
|
State taxes, net of federal benefit
|
|
|
73
|
|
|
|
46
|
|
Foreign operations
|
|
|
(10
|
)
|
|
|
(13
|
)
|
Subpart F taxable income
|
|
|
2
|
|
|
|
|
|
Valuation allowance, including change in state effective rate
|
|
|
(12
|
)
|
|
|
6
|
|
Change in state effective tax rate
|
|
|
(11
|
)
|
|
|
|
|
Change in local German effective tax rates
|
|
|
|
|
|
|
(29
|
)
|
Foreign dividends
|
|
|
32
|
|
|
|
26
|
|
Non-deductible interest
|
|
|
26
|
|
|
|
10
|
|
Permanent differences, reserves, other
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
713
|
|
|
$
|
377
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
41.2
|
%
|
|
|
39.9
|
%
|
The increase in income tax expense was primarily due to:
|
|
|
|
|
Increase in income pre-tax income increased
by $783 million, with a corresponding increase of
$305 million in income tax expense.
|
82
|
|
|
|
|
Permanent differences the Companys
effective tax rate differs from the US statutory rate of 35% due
to:
|
|
|
|
|
o
|
Taxable dividends from foreign subsidiaries
due to the provision of deferred taxes in 2008
on foreign income no longer expected to be permanently
reinvested overseas offset by decreased dividends from foreign
operations in the current year, tax expense increased by
approximately $6 million as compared to 2007.
|
|
|
o
|
Non-deductible interest on CAGR Settlement
the Companys $45 million settlement
of the embedded derivative in its CSF I notes and preferred
interests resulted in an additional income tax expense of
$16 million in 2008 as compared to the same period in 2007.
|
|
|
o
|
Change in German tax rate as a result of
revaluing our deferred tax assets, income tax expense benefited
by $29 million in 2007, with no comparable benefit in 2008.
|
|
|
o
|
Valuation Allowance the Company generated
capital gains in 2008 primarily due to the sale of ITISA and
derivative contracts that are eligible for capital treatment for
tax purposes. These gains enabled NRG to reduce our valuation
allowance against capital loss carryforwards. In addition,
applicable changes to the state and local effective tax rate are
captured in the current period. This resulted in a decrease of
$18 million income tax expense in 2008 as compared to 2007.
|
|
|
o
|
Change in state effective tax rate the
Company reduced its domestic state and local deferred income tax
rate from 7% to 6% in the current period.
|
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
Discontinued operations included ITISA results for 2008 and the
same period in 2007. NRG classifies as discontinued operations
the income from operations and gains/losses recognized on the
sale of projects that were sold or have met the required
criteria for such classification pending final disposition. For
2008 and the same period in 2007, NRG recorded income from
discontinued operations, net of income tax expense, of
$172 million and $17 million, respectively. NRG closed
the sale of ITISA during the second quarter 2008 and recognized
an after-tax gain of $164 million.
83
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
|
|
|
|
(97
|
)
|
Contract amortization
|
|
|
242
|
|
|
|
628
|
|
|
|
(61
|
)
|
Thermal revenue
|
|
|
125
|
|
|
|
124
|
|
|
|
1
|
|
Hedge Reset
|
|
|
|
|
|
|
(129
|
)
|
|
|
(100
|
)
|
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
84
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:
|
|
|
|
|
o
|
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.
|
|
|
o
|
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.
|
|
|
o
|
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.
|
|
|
o
|
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:
|
|
|
|
|
o
|
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.
|
|
|
o
|
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.
|
|
|
o
|
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
|
85
|
|
|
|
|
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.
|
|
|
|
|
o
|
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:
|
|
|
|
|
o
|
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%.
|
|
|
o
|
Physical gas sales decreased by
$7 million due to the lower sales of excess natural gas.
|
|
|
o
|
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 economic hedges that do not
qualify for hedge accounting, ineffectiveness on cash flow
hedges, and trading activities. 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
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
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 (losses)/gains on open positions related to
trading activity
|
|
|
(1
|
)
|
|
|
26
|
|
|
|
24
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results
|
|
|
(66
|
)
|
|
|
(16
|
)
|
|
|
5
|
|
|
|
(77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative (losses)/gains
|
|
$
|
(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 $20 million increase in the value of forward
sales of electricity and fuel due to favorable power and gas
prices and a
86
$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:
|
|
|
|
|
o
|
Texas cost of energy decreased by
$95 million for the year ended December 31, 2007,
compared to 2006. This decrease 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 decrease was due to a
reduction of 2.7 million MWh in gas-fired generation as a
result of cooler summer weather, coupled with greater economic
purchases from the 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 the 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.
|
|
|
|
|
o
|
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.
|
|
|
o
|
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.
|
87
|
|
|
|
o
|
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 include 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:
|
|
|
|
|
o
|
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.
|
|
|
o
|
Northeast other operating costs increased by
$18 million due to increased staffing costs and higher
maintenance costs.
|
|
|
o
|
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.
|
|
|
o
|
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 increase was because the states franchise tax was
assessed based on the Companys total debt and equity that
rose significantly following the acquisition of Texas Genco.
|
|
|
|
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.
|
88
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 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.
|
89
|
|
|
|
|
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 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 Facility 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
Facility 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
Loan Facility 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
|
%
|
90
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:
|
|
|
|
|
o
|
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.
|
|
|
o
|
Taxable dividends from foreign subsidiaries
in January 2007, the Company transferred the
proceeds from the sale of its Flinders assets to the US creating
additional income tax expense of approximately $25 million.
|
|
|
o
|
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.
|
|
|
o
|
Non-deductible interest interest expense from
the stock buybacks from Phase I of the Companys Capital
Allocation Program was non-deductible for income tax purposes,
thus increasing income tax expense by approximately
$7 million.
|
|
|
o
|
Change in state effective tax rate the state
effective tax rate remained 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.
|
|
|
o
|
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.
|
|
|
o
|
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
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.
91
Results
of Operations Regional Discussions
Texas
Region
2008
compared to 2007
The following table provides selected financial information for
the Texas region for the year ended December 31, 2008, and
the period ended December 31, 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
2,870
|
|
|
$
|
2,698
|
|
|
|
6
|
%
|
Capacity revenue
|
|
|
493
|
|
|
|
363
|
|
|
|
36
|
|
Risk management activities
|
|
|
318
|
|
|
|
(33
|
)
|
|
|
N/A
|
|
Contract amortization
|
|
|
255
|
|
|
|
219
|
|
|
|
16
|
|
Other revenues
|
|
|
90
|
|
|
|
40
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
4,026
|
|
|
|
3,287
|
|
|
|
22
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
1,240
|
|
|
|
1,181
|
|
|
|
5
|
|
Depreciation and amortization
|
|
|
451
|
|
|
|
469
|
|
|
|
(4
|
)
|
Other operating expenses
|
|
|
650
|
|
|
|
668
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
1,685
|
|
|
$
|
969
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
47,806
|
|
|
|
49,220
|
|
|
|
(3
|
)
|
MWh generated (in thousands)
|
|
|
46,937
|
|
|
|
47,779
|
|
|
|
(2
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
96.53
|
|
|
$
|
62.00
|
|
|
|
56
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
2,719
|
|
|
|
2,707
|
|
|
|
|
|
CDDs 30 year rolling average
|
|
|
2,647
|
|
|
|
2,647
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
1,961
|
|
|
|
1,949
|
|
|
|
1
|
|
HDDs 30 year rolling average
|
|
|
2,007
|
|
|
|
1,997
|
|
|
|
1
|
%
|
|
|
|
(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 $716 million for the year
ended December 31, 2008, compared to the same period in
2007, primarily due to:
|
|
|
|
|
Energy revenues increased by
$172 million due to higher merchant energy revenue as a
result of higher power prices and sales volumes offset by lower
contract energy revenue.
|
|
|
|
Capacity revenue increased by
$130 million due to a greater proportion of base-load
contracts which contain a capacity component.
|
|
|
|
Risk management activities an increase of
$351 million was primarily due to $479 million in
greater unrealized derivative gains offset by $128 million
in greater realized losses on settled financial transactions.
These changes reflect a reduction in forward power and gas
prices at the close of the year ended December 31, 2008.
|
92
These increases were offset by:
|
|
|
|
|
Cost of energy increased by $59 million
reflecting the effects of increased natural gas and coal prices.
|
Operating
Revenues
Total operating revenues from the Texas region increased by
$739 million during the year ended December 31, 2008,
compared to 2007 due to the following:
|
|
|
|
|
Risk management activities gains of
$318 million were recognized for the year ended
December 31, 2008, compared to a $33 million loss in
the same period in 2007. The $318 million included
$413 million of unrealized mark-to-market gains and
$95 million in settled losses, or financial revenue. The
$413 million was the net effect of a $400 million gain
from economic hedge positions and a $25 million loss on
reversals of mark-to-market gains on economic hedges. In
addition, there were $37 million in unrealized
mark-to-market gains on trading transactions combined with a
$1 million gain on reversals of mark-to-market losses on
trading activity. The $400 million gain from economic
hedges incorporated $424 million in unrealized gains in the
value of forward sales of electricity and fuel driven by lower
power and natural gas prices. These hedges were considered
effective economic hedges that do not receive cash flow hedge
accounting treatment. The remaining $24 million in losses
were from hedge ineffectiveness which was driven by decreasing
gas prices while power prices decreased at a slower pace.
|
|
|
|
Energy revenues increased by
$172 million due to:
|
|
|
|
|
o
|
Energy prices increased by $219 million
due to a more favorable mix of merchant versus contract sales
resulting in a 28% increase in merchant prices offset by a 14%
decrease in contract energy prices.
|
|
|
o
|
Generation decreased by 839 thousand MWh or
2%. This decrease in generation was due to a 3% decline in
nuclear generation at STP, as a result of additional plant
outages, and a 14% decline in overall gas plant generation for
the year ended December 2008. Hurricane Ike in September 2008
caused major damage to the Houston area transmission grid which
reduced significantly the demand for power causing a decrease in
gas-fired generation. These declines were offset by a 1%
increase in coal generation in 2008.
|
|
|
|
|
|
Capacity revenue increased by
$130 million due to a greater proportion of base-load
contracts which contain a capacity component.
|
|
|
|
Other revenues increased by $50 million
related to a $23 million increase in ancillary services
revenue in 2008, a $22 million increase of allocations for
trading of emission allowances and carbon financial instruments,
and increased activity in trading natural gas and coal of
$4 million.
|
|
|
|
Contract amortization revenue increased by
$36 million due to the volume of contracted energy being
positively affected by a greater spread between contract prices
and market prices used in the Texas Genco purchase accounting.
|
Cost
of Energy
Cost of energy for the Texas region increased by
$59 million for the year ended December 31, 2008,
compared to 2007 due to the following:
|
|
|
|
|
Natural gas costs increased by
$99 million due to a 28% rise in average gas prices offset
by a 14% decrease in gas-fired generation.
|
|
|
|
Coal costs increased by $44 million due
to higher coal prices and the settlement of a coal contract
dispute.
|
|
|
|
Ancillary services increased by
$14 million due to a $16 million rise in ancillary
service costs purchased through ERCOT, offset by a
$2 million decrease in other purchased ancillary services
costs.
|
93
These increases were partially offset by:
|
|
|
|
|
Amortized contract costs decreased by
$59 million due to a $36 million decrease in the
amortization of water supply contracts which ended in 2007. In
addition, the amortization of coal contracts decreased by a net
$22 million as a result of a reduction in expense related
to in-the-money coal contract amortization. These contracts were
established under Texas Genco purchase accounting.
|
|
|
|
Nuclear fuel expense decreased by
$19 million as amortization of nuclear fuel inventory
established under Texas Genco purchase accounting ended in early
2008.
|
|
|
|
Purchased power decreased by $26 million
due to lower forced outage rates at the regions baseload
plants.
|
Other
Operating Expenses
Other operating expenses for the Texas region decreased by
$18 million for the year ended December 31, 2008,
compared to 2007 due to the following:
|
|
|
|
|
Development costs decreased by
$59 million primarily due to the initial costs for
developing the nuclear units 3 and 4 at STP associated with the
RepoweringNRG initiative that began in 2007. Costs for
STP nuclear units 3 and 4 are being capitalized in 2008.
|
This decrease was primarily offset by:
|
|
|
|
|
Operations & maintenance expense
increased by $32 million due to an
additional planned outage at STP and the acceleration of planned
outages at the baseload plants.
|
|
|
|
General and Administrative expense increased
by $10 million driven by higher corporate allocations.
|
94
2007
compared to 2006
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
|
)
|
|
|
(100
|
)
|
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.
|
This favorable result was offset by:
|
|
|
|
|
Capacity Revenues reduction in capacity
auction sales reduced capacity revenues by approximately
$517 million, excluding January 2007.
|
95
|
|
|
|
|
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 the 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 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.
|
96
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
decrease 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 the ERCOT and
increased baseload generation. Coal expenses, excluding January
2007, decreased by $13 million due to a 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 increase 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 were
$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.
|
97
Northeast
Region
2008
compared to 2007
The following table provides selected financial information for
the Northeast region for the years ended December 31, 2008
and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions except
|
|
|
|
|
|
|
otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
1,064
|
|
|
$
|
1,104
|
|
|
|
(4
|
)%
|
Capacity revenue
|
|
|
415
|
|
|
|
402
|
|
|
|
3
|
|
Risk management activities
|
|
|
85
|
|
|
|
27
|
|
|
|
215
|
|
Other revenues
|
|
|
66
|
|
|
|
72
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,630
|
|
|
|
1,605
|
|
|
|
2
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
695
|
|
|
|
641
|
|
|
|
8
|
|
Depreciation and amortization
|
|
|
109
|
|
|
|
102
|
|
|
|
7
|
|
Other operating expenses
|
|
|
392
|
|
|
|
404
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
434
|
|
|
$
|
458
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
(6
|
)
|
MWh generated (in thousands)
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
(6
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
91.70
|
|
|
$
|
76.37
|
|
|
|
20
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
611
|
|
|
|
702
|
|
|
|
(13
|
)
|
CDDs 30 year rolling average
|
|
|
537
|
|
|
|
537
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
6,057
|
|
|
|
6,074
|
|
|
|
|
|
HDDs 30 year rolling average
|
|
|
6,294
|
|
|
|
6,261
|
|
|
|
1
|
%
|
|
|
|
(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 $24 million for the year
ended December 31, 2008, compared to 2007, due to:
|
|
|
|
|
Cost of energy increased by $54 million
due to higher coal costs, increased coal transportation
surcharges and higher natural gas prices. The increase was
offset by lower oil costs from lower oil-fired generation.
|
This unfavorable variance was offset by:
|
|
|
|
|
Operating revenues increased by
$25 million due to higher capacity revenue and risk
management revenues partially offset by lower energy revenue.
|
|
|
|
Other operating expenses decreased by
$12 million due to lower major maintenance expenses and
property taxes offset by higher utilities expense.
|
98
Operating
Revenues
Operating revenues increased by $25 million for the year
ended December 31, 2008, compared to 2007, due to:
|
|
|
|
|
Risk management activities gains of
$85 million were recorded for the year ended
December 31, 2008, compared to gains of $27 million
during the same period in 2007. The $85 million gain
includes $82 million of unrealized mark-to-market gains and
$3 million of gains in settled transactions, or financial
revenue. The $82 million unrealized gains is the net effect
of a $96 million gain from economic hedge positions, the
$13 million loss due to the reversal of previously
recognized mark-to-market gains on economic hedges, the
$14 million loss due to the reversal of mark-to-market
gains on trading activity and $13 million in unrealized
mark-to-market gains on trading activity. Gains are driven by
increases in power and gas prices.
|
|
|
|
Capacity revenues increased by
$13 million due to:
|
|
|
|
|
o
|
PJM capacity revenues increased by
$20 million reflecting recognition of a year of revenue
from the RPM capacity market (effective on June 1,
2007) in 2008 compared to seven months in 2007.
|
|
|
o
|
NEPOOL capacity revenues increased
$11 million due to increased revenue recognized on the
Norwalk RMR contract (effective on June 19, 2007) in
2008 compared to seven months in 2007.
|
|
|
o
|
NYISO capacity revenues decreased by
$18 million due to unfavorable market prices. The lower
capacity market prices are a result of NYISOs reductions
in Installed Reserve Margins and ICAP in-city mitigation rules
effective March 2008. These decreases were offset by higher
capacity contract revenue.
|
These gains were offset by:
|
|
|
|
|
Energy revenues decreased by $40 million
due to:
|
|
|
|
|
o
|
Energy prices increased by a net
$26 million. An average 6% rise in merchant
energy prices resulted in an increase of $64 million. This
increase was offset by lower contract revenue of
$38 million driven by higher net costs incurred to service
PJM contracts as a result of the increase in market energy
prices.
|
|
|
o
|
Generation decreased by $66 million due
to a net 6% decrease in generation. The decrease in
generation represented a 55% decrease in oil-fired generation as
these oil-fired plants were not dispatched due to 41% higher
average oil prices. In addition, there was a 12% decrease in
gas-fired generation related to a cooler summer in 2008 as
compared to 2007. Coal generation was flat in 2008 compared to
2007.
|
|
|
|
|
|
Other revenues decreased by $6 million
due to lower allocations of net physical sales in 2008 of
$17 million offset by higher allocations for trading of
emission allowances and carbon financial instruments of
$10 million.
|
Cost
of Energy
Cost of energy increased by $54 million for the year ended
December 31, 2008, compared to the same period in 2007, due
to:
|
|
|
|
|
Coal costs increased by $61 million due
to higher coal costs and fuel transportation surcharges.
|
|
|
|
Natural gas costs increased by
$22 million, despite 12% lower generation, due to a 32%
higher average natural gas prices.
|
These increases were offset by:
|
|
|
|
|
Oil costs decreased by $27 million due
to lower oil-fired generation of 55% as these plants were not
dispatched in 2008 due to 41% higher average oil prices.
|
99
Other
Operating Expenses
Other operating expenses decreased by $12 million for the
year ended December 31, 2008, compared to the same period
in 2007, due to:
|
|
|
|
|
Major Maintenance decreased $18 million
as a result of less outage work at the Norwalk and Indian River
plants.
|
|
|
|
Property taxes decreased $10 million due
to $4 million in property tax credits received in 2008 at
our New York City plants and higher property credits
received in 2008 at our Western New York plants.
|
These decreases were offset by:
|
|
|
|
|
Utilities expense increased by
$16 million as a result of a $19 million benefit
included in the 2007 utilities cost due to a lower than planned
settlement of the station service agreement with CL&P.
|
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.
|
100
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.
|
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.
|
|
|
|
|
o
|
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.
|
|
|
o
|
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.
|
|
|
|
|
o
|
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.
|
|
|
o
|
PJM On June 1, 2007, the new RPM
capacity market became effective in PJM increasing capacity
revenues by approximately $36 million.
|
|
|
o
|
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.
|
101
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.
|
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.
|
102
South
Central Region
2008
compared to 2007
The following table provides selected financial information for
the South Central region for the years ended December 31,
2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
478
|
|
|
$
|
404
|
|
|
|
18
|
%
|
Capacity revenue
|
|
|
233
|
|
|
|
221
|
|
|
|
5
|
|
Risk management activities
|
|
|
10
|
|
|
|
10
|
|
|
|
|
|
Contract amortization
|
|
|
23
|
|
|
|
23
|
|
|
|
|
|
Other revenues
|
|
|
2
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
746
|
|
|
|
658
|
|
|
|
13
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
468
|
|
|
|
412
|
|
|
|
14
|
|
Depreciation and amortization
|
|
|
67
|
|
|
|
68
|
|
|
|
(1
|
)
|
Other operating expenses
|
|
|
111
|
|
|
|
121
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
100
|
|
|
$
|
57
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
12,447
|
|
|
|
12,452
|
|
|
|
|
|
MWh generated (in thousands)
|
|
|
11,148
|
|
|
|
10,930
|
|
|
|
2
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
71.25
|
|
|
$
|
59.62
|
|
|
|
20
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
1,618
|
|
|
|
1,963
|
|
|
|
(18
|
)
|
CDDs 30 year rolling average
|
|
|
1,547
|
|
|
|
1,547
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,672
|
|
|
|
3,236
|
|
|
|
13
|
|
HDDs 30 year rolling average
|
|
|
3,623
|
|
|
|
3,604
|
|
|
|
1
|
%
|
|
|
|
(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 $43 million for the year
ended December 31, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Operating revenues increased by
$88 million due to increases in energy revenue and capacity
revenue.
|
|
|
|
Cost of energy increased by $56 million
due to higher purchased energy, coal transportation costs,
natural gas and transmission costs.
|
Operating
Revenues
Operating revenues increased by $88 million for the year
ended December 31, 2008, compared to 2007, due to:
|
|
|
|
|
Energy revenues increased by $74 million
due to higher merchant energy revenues. A decline in contract
sales of 577 thousand MWh allowed for increased sales into the
merchant market at higher prices. Merchant
|
103
|
|
|
|
|
energy sales increased 573 thousand MWh. Revenue from contract
load was flat as higher fuel cost pass-through adjustments for
the regions cooperative customers were offset by
reductions in contract volume to other contract customers.
|
|
|
|
|
|
Capacity revenues increased by
$12 million. Capacity payments from the regions
cooperative customers increased by $10 million due to new
peak loads set by the regions cooperative customers and
increased transmission and environmental pass-through costs.
Increased RPM capacity payments from the regions Rockford
facilities in the PJM market contributed an additional
$8 million. These increases were offset by a reduction in
contract volumes to other customers of $6 million.
|
|
|
|
Risk Management Activities gains of
$10 million were recognized during 2008 compared to
$10 million in gains recognized during the same period in
2007. Unrealized gains in 2008 of $26 million were offset
by realized losses of $16 million. The $26 million
unrealized gain was the net effect of a $45 million
unrealized mark-to-market gain from trading activities in the
region offset by the reversal of $19 million loss of
previously recognized mark-to-market gains on trading activity.
Unrealized gains were primarily driven by decreases in power and
gas prices relative to our forward positions.
|
Cost
of Energy
Cost of energy increased by $56 million for the year ended
December 31, 2008, compared to 2007, due to:
|
|
|
|
|
Purchased energy increased by
$16 million reflecting a 21% increase in the average cost
per MWh of purchased energy which reflects higher gas costs
associated with the regions tolling agreements. This
increase was offset by an 8% decrease in purchased MWh as
increased plant availability and lower contract load
requirements reduced the need to purchase power.
|
|
|
|
Coal costs increased by $16 million due
to a $2 per ton increase in fuel transportation surcharges
combined with a 1% increase in coal generation. These increases
were offset by a $3 million decrease in allocated rail car
lease fees.
|
|
|
|
Natural gas costs increased
$14 million. The regions Bayou Cove and
Big Cajun I peaker plants ran extensively to support
transmission system stability after hurricane Gustav in
September 2008.
|
|
|
|
Transmission costs increased by
$9 million due to additional point-to-point transmission
costs driven by an increase in merchant energy sales.
|
Other
Operating Expenses
Other operating expenses decreased by approximately
$10 million for the year ended December 31, 2008,
compared to 2007, due to:
|
|
|
|
|
G&A Expense Franchise tax decreased by
$5 million due to retroactive charges recorded in 2007. The
Louisiana state franchise tax is assessed on the Companys
total debt and equity that significantly increased following the
Acquisition of Texas Genco. This decrease was offset by
$6 million in higher corporate allocations in 2008 compared
to the same period in 2007.
|
|
|
|
Operating and maintenance expense Major
maintenance decreased by $9 million due to more extensive
spring outage work performed at the Big Cajun II plant in
2007 compared to the same period in 2008. Normal maintenance
rose $2 million as a result of increased forced outages and
higher contractor costs. Asset retirements decreased by
$4 million reflecting disposals associated with the 2007
outage work at Big Cajun II.
|
104
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
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
|
105
|
|
|
|
|
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.
|
106
West
Region
2008
compared to 2007
The following table provides selected financial information for
the West region for the years ended December 31, 2008, and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
39
|
|
|
$
|
4
|
|
|
|
N/A
|
|
Capacity revenue
|
|
|
125
|
|
|
|
122
|
|
|
|
2
|
%
|
Risk management activities
|
|
|
|
|
|
|
|
|
|
|
N/A
|
|
Other revenues
|
|
|
7
|
|
|
|
1
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
171
|
|
|
|
127
|
|
|
|
35
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
35
|
|
|
|
5
|
|
|
|
N/A
|
|
Depreciation and amortization
|
|
|
8
|
|
|
|
3
|
|
|
|
167
|
|
Other operating expenses
|
|
|
70
|
|
|
|
80
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
58
|
|
|
$
|
39
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
1,532
|
|
|
|
1,246
|
|
|
|
23
|
|
MWh generated (in thousands)
|
|
|
1,532
|
|
|
|
1,246
|
|
|
|
23
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
82.62
|
|
|
$
|
66.52
|
|
|
|
24
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
953
|
|
|
|
785
|
|
|
|
21
|
|
CDDs 30 year rolling average
|
|
|
704
|
|
|
|
704
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,190
|
|
|
|
3,048
|
|
|
|
5
|
%
|
HDDs 30 year rolling average
|
|
|
3,243
|
|
|
|
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 increased by $19 million for the year
ended December 31, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Energy revenues increased by $35 million
due to the 2008 dispatch of the El Segundo plant outside of the
tolling agreement in 2008. In 2007, no such dispatch occurred.
|
|
|
|
Other operating expense decreased by
$10 million as a result of a $5 million reduction in
RepoweringNRG expenses due to the capitalization of cost
for the El Segundo Energy Center project in 2008. In addition
there was a $3 million reduction in lease expenses in 2008
and the recognition of a $2 million environmental liability
for the El Segundo plant in 2007.
|
|
|
|
Other revenues increased by $6 million
due to higher allocations for trading of emission allowances in
2008.
|
107
|
|
|
|
|
Capacity revenues increased by
$3 million primarily due to the tolling agreement at the
Long Beach plant partially offset by the expiration of a two
year tolling agreement at the El Segundo facility:
|
|
|
|
|
o
|
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. The plant contributed $15 million in incremental
capacity revenues for the year ended December 31, 2008.
|
|
|
o
|
El Segundo The expiration of the two year
tolling agreement at the end of April resulted in a decrease of
$11 million in capacity revenues for the year ended
December 31, 2008.
|
These increases were partially offset by:
|
|
|
|
|
Cost of energy increased by $30 million
due to the dispatch of the El Segundo plant outside of the
tolling agreement in 2008. In 2007, no such dispatch occurred.
|
|
|
|
Depreciation and amortization increased by
$5 million, reflecting depreciation associated with the
repowered plant at the Long Beach generating facility.
|
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
|
)
|
|
|
100
|
|
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.
|
108
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:
|
|
|
|
|
o
|
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.
|
|
|
o
|
Long Beach The repowered plant at the Long
Beach generating facility contributed approximately
$13 million in capacity revenues for the year ended
December 31, 2007.
|
|
|
|
|
|
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 its 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 a 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.
|
109
Liquidity
and Capital Resources
Liquidity
Position
As of December 31, 2008 and 2007, NRGs liquidity,
excluding collateral received, was approximately
$3.4 billion and $2.7 billion, respectively, comprised
of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
Funds deposited by counterparties
|
|
|
754
|
|
|
|
|
|
Restricted cash
|
|
|
16
|
|
|
|
29
|
|
|
|
|
|
|
|
|
|
|
Total cash
|
|
|
2,264
|
|
|
|
1,161
|
|
Synthetic Letter of Credit Facility availability
|
|
|
860
|
|
|
|
557
|
|
Revolver Credit Facility availability
|
|
|
1,000
|
|
|
|
997
|
|
|
|
|
|
|
|
|
|
|
Total liquidity
|
|
|
4,124
|
|
|
|
2,715
|
|
Less: Funds deposited as collateral by hedge counterparties
|
|
|
(760
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liquidity, excluding collateral received
|
|
$
|
3,364
|
|
|
$
|
2,715
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2008, total liquidity
increased by $1.4 billion due to a rise in funds deposited
of $754 million as well as higher cash balances of
$362 million. Changes in cash balances are further
discussed hereinafter under Cash Flow Discussion. Cash
and cash equivalents and funds deposited by counterparties at
December 31, 2008 are predominantly held in money market
funds invested in treasury securities or treasury repurchase
agreements.
The line item Funds deposited by counterparties
consist of cash collateral received from hedge counterparties in
support of energy risk management activities, and it is the
Companys intention as of December 31, 2008 to limit
the use of these funds. The increase in these amounts is due to
the in-the-money position of our transactions following the drop
in commodity prices since the summer of 2008. Depending on
market fluctuation and the settlement of the underlying
contracts, the Company will refund this collateral to the
counterparties pursuant to the terms and conditions of the
underlying trades. The Companys balance sheet reflects a
liability for cash collateral received within current
liabilities.
Management believes that the Companys liquidity position
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 net 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
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. As of December 31, 2008, NRGs credit
ratings are on positive watch from both S&P and
Moodys rating agencies.
110
The following table summarizes the credit ratings for NRG
Energy, Inc., its Term Loan Facility and its senior notes as of
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Facility
|
|
|
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
As of December 31, 2008, NRG has a Senior Credit Facility
which is 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 $1.3 billion senior first priority
secured synthetic letter of credit facility, or the Synthetic
Letter of Credit Facility. The Senior Credit Facility was last
amended on June 8, 2007. As of December 31, 2008, NRG
had issued $440 million of letters of credit under the
Synthetic Letter of Credit Facility, leaving $860 million
available for future issuances. Under the Revolving Credit
Facility, as of December 31, 2008, NRG had not issued any
letters of credit.
First
and Second Lien Structure
NRG has granted first and second liens to certain counterparties
on substantially all of the Companys assets. 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 out-of-the-money hedge agreements for forward sales of
power or MWh equivalents. To the extent that the underlying
hedge positions for a counterparty are in-the-money to NRG, the
counterparty would have no claim under the lien program. The
lien program limits the volume that can be hedged, not the value
of underlying out-of-the money positions. The first lien program
does not require NRG to post collateral above any threshold
amount of exposure. 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 for the
first 60 months and then declining thereafter. Net exposure
to a counterparty on all trades must be positively correlated to
the price of the relevant commodity for the first lien to be
available to that counterparty. The first and second lien
structure is not subject to unwind or termination upon a ratings
downgrade of a counterparty and has no stated maturity date.
The Companys lien counterparties may have a claim on our
assets to the extent market prices exceed the hedged price. As
of December 31, 2008 and February 2, 2009, the first
lien exposure of net out-of-the-money positions to
counterparties on hedges was $88 million and
$43 million, respectively. As of December 31, 2008 and
February 2, 2009, there was no exposure to out-of-the-money
positions to counterparties on hedges under the second lien.
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 2, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales Secured by First and Second Lien
Structure(a)
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
In MW(b)
|
|
|
4,967
|
|
|
|
4,600
|
|
|
|
3,788
|
|
|
|
2,196
|
|
|
|
828
|
|
As a percentage of total forecasted baseload
capacity(c)
|
|
|
71
|
%
|
|
|
67
|
%
|
|
|
56
|
%
|
|
|
33
|
%
|
|
|
12
|
%
|
|
|
|
(a)
|
|
Equivalent Net Sales include
natural gas swaps converted using a weighted average heat rate
by region.
|
|
(b)
|
|
2009 MW value consists of
March through December positions only.
|
|
(c)
|
|
Forecasted baseload capacity under
the first and second lien structure represents 80% of the total
Companys baseload assets.
|
111
Common
Stock Finance I Debt
The Companys Senior Credit Facility and Senior Notes
indentures contain restricted payment provisions limiting the
use of funds for transactions such as common share repurchases.
To maintain restricted payment capacity under the Senior Notes
indentures, in March 2008 the Company executed an arrangement
with CS to extend maturities of CSF Is notes and preferred
interests from October 2008 to June 2010. In addition, the
settlement date of an embedded derivative, or CSF I CAGR, which
is based on NRGs share price appreciation above a
threshold price, was extended 30 days to early December
2008. As part of this extension arrangement, the Company
contributed 795,503 treasury shares to CSF I as additional
collateral to maintain a blended interest rate in the CSF I
facility of approximately 7.5%. Accordingly, the amount due at
maturity in June 2010 for the CSF I notes and preferred
interests will be $248 million. In August 2008, the Company
amended the CSF I notes and preferred interests to early settle
the CSF I CAGR. Accordingly, NRG made a cash payment of
$45 million to CS for the benefit of CSF I, which was
recorded to interest expense in the Companys Consolidated
Statement of Operations.
Asset
Sales
ITISA On April 28, 2008, NRG completed
the sale of its 100% interest in Tosli, which held all
NRGs interest in ITISA, to Brookfield Renewable Power Inc.
(previously Brookfield Power Inc.), a wholly-owned subsidiary of
Brookfield Asset Management Inc. In addition, the purchase price
adjustment contingency under the sale agreement was resolved on
August 7, 2008. In connection with the sale, NRG received
$300 million of cash proceeds from Brookfield, and removed
$163 million of assets, including $59 million of cash,
$122 million of liabilities, including $63 million of
debt, and $15 million in foreign currency translation
adjustment from its 2008 consolidated balance sheet. 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: (i) commercial
operations activities; (ii) debt service obligations;
(iii) capital expenditures including RepoweringNRG
and environmental; and (iv) corporate financial
transactions including return of capital to shareholders.
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, 2008, commercial operations had total cash
collateral outstanding of $492 million, and
$283 million outstanding in letters of credit to third
parties primarily to support its economic hedging activities. As
of December 31, 2008, total collateral held from
counterparties was $788 million, including $6 million
of restricted cash, and $28 million of letters of credit.
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.
Debt
Service Obligations
NRG must annually offer a portion of its excess cash flow (as
defined in the Senior Credit Facility) to its first lien lenders
under the Term Loan Facility. 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
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 for 2008, and, as such, the Company has
reclassified approximately
112
$197 million of Term Loan Facility maturity from a
non-current to a current liability as of December 31, 2008.
The mandatory annual offer required for 2007 was
$446 million, against which the Company made a
$300 million prepayment in December 2007. With this
prepayment, the Company met a financial ratio by the end of 2007
that resulted in a 0.25% reduction in the interest rate on both
its Term Loan Facility and Synthetic Letter of Credit Facility
which resulted in approximately $8 million in pre-tax
interest savings during 2008. Of the remaining
$146 million, the lenders accepted a repayment of
$143 million in March 2008. The amount retained by the
Company was used for investments, capital expenditures and other
items as defined by the Senior Credit Facility.
As of December 31, 2008, NRG had approximately
$4.7 billion in aggregate principal amount of unsecured
high yield notes or Senior Notes, had approximately
$2.6 billion in principal amount outstanding under the Term
Loan Facility, and had issued $440 million of letters of
credit under the Companys $1.3 billion Synthetic
Letter of Credit Facility. The Revolving Credit Facility matures
on February 2, 2011 and the Synthetic Letter of Credit
Facility matures on February 1, 2013.
Principal payments on debt and capital leases as of
December 31, 2008 are due in the following periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary/Description
|
|
2009
|
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
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 Facility, due 2013
|
|
|
228
|
|
|
|
32
|
|
|
|
31
|
|
|
|
32
|
|
|
|
2,319
|
|
|
|
|
|
|
|
2,642
|
|
CSF notes and preferred interests, due 2009 and 2010
|
|
|
143
|
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
NRG Energy Center Minneapolis LLC, due 2013 and 2017
|
|
|
11
|
|
|
|
11
|
|
|
|
12
|
|
|
|
13
|
|
|
|
10
|
|
|
|
27
|
|
|
|
84
|
|
Nuclear Innovation North America LLC, due 2011
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
NRG Repowering Holdings LLC, due 2011
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
NRG Peaker Finance Co. LLC, due June 2019
|
|
|
15
|
|
|
|
20
|
|
|
|
21
|
|
|
|
22
|
|
|
|
23
|
|
|
|
165
|
|
|
|
266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal Debt, Bonds and Notes
|
|
|
397
|
|
|
|
253
|
|
|
|
84
|
|
|
|
67
|
|
|
|
2,352
|
|
|
|
4,892
|
|
|
|
8,045
|
|
Capital Lease:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau
|
|
|
72
|
|
|
|
12
|
|
|
|
6
|
|
|
|
4
|
|
|
|
4
|
|
|
|
44
|
|
|
|
142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Payments and Capital Leases
|
|
$
|
469
|
|
|
$
|
265
|
|
|
$
|
90
|
|
|
$
|
71
|
|
|
$
|
2,356
|
|
|
$
|
4,936
|
|
|
$
|
8,187
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
113
Capital
Expenditures
For the year ended December 31, 2008, the Companys
capital expenditures, including accruals, were approximately
$1.0 billion, of which $645 million was related to
RepoweringNRG projects. The following table summarizes
the Companys capital expenditures for the year ended
December 31, 2008 and the estimated capital expenditure and
repowering investments forecast for 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
|
|
|
Environmental
|
|
|
Repowering
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Northeast
|
|
$
|
32
|
|
|
$
|
157
|
|
|
$
|
19
|
|
|
$
|
208
|
|
Texas
|
|
|
115
|
|
|
|
26
|
|
|
|
97
|
|
|
|
238
|
|
South Central
|
|
|
9
|
|
|
|
5
|
|
|
|
|
|
|
|
14
|
|
West
|
|
|
5
|
|
|
|
|
|
|
|
30
|
|
|
|
35
|
|
Wind
|
|
|
|
|
|
|
|
|
|
|
398
|
|
|
|
398
|
|
NINA
|
|
|
|
|
|
|
|
|
|
|
101
|
|
|
|
101
|
|
Other
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
182
|
|
|
$
|
188
|
|
|
$
|
645
|
|
|
$
|
1,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated capital expenditures for 2009
|
|
$
|
255
|
|
|
$
|
256
|
|
|
$
|
256
|
|
|
$
|
767
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RepoweringNRG capital expenditures and
investments RepoweringNRG project capital
expenditures consisted of approximately $218 million for
wind turbines and construction related costs for the Elbow Creek
wind farm project which became commercially operational in
December 2008 and $180 million in turbine purchases for
other wind projects currently under development. In addition,
the Companys RepoweringNRG capital expenditures
included $97 million related to the construction of Cedar
Bayou Unit 4 in Texas, $101 million related to the
development of STP Units 3 and 4 in Texas, $30 million for
the repowering of the El Segundo generating station in
California, and $19 million for the construction of Cos Cob
in Connecticut.
The Companys estimated repowering capital expenditures for
2009 are expected to be approximately $256 million, of
which capital expenditures related to STP units 3 and 4 will be
approximately $145 million, the construction of Cedar Bayou
Unit 4 anticipated to be approximately $22 million, and the
balance of the Companys repowering capital expenditures
related to the purchase of additional wind turbines. The Company
also anticipates receiving approximately $145 million in
third party equity investments related to its
RepoweringNRG projects in 2009.
Related to RepoweringNRG, the Company contributed equity
of approximately $84 million to its Sherbino wind farm
joint venture project with BP in 2008 which became commercially
operational in October 2008.
Major maintenance and environmental capital
expenditures The Companys baghouse project
at its Huntley and Dunkirk plants resulted in environmental
capital expenditures of $124 million for the year ended
December 31, 2008. Other capital expenditures included
$44 million for STP fuel and $71 million in
maintenance capital expenditures in Texas primarily related to
the W.A. Parish and Limestone plants.
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 region through Solid Waste
Disposal Bonds utilizing tax exempt financing, and expects to
draw upon such funds during 2009.
Loans to affiliates During 2008 the Company
loaned approximately $36 million in funds to GenConn Energy
LLC, a 50/50 joint venture vehicle of NRG and the United
Illuminating Company as a part of the Devon and Middletown plant
projects. These loans, which are in the form of an interest
bearing note, mature in 2009, at which point GenConn Energy
LLCs construction costs are expected to be funded through
equity of NRG and the United Illuminating Company and
non-recourse project level financing.
114
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2009
through 2013 to meet NRGs environmental commitments will
be approximately $1.2 billion. These capital expenditures,
in general, are related to installation of particulate,
SO2,
NOx,
and mercury controls to comply with federal and state air
quality rules and consent orders, 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. While this
estimate reflects schedules and controls to meet anticipated
reduction requirements, the full impact on the scope and timing
of environmental retrofits cannot be determined until issuance
of final rules by the USEPA.
The following table summarizes the estimated environmental
capital expenditures for the referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
2009
|
|
$
|
|
|
|
$
|
256
|
|
|
$
|
|
|
|
$
|
256
|
|
2010
|
|
|
8
|
|
|
|
213
|
|
|
|
57
|
|
|
|
278
|
|
2011
|
|
|
17
|
|
|
|
175
|
|
|
|
116
|
|
|
|
308
|
|
2012
|
|
|
29
|
|
|
|
67
|
|
|
|
114
|
|
|
|
210
|
|
2013
|
|
|
21
|
|
|
|
3
|
|
|
|
74
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
75
|
|
|
$
|
714
|
|
|
$
|
361
|
|
|
$
|
1,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
Allocation
2008 Capital Allocation Plan In December
2007, the Company initiated its 2008 Capital Allocation Plan,
with the repurchase of 2,037,700 shares of NRG common stock
during that month for approximately $85 million. In
February 2008, the Companys Board of Directors authorized
an additional $200 million in common share repurchases that
raised the total 2008 Capital Allocation Plan to approximately
$300 million. In the first quarter 2008, the Company
repurchased 1,281,600 shares of NRG common stock for
approximately $55 million. In the third quarter 2008, the
Company repurchased an additional 3,410,283 of NRG common stock
in the open market for approximately $130 million. As of
December 31, 2008, NRG had repurchased a total of
6,729,583 shares of NRG common stock at a cost of
approximately $270 million as part of its 2008 Capital
Allocation Plan.
2009 Capital Allocation Plan On
October 30, 2008, the Company announced its 2009 Capital
Allocation Plan to purchase an additional $300 million in
common stock, subject to restrictions under US securities laws.
As part of the 2009 plan, the Company will invest over
$511 million in maintenance and environmental capital
expenditures in existing assets in 2009 and $256 million in
investment in projects under RepoweringNRG that are
currently under construction or for which there exists current
obligations. Finally, in addition to scheduled debt amortization
payment, in the first quarter 2009 the Company will offer its
first lien lenders $197 million of its 2008 excess cash
flow (as defined in the Senior Credit Facility).
Preferred
Stock Dividend Payments
For the year ended December 31, 2008, NRG paid
approximately $29 million, $17 million and
$9 million in dividend payments to holders of the
Companys 5.75%, 4% and 3.625% Preferred Stock.
Benefit
Plans Obligations
As of December 31, 2008, NRG contributed $99 million
towards its three defined benefit pension plans to meet the
Companys 2008 benefit obligation, $35 million of
which was to partially fund the plans as a result of the weak
market performance of plan assets in 2008. Based on the
Companys December 31, 2008 measurement of its benefit
obligation for its three defined benefit pension plans, the
Company is expected to contribute another $60 million to
these plans during 2009, $29 million of which also relates
to the Companys 2008 benefit obligation.
115
Cash Flow
Discussion
2008
compared to 2007
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
(In millions)
|
|
|
Net cash provided by operating activities
|
|
$
|
1,434
|
|
|
$
|
1,517
|
|
|
$
|
(83
|
)
|
Net cash used by investing activities
|
|
|
(672
|
)
|
|
|
(327
|
)
|
|
|
(345
|
)
|
Net cash used by financing activities
|
|
|
(442
|
)
|
|
|
(814
|
)
|
|
|
372
|
|
Net Cash
Provided By Operating Activities
For the year ended December 31, 2008, net cash provided by
operating activities decreased by $83 million compared to
the same period in 2007. The difference was due to:
|
|
|
|
|
Collateral paid In 2008, higher cash
collateral paid to support the Companys hedging and
trading activities decreased cash from operations by
$292 million as compared to the same period in 2007.
|
|
|
|
Working capital In 2008, the cash provided by
working capital items increased by $196 million. Changes in
option premiums collected from 2007 to 2008 classified in other
current liabilities increased as a result of the deferral of
option premium revenue to 2009 to match revenues with option
expiration dates. Further, changes to account receivable were
caused by higher energy revenues in December 2007 as compared to
December 2008 and changes to accounts payable were caused by
reduced maintenance expenses incurred in December 2007 as
compared to December 2008.
|
Net Cash
Used By Investing Activities
For the year ended December 31, 2008, net cash used in
investing activities was approximately $345 million more
than the same period in 2007. This was due to:
|
|
|
|
|
Capital expenditures NRGs capital
expenditures increased by $418 million due to
RepoweringNRG projects, primarily related to
$398 million for wind turbines and construction activities
related to Elbow Creek and other wind projects currently under
development.
|
|
|
|
Sale of discontinued operations Proceeds from
the sale of ITISA, net of cash divested, were $241 million
in 2008.
|
|
|
|
Asset sales The Company received
$14 million in proceeds primarily from the sale of rail
cars in 2008 compared to proceeds of $57 million for the
sale of Red Bluff and Chowchilla II power plants and
equipment in the same period in 2007 for a net decrease in cash
of $43 million.
|
|
|
|
Trading of emission allowances Net purchases
and sales of emission allowances resulted in a decrease in cash
of $44 million for 2008 as compared to 2007.
|
|
|
|
Equity Contribution The Company contributed
approximately $84 million to its equity investment in
Sherbino.
|
Net Cash
Used By Financing Activities
For year ended December 31, 2008, net cash used by
financing activities decreased by approximately
$372 million compared to 2007, due to:
|
|
|
|
|
Term Loan Facility debt payment In 2008, the
Company paid down $174 million of its Term Loan Facility,
including the payment of excess cash flow, as discussed above
under Debt Service Obligations. The Company paid down
$332 million of its Term Loan Facility during 2007 for a
net cash increase of $158 million for the year ended 2008
compared to the same period in 2007.
|
116
|
|
|
|
|
Share repurchase During 2008, the Company
repurchased approximately $185 million shares of NRG common
stock, compared to $353 million for 2007 for a net
$168 million increase to cash for the year ended 2008
compared to the same period in 2007.
|
|
|
|
Sale of minority interest The Company
received $50 million in proceeds from the sale of minority
interest in NINA in the first half of 2008.
|
|
|
|
Payment of financing element of acquired
derivatives For 2008, the Company paid
approximately $43 million for the settlement of gas swaps
related to the acquisition of Texas Genco in 2006.
|
|
|
|
Issuance of debt During 2008 the Company
received $20 million in proceeds from borrowings made by
its subsidiaries.
|
NOLs,
Deferred Tax Assets and FIN 48 Implications
As of December 31, 2008, the Company had generated total
domestic pre-tax book income of $1,644 million and foreign
continuing pre-tax book income of $85 million. In addition,
NRG has cumulative foreign NOL carryforwards of
$239 million, of which $41 million will expire
starting in 2011 through 2017 and of which $198 million do
not have an expiration date.
In addition to these amounts, the Company has $527 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, we anticipate income
tax payments of up to $100 million in 2009.
However, as the position remains uncertain, of the
$527 million of tax effected unrecognized tax benefits, the
Company has recorded a non-current tax liability of
$208 million and may accrue the remaining balance as an
increase to non-current liabilities until final resolution with
the related taxing authority. The $208 million non-current
tax liability for unrecognized tax benefits is due to taxable
earnings for the period which there are no NOLs available to
offset for financial statement purposes.
The Company has been contacted for examination by the Internal
Revenue Service for years 2004 through 2006. The audit commenced
during the third quarter 2008 and is expected to continue for
approximately 18 to 24 months.
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 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.
See also Item 15 Note 25, Guarantees,
to the Consolidated Financial Statements for additional
discussion.
Retained
or Contingent Interests
NRG does not have any material retained or contingent interests
in assets transferred to an unconsolidated entity.
117
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, 2008, based on the
Companys stock price, the embedded derivative was
out-of-the-money and had no redemption value. See also
Item 15 Note 13, Capital Structure,
to the Consolidated Financial Statements for additional
discussion.
On October 13, 2006, NRG, through its unrestricted
wholly-owned subsidiaries CSF I and CSF II issued notes and
preferred interests for the repurchase of NRGs common
stock. Included in each agreement was a feature 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. In August 2008, the Company amended the CSF I
notes and preferred interests to early settle the CSF I embedded
derivative. Accordingly, NRG made a cash payment of
$45 million to CS for the benefit of CSF I, which was
recorded to interest expense in the Companys Consolidated
Statement of Operations. As of December 31, 2008, based on
the Companys stock price, the CSF II embedded derivative
was out-of-the-money and had no redemption value. See also
Item 15 Note 11, Debt and Capital
Leases, to the Consolidated Financial Statements for
additional discussion.
Obligations
Arising Out of a Variable Interest in an Unconsolidated
Entity
Variable interest in Equity investments As of
December 31, 2008, 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. One of these investments, GenConn Energy
LLC, is a variable interest entity for which NRG is not the
primary beneficiary. NRGs pro-rata share of non-recourse
debt held by unconsolidated affiliates was approximately
$135 million as of December 31, 2008. This
indebtedness may restrict the ability of these subsidiaries to
issue dividends or distributions to NRG. See also
Item 15 Note 14, Investments Accounted
for by the Equity Method, to the Consolidated Financial
Statements for additional discussion.
Letter of Credit Facilities The
Companys $1.3 billion Synthetic Letter of Credit
Facility is unfunded by NRG and is secured by a
$1.3 billion cash deposit at Deutsche Bank AG, New York
Branch that was funded using proceeds from the Term Loan
Facility 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.
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 contingent obligations for
guarantee. See also Item 15 Note 11,
Debt and Capital Leases, Note 21, Commitments and
Contingencies, and Note 25, Guarantees , to the
Consolidated Financial Statements for additional discussion.
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
|
2008
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2007
|
|
Contractual Cash
Obligations
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total(b)
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Long-term debt (including estimated interest)
|
|
$
|
858
|
|
|
$
|
1,316
|
|
|
$
|
3,267
|
|
|
$
|
5,701
|
|
|
$
|
11,142
|
|
|
$
|
12,301
|
|
Capital lease obligations (including estimated interest)
|
|
|
87
|
|
|
|
37
|
|
|
|
25
|
|
|
|
172
|
|
|
|
321
|
|
|
|
390
|
|
Operating leases
|
|
|
43
|
|
|
|
79
|
|
|
|
62
|
|
|
|
193
|
|
|
|
377
|
|
|
|
420
|
|
RepoweringNRG project commitments
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
352
|
|
Fuel purchase and transportation
obligations(a)
|
|
|
1,513
|
|
|
|
477
|
|
|
|
182
|
|
|
|
206
|
|
|
|
2,378
|
|
|
|
3,203
|
|
Pension minimum funding
requirement(c)
|
|
|
65
|
|
|
|
95
|
|
|
|
34
|
|
|
|
|
|
|
|
194
|
|
|
|
196
|
|
Other postretirement benefits minimum funding
requirement(d)
|
|
|
4
|
|
|
|
11
|
|
|
|
4
|
|
|
|
|
|
|
|
19
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,597
|
|
|
$
|
2,015
|
|
|
$
|
3,574
|
|
|
$
|
6,272
|
|
|
$
|
14,458
|
|
|
$
|
16,877
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes only those coal
transportation and lignite commitments for 2009 as no other
nominations were made as of December 31, 2008. Natural gas
nomination is through February 2010.
|
|
(b)
|
|
Excludes $208 million
non-current FIN 48 payable relating to NRGs uncertain
tax benefits as the period of payment cannot be reasonably
estimated.
|
|
(c)
|
|
These amounts represent the
Companys estimated minimum pension contributions required
under the Pension Protection Act of 2006. These amounts
represent estimates that are based on assumptions that are
subject to change. The minimum required contribution for years
after 2013 is currently not available.
|
|
(d)
|
|
These amounts represent estimates
that are based on assumptions that are subject to change. The
minimum required contribution for years after 2013 are currently
not available.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
|
2008
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2007
|
|
Guarantees, Indemnifications and
Other Contingent Obligations
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Synthetic letters of credit
|
|
$
|
357
|
|
|
$
|
83
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
440
|
|
|
$
|
743
|
|
Unfunded standby letters of credit and surety bonds
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
8
|
|
Asset sales guarantee obligations
|
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
17
|
|
|
|
129
|
|
|
|
148
|
|
Commercial sales arrangements
|
|
|
192
|
|
|
|
13
|
|
|
|
|
|
|
|
800
|
|
|
|
1,005
|
|
|
|
791
|
|
Other guarantees
|
|
|
24
|
|
|
|
30
|
|
|
|
|
|
|
|
26
|
|
|
|
80
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
578
|
|
|
$
|
238
|
|
|
$
|
|
|
|
$
|
843
|
|
|
$
|
1,659
|
|
|
$
|
1,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value of 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
119
instruments are recognized in earnings. These trading activities
are a complement to NRGs energy marketing portfolio.
The tables below disclose the activities that include both
exchange and 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, 2008, based on
whether fair values are determined by quoted market prices or
more subjective means; and indicate the maturities of contracts
at December 31, 2008.
|
|
|
|
|
Derivative Activity
Gains/(Losses)
|
|
(In millions)
|
|
|
Fair value of contracts as of December 31, 2007
|
|
$
|
(492
|
)
|
Contracts realized or otherwise settled during the period
|
|
|
162
|
|
Changes in fair value
|
|
|
1,326
|
|
|
|
|
|
|
Fair value of contracts as of December 31, 2008
|
|
$
|
996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of December 31, 2008
|
|
|
|
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
|
|
$
|
(32
|
)
|
|
$
|
14
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(18
|
)
|
Prices provided by other external sources
|
|
|
614
|
|
|
|
114
|
|
|
|
283
|
|
|
|
(46
|
)
|
|
|
965
|
|
Prices provided by models and other valuation methods
|
|
|
37
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
619
|
|
|
$
|
140
|
|
|
$
|
283
|
|
|
$
|
(46
|
)
|
|
$
|
996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A small portion of NRGs contracts are exchange-traded
contracts with readily available quoted market prices. The
majority of NRGs contracts are non exchange-traded
contracts valued using prices provided by external sources,
primarily price quotations available through brokers or
over-the-counter and on-line exchanges. For the majority of NRG
markets, the Company receives quotes from multiple sources. To
the extent that NRG receives multiple quotes, the Companys
prices reflect the average of the bid-ask mid-point prices
obtained from all sources that NRG believes provide the most
liquid market for the commodity. If the Company receives one
quote then the mid point of the bid-ask spread for that quote is
used. The terms for which such price information is available
vary by commodity, region and product. The remainder of the
assets and liabilities represent contracts for which external
sources or observable market quotes are not available. These
contracts are valued based on various valuation techniques
including but not limited to internal models based on a
fundamental analysis of the market and extrapolation of
observable market data with similar characteristics. Contracts
valued with prices provided by models and other valuation
techniques make up 5% of the total fair value of all derivative
contracts. The fair value of each contract is discounted using a
risk free interest rate. In addition, the Company applies a
credit reserve to reflect credit risk which is calculated based
on published default probabilities. To the extent that
NRGs net exposure under a specific master agreement is an
asset, the Company is using the counterpartys default swap
rate. If the exposure under a specific master agreement is a
liability, the Company is using NRGs default swap rate.
The credit reserve is added to the discounted fair value to
reflect the exit price that a market participant would be
willing to receive to assume NRGs liabilities or that a
market participant would be willing to pay for NRGs
assets. As of December 31, 2008 the credit reserve resulted
in a $22 million decrease in fair value which is composed
of a $10 million gain in other comprehensive income, or
OCI, and a $12 million gain in derivative revenue.
The fair values in each category reflect the level of forward
prices and volatility factors as of December 31, 2008 and
may change as a result of changes in these factors. Management
uses its best estimates to determine the fair value of commodity
and derivative contracts NRG holds and sells. These estimates
consider various factors including closing exchange and
over-the-counter price quotations, time value, volatility
factors and credit exposure. It is possible however, that future
market prices could vary from those used in recording assets and
liabilities from energy marketing and trading activities and
such variations could be material.
120
The Company has elected to disclose derivative activity on a
trade-by-trade
basis and does not offset amounts at the counterparty master
agreement level. Consequently, the magnitude of the changes in
individual current and non-current derivative assets or
liabilities is higher than the underlying credit and market risk
of the Companys portfolio. As discussed in Item 7A
Commodity Price Risk, NRG measures the
sensitivity of the Companys portfolio to potential changes
in market prices using Value at Risk, or VAR, a statistical
model which attempts to predict risk of loss based on market
price and volatility. NRGs risk management policy places a
limit on
one-day
holding period VAR, which limits the Companys net open
position. As the Companys
trade-by-trade
derivative accounting results in a
gross-up of
the Companys derivative assets and liabilities, the net
derivative assets and liability position is a better indicator
of our hedging activity. As of December 31, 2008,
NRGs net derivative asset was $996 million, an
increase to total fair value of $1,488 million as compared
to December 31, 2007. This increase was primarily driven by
decreases in gas and power prices as well as the roll-off of
trades that settled during the period.
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 US.
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
|
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
|
121
|
|
|
|
|
Accounting Policy
|
|
|
|
Judgments/Uncertainties
Affecting Application
|
|
|
|
|
|
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
|
|
|
|
|
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
|
|
|
|
|
Regulatory and political environments and requirements
|
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 commodities based on
the specific market in which the energy commodity is being
purchased or sold, using externally available forward market
pricing curves for all periods possible under the pricing model.
In order to qualify derivative 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.
122
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, 2008, NRG had a valuation allowance of
approximately $359 million. This amount is comprised of
U.S. domestic capital loss carryforwards and
non-depreciable property of approximately $292 million,
foreign net operating loss carryforwards of approximately
$66 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, cumulative net operating losses of
$245 million had been fully utilized with the exception of
state NOLs. 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 and Australia. 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
123
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 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.
For the years ended December 31, 2008 and 2007, there were
reductions of $23 million and $11 million,
respectively, in income from continuing operation due to
impairment of an investment in commercial paper. The Company
recorded these impairments as a reduction to interest income.
For the year ended December 31, 2006, there was no
reduction in income from continuing operations due to an
impairment.
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.
Goodwill
and Other Intangible Assets
As part of the acquisition of Texas Genco, NRG recorded goodwill
and intangible assets at its Texas segment reporting unit. The
Company applied SFAS No. 141, Business
Combinations, or SFAS 141, and 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
are tested for impairments at least annually, or more frequently
whenever an event or change in circumstances occurs that would
more likely than not reduce the fair value of a reporting unit
below its carrying amount. We test goodwill for impairment at
the reporting unit level, which is identified by assessing
whether the components of our operating segments constitute
businesses for which discrete financial information is available
and segment management regularly reviews the operating results
of those components. If it is determined that the fair value of
a reporting unit is below its carrying amount, where necessary
the Companys goodwill
and/or
intangible asset with indefinite lives will be impaired at that
time.
The Company performed its annual goodwill impairment assessment
as of December 31, 2008 for its Texas reporting unit, which
is at the operating segment level. The impairment assessment
included both income and
124
market approaches, represented by discounted cash flow and
earnings multiple methodologies that considered the following:
Income
approach
|
|
|
|
|
a discounted cash flow valuation for the regions major
solid fuel baseload plants that utilized the Companys
six-year budget data and a market-derived earnings multiple
terminal value, with such terminal value assessed for
reasonableness by capitalizing the final years cash flow
with adjustments for expected inflation;
|
|
|
|
a discounted cash flow valuation for the tax benefit associated
with the amortization of tax basis of the regions
intangible assets;
|
|
|
|
a market approach valuation of the regions gas plants
using market-derived earnings multiples of comparable power
generators, with adjustments for the regions expected
capital expenditure requirements;
|
Market
approach
|
|
|
|
|
an overall market approach reasonableness test that reconciled
NRGs current market value based upon the average percent
of total company value represented by NRG Texas, as measured by
four different earnings measures, each calculated over three
different historical time periods. This market approach
reasonableness test also considered sensitivity testing under a
number of different implied control premium scenarios, including
one with no premium.
|
The income approach methodologies were consistent with the
approach for determining fair value at December 31, 2007
and 2006. Significant assumptions and judgments impacting the
Companys goodwill impairment assessment included
managements projections of operating results and capital
expenditure requirements, risk-adjusted discount rates, market
performance, and other factors. Under all methodologies, the
calculated NRG Texas equity value exceeded the NRG Texas book
value, and the Company concluded that goodwill was not impaired
as of December 31, 2008.
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.
125
|
|
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 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, oil, and emissions credits. 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 forwards, futures, swaps, and option
contracts traded on various exchanges, such as New York
Mercantile Exchange, or NYMEX, Intercontinental Exchange, or
ICE, and Chicago Climate Exchange, or CCX, as well as
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 risk of the Companys portfolio using
several analytical methods, including sensitivity tests,
scenario tests, stress tests, position reports, and 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: (i) a lognormal
126
distribution of prices,
(ii) one-day
holding period, (iii) a 95% confidence interval,
(iv) a rolling
36-month
forward looking period, and (v) market implied volatilities
and historical price correlations.
As of December 31, 2008, the VAR for NRGs commodity
portfolio, including generation assets, load obligations and
bilateral physical and financial transactions calculated using
the diversified VAR model was $43 million.
The following table summarizes average, maximum and minimum VAR
for NRG for the year ended December 31, 2008 and 2007:
|
|
|
|
|
VAR
|
|
In millions
|
|
|
As of December 31, 2008
|
|
$
|
43
|
|
Average
|
|
|
50
|
|
Maximum
|
|
|
65
|
|
Minimum
|
|
|
35
|
|
As of December 31,
2007(a)
|
|
$
|
64
|
|
Average
|
|
|
28
|
|
Maximum
|
|
|
64
|
|
Minimum
|
|
|
14
|
|
|
|
|
(a)
|
|
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, 2008, for the
entire term of these instruments entered into for both asset
management and trading, was approximately $35 million
primarily driven by
asset-backed
transactions.
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, 2008 was $1.9 billion.
127
The maturities and notional amounts of each tranche of these
swaps in connection with the Senior Credit Facility are as
follows:
|
|
|
|
|
Maturity
|
|
Notional Value
|
|
|
March 31, 2009
|
|
$
|
150 million
|
|
March 31, 2010
|
|
$
|
190 million
|
|
March 31, 2011
|
|
$
|
1.55 billion
|
|
In addition to those listed above, the Company had the following
additional interest rate swaps outstanding as of
December 31, 2008:
|
|
|
|
|
|
|
|
|
Notional Value
|
|
Maturity
|
|
Floating to fixed interest rate swap for NRG Peaker Financing LLC
|
|
$
|
266 million
|
|
|
June 10, 2019
|
Fixed to floating interest rate swap for Senior notes, due 2014
|
|
$
|
400 million
|
|
|
December 15, 2013
|
If all of the above swaps had been discontinued on
December 31, 2008, the Company would have owed the
counterparties approximately $156 million. Based on the
investment grade rating of the counterparties, 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, 2008, a 1% change
in interest rates would result in a $12.8 million change in
interest expense on a rolling twelve month basis.
As of December 31, 2008, the Companys long-term debt
fair value was $7.5 billion and the carrying amount was
$8.0 billion. NRG estimates that a 1% decrease in market
interest rates would have increased the fair value of the
Companys long-term debt by $401 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 MMBtu increase or
decrease in natural gas prices across the term of the marginable
contracts for power and gas positions would cause a change in
margin collateral outstanding of approximately $72 million
as of December 31, 2008. In addition, a 0.25 MMBtu/MWh
change in heat rates for heat rate positions would result in a
change in margin collateral of approximately $82 million as
of December 31, 2008. This analysis uses simplified
assumptions and is calculated based on portfolio composition and
margin-related contract provisions as of December 31, 2008.
Under the second lien, NRG is required to post certain letter of
credits as credit support for changes in commodity prices. As of
December 31, 2008, $19 million in letters of credit
are outstanding to second lien counterparties. With changes in
commodity prices, the letters of credit could grow to
$87 million, the cap under the agreements.
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 credit risk through credit policies that include:
(i) an established credit approval process, (ii) a
daily monitoring of counterparties credit limits,
(iii) the use of credit mitigation measures such as margin,
collateral, credit derivatives or prepayment
128
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
seeks to mitigate counterparty risk with a diversified portfolio
of counterparties, including ten participants under its first
and second lien structure. The Company also has credit
protection within various agreements to call on additional
collateral support if and when necessary. Cash margin is
collected and held at NRG to cover the credit risk of the
counterparty until positions settle.
A sharp economic downturn in the US and overseas markets during
the latter part of 2008 was prompted by a combination of
factors: tight credit markets, speculation and fear over the
health of the US and global financial systems, and weaker
economic activity in general prompting fears of an economic
recession. Under the current market dynamics, the Company has
heightened its management and mitigation of counterparty credit
risk by using credit limits, netting agreements, collateral
thresholds, volumetric limits and other mitigation measures,
where available. NRG avoids concentration of counterparties
whenever possible and applies credit policies that include an
evaluation of counterparties financial condition,
collateral requirements and the use of standard agreements that
allow for netting and other security.
As of December 31, 2008, total credit exposure to
substantially all counterparties was $2.0 billion and NRG
held collateral (cash and letters of credit) against those
positions of $788 million resulting in a net exposure of
$1.2 billion. Total credit exposure is discounted at the
risk free rate.
The following table highlights the credit quality and the net
counterparty credit exposure by industry sector. Net
counterparty credit risk is defined as the aggregate net asset
position for NRG with counterparties where netting is permitted
under the enabling agreement and includes all cash flow, mark to
market and normal purchase and sale and non-derivative
transactions. The exposure is shown net of collateral held, and
includes amounts net of receivables or payables.
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
|
Coal producers
|
|
|
16
|
%
|
Financial institutions
|
|
|
58
|
|
Utilities, energy, merchants and marketers
|
|
|
21
|
|
ISOs
|
|
|
5
|
|
|
|
|
|
|
Total as of December 31, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
|
Investment grade
|
|
|
81
|
%
|
Non-Investment grade
|
|
|
8
|
|
Non-rated
|
|
|
11
|
|
|
|
|
|
|
Total as of December 31, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
(a)
|
|
Credit exposure excludes California
tolling, uranium, coal transportation/railcar leases, New
England Reliability Must-Run, cooperative load contracts and
Texas Westmoreland coal contracts.
|
NRG has credit risk exposure to certain counterparties
representing more than 10% of total net exposure and the
aggregate of such counterparties was $241 million. No
counterparty represents more than 20% of total net credit
exposure. Approximately 80% of NRGs positions relating to
credit risk roll-off by the end of 2011. Changes in hedge
positions and market prices will affect credit exposure and
counterparty concentration. 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.
129
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,
2008, 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 US 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 and approximately
$58 million in pre-tax unrealized income reflected in the
currency translation adjustment component of 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 the effectiveness of the design and
operation 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 2008 Annual Report to
Shareholders.
Changes
in Internal Control over Financial Reporting
Except for the remediation of the material weakness discussed
below, there were no changes in the Companys internal
control over financial reporting (as such term is defined in
Rule 13a-15(f)
under the Exchange Act) that occurred in the fourth quarter of
2008 that materially affected, or are reasonably likely to
materially affect, the Companys internal control over
financial reporting.
Material
Weakness Related to Operating Revenues
Subsequent to the filing of the September 30, 2008
Form 10-Q,
the Company identified a material weakness in our internal
control over financial reporting related to the accounting for
option premiums on certain derivative instruments. This material
weakness resulted from the operational ineffectiveness of
reconciliation and review controls specifically related to our
accounting for premiums on energy options.
The material weakness resulted in an error to operating revenues
of $78 million in the third quarter of 2008. In this
Form 10-K,
we have revised our unaudited quarterly financial data for the
quarter ended September 30, 2008. For further information,
see Item 15 Note 27, Unaudited
Quarterly Financial Data, to the Consolidated Financial
Statements.
130
In connection with this material weakness, we reevaluated our
disclosure controls and procedures as of September 30,
2008. Based on this reevaluation, and solely as a result of this
material weakness, the Companys principal executive
officer, principal financial officer and principal accounting
officer concluded that the disclosure controls and procedures
were not effective as of September 30, 2008.
Remediation
of Material Weakness in Internal Control
During the fourth quarter, a number of remedial actions were
taken to address the material weakness, which included:
|
|
|
|
|
Reviewing and documenting all mark-to-market logic in our power
marketing trading activity system, including any manual
adjustments related thereto;
|
|
|
|
Formalizing and documenting energy options accounting;
|
|
|
|
Formalizing the analysis and review by management of realized
and unrealized gain/(loss) derivative accounts;
|
|
|
|
Expanding the communication process between accounting, risk
management and commercial operations groups to understand
derivative accounting results and changes in the commercial
operations portfolio; and
|
|
|
|
Establishing ongoing training and education in the
Companys accounting group on accounting for derivative
option premiums
|
We have completed the process of implementing the aforementioned
enhancements, and believe that we have fully remediated the
material weakness in our internal control over financial
reporting with respect to the appropriate accounting for option
premiums on certain derivative instruments as of
December 31, 2008.
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
|
None.
131
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 2009 Annual Meeting of
Stockholders.
|
|
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 2009 Annual Meeting of
Stockholders.
|
|
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 2009 Annual Meeting of
Stockholders.
|
|
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 2009 Annual Meeting of
Stockholders.
|
|
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 2009 Annual Meeting of
Stockholders.
132
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, 2008, 2007 and 2006
Consolidated Balance Sheet December 31, 2008
and 2007
Consolidated Statement of Cash Flows Years ended
December 31, 2008, 2007 and 2006
Consolidated Statement of Stockholders Equity and
Comprehensive Income/(Loss) Years ended
December 31, 2008, 2007 and 2006
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.
133
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, 2008.
The effectiveness of the Companys internal control over
financial reporting as of December 31, 2008 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.
134
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, 2008, 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, 2008, 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. and subsidiaries
as of December 31, 2008 and 2007, 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, 2008, and
our report dated February 12, 2009 expressed an unqualified
opinion on those consolidated financial statements.
/s/ KPMG LLP
KPMG LLP
Philadelphia, Pennsylvania
February 12, 2009
135
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, 2008
and 2007, and the related consolidated statements of operations,
consolidated statement of stockholders equity and
comprehensive income/(loss), and consolidated statements of cash
flows for each of the years in the three-year period ended
December 31, 2008. 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, 2008 and 2007, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2008, 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, in order to comply with the requirements of
U.S. generally accepted accounting principles, the Company
adopted Statement of Financial Accounting Standards (SFAS)
No. 157, Fair Value Measurements, effective January 1,
2008; FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes an Interpretation of
SFAS No. 109, effective January 1, 2007; Emerging
Issues Task Force Issue
No. 04-6,
Accounting for Stripping Costs Incurred during Production in the
Mining Industry, and SFAS No. 123R, Share Based
Payments, and related interpretations effective January 1,
2006; and SFAS No 158, Employers Accounting for
Defined Benefit Pension and Other Postretirement
Plans an amendment of SFAS No. 87, 88, 106
and 132R, effective December 31, 2006.
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, 2008, 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 12, 2009 expressed an
unqualified opinion on the effectiveness of the Companys
internal control over financial reporting.
/s/ KPMG LLP
KPMG LLP
Philadelphia, Pennsylvania
February 12, 2009
136
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions except per share amounts)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,885
|
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,598
|
|
|
|
3,378
|
|
|
|
3,265
|
|
Depreciation and amortization
|
|
|
649
|
|
|
|
658
|
|
|
|
590
|
|
General and administrative
|
|
|
319
|
|
|
|
309
|
|
|
|
276
|
|
Development costs
|
|
|
46
|
|
|
|
101
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,612
|
|
|
|
4,446
|
|
|
|
4,167
|
|
Gain on sale of assets
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
2,273
|
|
|
|
1,560
|
|
|
|
1,418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
59
|
|
|
|
54
|
|
|
|
60
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
8
|
|
Other income, net
|
|
|
17
|
|
|
|
55
|
|
|
|
156
|
|
Refinancing expenses
|
|
|
|
|
|
|
(35
|
)
|
|
|
(187
|
)
|
Interest expense
|
|
|
(620
|
)
|
|
|
(689
|
)
|
|
|
(590
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(544
|
)
|
|
|
(614
|
)
|
|
|
(553
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
1,729
|
|
|
|
946
|
|
|
|
865
|
|
Income tax expense
|
|
|
713
|
|
|
|
377
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
1,016
|
|
|
|
569
|
|
|
|
543
|
|
Income from discontinued operations, net of income taxes
|
|
|
172
|
|
|
|
17
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
1,188
|
|
|
|
586
|
|
|
|
621
|
|
Dividends for preferred shares
|
|
|
55
|
|
|
|
55
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Available for Common Stockholders
|
|
$
|
1,133
|
|
|
$
|
531
|
|
|
$
|
571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
basic
|
|
|
235
|
|
|
|
240
|
|
|
|
258
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
4.09
|
|
|
$
|
2.14
|
|
|
$
|
1.90
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
0.73
|
|
|
|
0.07
|
|
|
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Basic
|
|
$
|
4.82
|
|
|
$
|
2.21
|
|
|
$
|
2.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
275
|
|
|
|
288
|
|
|
|
301
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
3.66
|
|
|
$
|
1.95
|
|
|
$
|
1.78
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
0.63
|
|
|
|
0.06
|
|
|
|
0.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Diluted
|
|
$
|
4.29
|
|
|
$
|
2.01
|
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
137
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
Funds deposited by counterparties
|
|
|
754
|
|
|
|
|
|
Restricted cash
|
|
|
16
|
|
|
|
29
|
|
Accounts receivable trade, less allowance for
doubtful accounts
of $3 and $1
|
|
|
464
|
|
|
|
482
|
|
Current portion of note receivable affiliate and
capital leases
|
|
|
68
|
|
|
|
30
|
|
Inventory
|
|
|
455
|
|
|
|
451
|
|
Derivative instruments valuation
|
|
|
4,600
|
|
|
|
1,034
|
|
Deferred income taxes
|
|
|
|
|
|
|
124
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
494
|
|
|
|
85
|
|
Prepayments and other current assets
|
|
|
147
|
|
|
|
144
|
|
Current assets discontinued operations
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
8,492
|
|
|
|
3,562
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
In service
|
|
|
13,084
|
|
|
|
12,678
|
|
Under construction
|
|
|
804
|
|
|
|
337
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
13,888
|
|
|
|
13,015
|
|
Less accumulated depreciation
|
|
|
(2,343
|
)
|
|
|
(1,695
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
11,545
|
|
|
|
11,320
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
490
|
|
|
|
425
|
|
Capital leases and note receivable, less current portion
|
|
|
435
|
|
|
|
491
|
|
Goodwill
|
|
|
1,718
|
|
|
|
1,786
|
|
Intangible assets, net of accumulated amortization of $335 and
$372
|
|
|
815
|
|
|
|
873
|
|
Nuclear decommissioning trust fund
|
|
|
303
|
|
|
|
384
|
|
Derivative instruments valuation
|
|
|
885
|
|
|
|
150
|
|
Other non-current assets
|
|
|
125
|
|
|
|
190
|
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
4,771
|
|
|
|
4,392
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
24,808
|
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
138
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS (Continued)
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions, except share
|
|
|
|
data)
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
464
|
|
|
$
|
466
|
|
Accounts payable trade
|
|
|
447
|
|
|
|
381
|
|
Accounts payable affiliates
|
|
|
4
|
|
|
|
3
|
|
Derivative instruments valuation
|
|
|
3,981
|
|
|
|
917
|
|
Deferred income taxes
|
|
|
201
|
|
|
|
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
760
|
|
|
|
14
|
|
Accrued interest expense
|
|
|
178
|
|
|
|
185
|
|
Other accrued expenses
|
|
|
215
|
|
|
|
189
|
|
Other current liabilities
|
|
|
331
|
|
|
|
85
|
|
Current liabilities discontinued operations
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
6,581
|
|
|
|
2,277
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
7,704
|
|
|
|
7,895
|
|
Nuclear decommissioning reserve
|
|
|
284
|
|
|
|
307
|
|
Nuclear decommissioning trust liability
|
|
|
218
|
|
|
|
326
|
|
Postretirement and other benefit obligations
|
|
|
277
|
|
|
|
263
|
|
Deferred income taxes
|
|
|
1,190
|
|
|
|
843
|
|
Derivative instruments valuation
|
|
|
508
|
|
|
|
759
|
|
Out-of-market contracts
|
|
|
291
|
|
|
|
628
|
|
Other non-current liabilities
|
|
|
392
|
|
|
|
149
|
|
Non-current liabilities discontinued operations
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
10,864
|
|
|
|
11,246
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
17,445
|
|
|
|
13,523
|
|
|
|
|
|
|
|
|
|
|
Minority Interest
|
|
|
7
|
|
|
|
|
|
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, 1,841,680 shares issued and outstanding at
December 31, 2008, (at liquidation value of $462, net of
issuance costs) and 2,000,000 shares issued and outstanding
at December 31, 2007 (at liquidation value of $500, net of
issuance costs)
|
|
|
447
|
|
|
|
486
|
|
Common Stock; $0.01 par value; 500,000,000 shares
authorized; 263,599,200 and 261,285,529 shares issued and
234,356,717 and 236,734,929 shares outstanding at
December 31, 2008 and 2007
|
|
|
3
|
|
|
|
3
|
|
Additional
paid-in-capital
|
|
|
4,363
|
|
|
|
4,092
|
|
Retained earnings
|
|
|
2,403
|
|
|
|
1,270
|
|
Less treasury stock, at cost 29,242,483 and
24,550,600 shares at December 31, 2008 and 2007
|
|
|
(823
|
)
|
|
|
(638
|
)
|
Accumulated other comprehensive income/(loss)
|
|
|
310
|
|
|
|
(115
|
)
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity
|
|
|
7,109
|
|
|
|
5,504
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
24,808
|
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
139
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, 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,188
|
|
|
|
|
|
|
|
|
|
|
|
1,188
|
|
Foreign currency translation adjustments, net of $22 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(112
|
)
|
|
|
(112
|
)
|
Reclassification adjustment for translation loss realized upon
sale of ITISA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
15
|
|
Unrealized gain on derivatives, net of $369 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
580
|
|
|
|
580
|
|
Available-for-sale securities, net of $2 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
(4
|
)
|
Defined benefit plan prior service credit of $1 and
net loss of $55, net of $35 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,613
|
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
(185
|
)
|
Reduction to tax valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
NINA contribution, net of $17 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
5.75% preferred stock conversion to common stock
|
|
|
(39
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
1
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008
|
|
$
|
853
|
|
|
|
2.3
|
|
|
$
|
3
|
|
|
|
234
|
|
|
$
|
4,363
|
|
|
$
|
2,403
|
|
|
$
|
(823
|
)
|
|
$
|
310
|
|
|
$
|
7,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
140
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,188
|
|
|
$
|
586
|
|
|
$
|
621
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions less than equity in earnings of unconsolidated
affiliates
|
|
|
(44
|
)
|
|
|
(33
|
)
|
|
|
(33
|
)
|
Depreciation and amortization
|
|
|
649
|
|
|
|
661
|
|
|
|
607
|
|
Amortization of nuclear fuel
|
|
|
39
|
|
|
|
58
|
|
|
|
47
|
|
Amortization and write-off of financing costs and debt
discount/premiums
|
|
|
29
|
|
|
|
66
|
|
|
|
79
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(270
|
)
|
|
|
(156
|
)
|
|
|
(490
|
)
|
Amortization of unearned equity compensation
|
|
|
26
|
|
|
|
19
|
|
|
|
14
|
|
Gains on sale of equity method investments
|
|
|
|
|
|
|
(1
|
)
|
|
|
(8
|
)
|
Loss/(gain) on disposals and sales of assets
|
|
|
25
|
|
|
|
(17
|
)
|
|
|
10
|
|
Impairment charges and asset write downs
|
|
|
23
|
|
|
|
20
|
|
|
|
|
|
Changes in derivatives
|
|
|
(484
|
)
|
|
|
77
|
|
|
|
(149
|
)
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
762
|
|
|
|
359
|
|
|
|
327
|
|
Gain on legal settlement
|
|
|
|
|
|
|
|
|
|
|
(67
|
)
|
Gain on sale of discontinued operations
|
|
|
(273
|
)
|
|
|
|
|
|
|
(76
|
)
|
Gain on sale of emission allowances
|
|
|
(51
|
)
|
|
|
(31
|
)
|
|
|
(64
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
34
|
|
|
|
32
|
|
|
|
12
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(417
|
)
|
|
|
(125
|
)
|
|
|
454
|
|
Settlement of out-of-market power contracts
|
|
|
|
|
|
|
|
|
|
|
(1,073
|
)
|
Cash provided/(used) by changes in other working capital, net of
acquisition and disposition effects
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
|
1
|
|
|
|
(102
|
)
|
|
|
87
|
|
Inventory
|
|
|
(5
|
)
|
|
|
(38
|
)
|
|
|
(50
|
)
|
Prepayments and other current assets
|
|
|
(7
|
)
|
|
|
22
|
|
|
|
43
|
|
Accounts payable
|
|
|
(31
|
)
|
|
|
49
|
|
|
|
(73
|
)
|
Accrued expenses and other current liabilities
|
|
|
262
|
|
|
|
106
|
|
|
|
133
|
|
Other assets and liabilities
|
|
|
(22
|
)
|
|
|
(35
|
)
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
1,434
|
|
|
|
1,517
|
|
|
|
408
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Texas Genco, WCP and Padoma, net of cash acquired
|
|
|
|
|
|
|
|
|
|
|
(4,333
|
)
|
Capital expenditures
|
|
|
(899
|
)
|
|
|
(481
|
)
|
|
|
(221
|
)
|
Decrease in restricted cash, net
|
|
|
13
|
|
|
|
12
|
|
|
|
6
|
|
Decrease in notes receivable
|
|
|
10
|
|
|
|
34
|
|
|
|
27
|
|
Decrease in trust fund balances
|
|
|
|
|
|
|
19
|
|
|
|
|
|
Purchases of emission allowances
|
|
|
(8
|
)
|
|
|
(161
|
)
|
|
|
(135
|
)
|
Proceeds from sale of emission allowances
|
|
|
75
|
|
|
|
272
|
|
|
|
146
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(616
|
)
|
|
|
(265
|
)
|
|
|
(227
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
582
|
|
|
|
233
|
|
|
|
214
|
|
Proceeds from sale of assets
|
|
|
14
|
|
|
|
2
|
|
|
|
86
|
|
Equity investment in unconsolidated affiliate
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
Purchases of securities
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
Proceeds from sale of discontinued operations and assets, net of
cash divested
|
|
|
241
|
|
|
|
57
|
|
|
|
260
|
|
Return of capital from equity method investments
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used by Investing Activities
|
|
|
(672
|
)
|
|
|
(327
|
)
|
|
|
(4,176
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
(55
|
)
|
|
|
(55
|
)
|
|
|
(50
|
)
|
Payment of financing element of acquired derivatives
|
|
|
(43
|
)
|
|
|
|
|
|
|
(296
|
)
|
Payment for treasury stock
|
|
|
(185
|
)
|
|
|
(353
|
)
|
|
|
(732
|
)
|
Proceeds from sale of minority interest in subsidiary
|
|
|
50
|
|
|
|
|
|
|
|
|
|
Funded letter of credit
|
|
|
|
|
|
|
|
|
|
|
350
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
9
|
|
|
|
7
|
|
|
|
986
|
|
Proceeds from issuance of preferred shares, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
486
|
|
Proceeds from issuance of long-term debt
|
|
|
20
|
|
|
|
1,411
|
|
|
|
8,619
|
|
Payment of deferred debt issuance costs
|
|
|
(4
|
)
|
|
|
(5
|
)
|
|
|
(199
|
)
|
Payments for short and long-term debt
|
|
|
(234
|
)
|
|
|
(1,819
|
)
|
|
|
(5,111
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(442
|
)
|
|
|
(814
|
)
|
|
|
4,053
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
43
|
|
|
|
(25
|
)
|
|
|
2
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
(1
|
)
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Cash Equivalents
|
|
|
362
|
|
|
|
355
|
|
|
|
291
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
1,132
|
|
|
|
777
|
|
|
|
486
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
|
$
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
141
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1
|
Nature of
Business
|
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 US. 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 US and select international markets.
As of December 31, 2008, NRG had a total global portfolio
of 189 active operating fossil fuel and nuclear generation
units, at 48 power generation plants, with an aggregate
generation capacity of approximately 24,005 MW, and
approximately 550 MW under construction which includes
partners interests of 275 MW. In addition, NRG has
ownership interests in two wind farms representing an aggregate
generation capacity of 270 MW, which includes partner
interests of 75 MW. Within the US, NRG has one of the
largest and most diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 22,925 MW of fossil fuel and nuclear
generation capacity in 177 active generating units at 43 plants
and ownership interests in two wind farms representing
195 MW of wind generation capacity. These power generation
facilities are primarily located in Texas (approximately
11,010 MW, including the 195 MW from the two wind
farms), the Northeast (approximately 7,020 MW), South
Central (approximately 2,845 MW), and West (approximately
2,130 MW) regions of the US, and 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, or
FIN, No. 46R, 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
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 has investments in partnerships,
joint ventures and projects, one of which is a VIE for which the
Company is not the primary beneficiary.
Accounting policies for all of NRGs operations are in
accordance with accounting principles generally accepted in the
US. Upon its emergence from bankruptcy on December 5, 2003,
the Company qualified for and
142
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
adopted fresh start reporting, or Fresh Start, under Statement
of Position
90-7,
Financial Reporting by Entities in Reorganization under the
Bankruptcy Code.
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.
Funds
Deposited by Counterparties
Funds deposited by counterparties consist of cash held as
collateral from hedge counterparties in support of energy risk
management activities, and at December 31, 2008, it is the
Companys intention to limit the use of these funds.
Depending on market fluctuations and the settlement of the
underlying contracts, the Company will refund this collateral to
the hedge counterparties pursuant to the terms and conditions of
the underlying trades. No such restrictions were imposed by the
Company in prior periods, and the amount of cash collateral held
at December 31, 2007 was immaterial. Changes in funds
deposited by counterparties are closely associated with the
Companys operating activities, and are classified as an
operating activity in the Companys consolidated statements
of cash flows.
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.
Trade
Receivables
Trade receivables are reported in the balance sheet at
outstanding principal adjusted for any write-offs and the
allowance for doubtful accounts.
Inventory
Inventory is valued at the lower of weighted average cost or
market, unless evidence indicates that the weighted average cost
will be recovered with a normal profit in the ordinary course of
business, and consists principally of fuel oil, coal and raw
materials used to generate steam. The Company removes these
inventories as they are used in the production of electricity or
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. The Company removes these
inventories when they are used for repairs, maintenance or
capital projects. 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.
143
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 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 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 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
Project 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.
Interest incurred on funds borrowed to finance capital projects
is capitalized if material, until the project under construction
is ready for its intended use. The amount of interest
capitalized for the years ended December 31, 2008, 2007 and
2006 was $45 million, $11 million and $5 million,
respectively.
When a project is available for operations, capitalized interest
and project development 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.
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 a contracted volumes,
straight line or units of production basis.
144
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2008.
Goodwill
In accordance with 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.
|
Income
Taxes
NRG accounts for income taxes using the liability method in
accordance with 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 assets to
an amount that is more-likely-than-not to be realized.
In January 2007, the Company adopted FIN No. 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. Under FIN 48, tax
benefits are recognized 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.
145
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
Emerging Issues Task Force, or 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 billed to 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 revenue in the
Companys consolidated statements of operations.
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 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 OCI until
the hedged transactions occur and are recognized in earnings.
|
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. In this case, the gain or
loss previously deferred in OCI would be immediately
reclassified into earnings. If the derivative instrument is
terminated, the effective portion of this derivative in OCI will
be frozen until the underlying hedged item is delivered.
146
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Revenues and expenses on contracts that qualify for the NPNS
exception are recognized when the underlying physical
transaction is delivered. 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
that 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.
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 not included in
the determination of the Companys statements of operations
for the period, but are accumulated and reported as a separate
component of stockholders equity until sale or complete or
substantially complete liquidation of the net investment in the
foreign entity takes place. Foreign currency transaction gains
or losses are reported within other income/(expense) in the
Companys statements of operations. For the years ended
December 31, 2008, 2007 and 2006, 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, derivatives, and
investments in debt securities. Cash and cash equivalents and
funds deposited by counterparties are predominantly held in
money market funds invested in treasury securities or treasury
repurchase agreements. 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 and other contractual
arrangements are subject to collateral requirements under the
terms of enabling agreements. However, NRG believes that the
credit risk posed by industry concentration is offset by the
diversification and creditworthiness of the Companys
customer base. See Note 5, Accounting for Derivative
Instruments and Hedging Activities, for a further discussion
of derivative concentrations.
Fair
Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds
deposited by counterparties, 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, Fair Value of
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. For the years
ended December 31, 2008 and 2007, the Company recorded
impairment charges related to an investment in commercial paper
of $23 million and $11 million, respectively; reducing
its carrying value to approximately $7 million.
147
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Asset
Retirement Obligations
NRG accounts for its asset retirement obligations, or AROs, in
accordance with SFAS No. 143, Accounting for Asset
Retirement Obligations, or SFAS 143, and
FIN No. 47, Accounting for Conditional Asset
Retirement Obligations, or FIN 47. Retirement
obligations associated with long-lived assets included within
the scope of SFAS 143 and FIN 47 are those for which a
legal obligation exists under enacted laws, statutes, and
written or oral contracts, including obligations arising under
the doctrine of promissory estoppel, and for which the timing
and/or
method of settlement may be conditional on a future event.
SFAS 143 and FIN 47 require an entity to recognize the
fair value of a liability for an ARO in the period in which it
is incurred and a reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, NRG
capitalizes the asset retirement cost by increasing the carrying
amount of the related long-lived asset by the same amount. Over
time, the liability is accreted to its future value, while the
capitalized cost is depreciated over the useful life of the
related asset.
NRGs AROs are primarily related to the future
dismantlement of equipment on leased property and environmental
obligations related to nuclear decommissioning, ash disposal,
site closures, and fuel storage facilities. In addition, NRG has
also identified conditional AROs for asbestos removal and
disposal, which are specific to certain power generation
operations. See Note 6, Nuclear Decommissioning
Trust Fund, for a further discussion of NRGs
nuclear decommissioning obligations.
The following table represents the balance of ARO obligations as
of December 31, 2008 and 2007, along with the additions,
reductions and accretion related to the Companys ARO
obligations for the year ended December 31, 2008:
|
|
|
|
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Balance as of December 31, 2007
|
|
$
|
409
|
|
Additions
|
|
|
1
|
|
Revisions in estimated cashflows
|
|
|
(41
|
)
|
Accretion Expense
|
|
|
7
|
|
Accretion Other
|
|
|
17
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
$
|
393
|
|
|
|
|
|
|
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.
As of December 31, 2008, NRG measured the fair value of its
pension assets in accordance with SFAS 157, Fair Value
Measurements.
148
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Stock-Based
Compensation
NRG accounts for its stock-based compensation in accordance with
SFAS No. 123 (Revised 2004), Share-Based
Payment, or SFAS 123R. 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 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. 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.
Issuance
of Subsidiarys Stock
The Company accounts for issuance of its subsidiaries
stock in accordance with SEC Staff Accounting
Bulletin Topic 5H, Accounting For Sales Of Stock By A
Subsidiary, or Topic 5H. Topic 5H precludes recognizing any
gain on issuance of a subsidiarys stock into earnings when
the subsidiary is a development stage entity. In March 2008, NRG
formed NINA, an NRG development stage subsidiary focused on
developing, financing, and investing in nuclear projects in
North America. TANE has partnered with NRG on the NINA venture,
receiving a 12% equity ownership in NINA in exchange for
$300 million to be invested in NINA in six annual
installments of $50 million, the last three of which are
subject to certain restrictions. NRG continues to control NINA
through its voting interest. Any change in NRGs
proportionate share of NINAs equity resulting from cash
invested by TANE directly into NINA is accounted for by the
Company as an equity transaction in consolidation, and not a
gain on sale, for as long as NINA remains a development stage
entity.
Accordingly, upon TANEs initial $50 million
installment contribution in April 2008, $44 million, or
88%, was recorded as additional paid in capital, while the
remaining $6 million, or 12%, was recorded as minority
interest on the Companys consolidated balance sheet.
Use of
Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the US 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
149
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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
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 and goodwill 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.
Recent
Accounting Developments
The Company partially adopted SFAS No. 157, Fair
Value Measurements, or SFAS 157, on January 1,
2008, delaying application for non-financial assets and
non-financial liabilities as permitted. This statement defines
fair value, establishes a framework for measuring fair value,
and expands disclosures about fair value measurements. 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 SFAS 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
non-financial assets and non-financial 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. The partial adoption
of SFAS 157 on January 1, 2008 did not have a material
impact on the Companys consolidated financial position,
statement of operations, and cash flows. The Company adopted the
remaining portion of SFAS 157 for non-financial assets and
non-financial liabilities on January 1, 2009, with no
impact on the Companys consolidated financial position,
statement of operations, and cash flows.
The Company adopted SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities-including
an amendment of FASB Statement No. 115, or
SFAS 159, on January 1, 2008. This statement provides
entities with an option to measure and report selected financial
assets and liabilities at fair value. The Company does not
intend to apply this standard to any of its eligible assets or
liabilities; therefore, there was no impact on NRGs
consolidated financial position, results of operations, or cash
flows.
The Company adopted FSP
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, on January 1, 2008. FSP
FIN 39-1
impacts entities that enter into master netting arrangements as
part of their derivative transactions. Under the guidance in
this 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. The Company chose not to offset positions as
defined in this FSP; 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 141R.
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
150
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 adopted SFAS 141R on
January 1, 2009, with no immediate impact on the
Companys results of operations, financial position and
cash flows. However, any future reductions to existing net
deferred tax assets or valuation allowances, and changes to
uncertain tax benefits, as they relate to Fresh Start or
previously completed acquisitions, occurring after
January 1, 2009 will be recorded to income tax expense
rather than APIC or goodwill, respectively.
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 141R. 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 adopted SFAS 160 on January 1,
2009, with no material impact on the Companys consolidated
financial position, statement of operations, and cash flows.
In March 2008, the FASB issued SFAS No. 161,
Disclosures About Derivative Instruments and Hedging
Activities, or SFAS 161. SFAS 161 requires
entities to provide enhanced disclosures about how and why an
entity uses derivative instruments, how derivative instruments
and related hedged items are accounted for under
SFAS No. 133 and how derivative instruments and
related hedged items affect an entitys financial position,
financial performance, and cash flows. This statement
encourages, but does not require, comparative disclosures for
earlier periods at initial adoption. SFAS 161 is effective
for financial statements issued for fiscal years and interim
periods beginning after November 15, 2008, with early
application encouraged. NRG adopted SFAS 161 on
January 1, 2009, with no impact on the Companys
results of operations, financial position, or cash flows.
In April 2008, the FASB issued FSP
No. FAS 142-3,
Determination of the Useful Life of Intangible Assets, or
FSP
FAS 142-3.
This FSP amends the factors that should be considered in
developing renewal or extension assumptions used to determine
the useful life of a recognized intangible asset under
SFAS 142. FSP
FAS 142-3
is effective for financial statements issued for fiscal years
beginning after December 15, 2008, and interim periods
within those fiscal years, with early adoption prohibited. NRG
adopted FSP
FAS 142-3
on January 1, 2009, with no impact on the Companys
results of operations, financial position and cash flows.
In May 2008, the FASB issued FSP No. APB
14-1,
Accounting for Convertible Debt Instruments That May Be
Settled in Cash upon Conversion (Including Partial Cash
Settlement), or FSP APB
14-1. This
FSP clarifies that convertible debt instruments that may be
settled in cash upon conversion (including partial cash
settlement) do not fall within the scope of paragraph 12 of
Accounting Principles Board Opinion No. 14, Accounting
for Convertible Debt and Debt Issued with Stock Purchase
Warrants, and specifies that issuers of such instruments
should separately account for the liability and equity
components in a manner that will reflect the entitys
nonconvertible debt borrowing rate when interest cost is
recognized in subsequent periods. FSP APB
14-1 does
not apply to embedded conversion options that must be separately
accounted for as derivatives under SFAS 133. FSP APB
14-1 is
effective for financial statements issued for fiscal years
beginning after December 15, 2008 and interim periods
within those fiscal years and is to be applied retrospectively.
NRG adopted FSP APB
14-1 on
January 1, 2009, with no material impact on the
Companys results of operations, financial position, or
cash flows.
In June 2008, the EITF issued EITF
No. 07-5,
Determining Whether an Instrument (or Embedded Feature) Is
Indexed to an Entitys Own Stock, or
EITF 07-5.
EITF 07-5
clarifies that contingent and other adjustment features in
equity-linked financial instruments are consistent with equity
indexation if they are based on variables that would be inputs
to a plain vanilla option or forward pricing model
and they do not increase the contracts exposure to those
variables.
EITF 07-5
is effective for financial statements issued for fiscal years
beginning after December 15,
151
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
2008, and interim periods within those fiscal years. NRG adopted
EITF 07-5
on January 1, 2009, with no impact on the Companys
results of operations, financial position, or cash flows.
In September 2008, the FASB issued FSP
No. FAS 133-1
and
FIN 45-4,
Disclosures about Credit Derivatives and Certain Guarantees:
An Amendment of FASB Statement No. 133 and Financial
Interpretation Number 45; and Clarification of the Effective
Date of FASB Statement No. 161, or FSP
FAS 133-1
and
FIN 45-4.
This FSP amends FAS 133, and FIN No. 45
Guarantors Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others, or FIN 45, to require additional disclosures
about credit derivatives, credit derivatives embedded in a
hybrid instrument, and the current status of the payment or
performance risk of a guarantee. FSP
FAS 133-1
and
FIN 45-4
is effective for the financial statements of reporting periods
(annual or interim) ending after November 15, 2008. NRG
currently has no credit derivative contracts, so the amendments
in this FSP related to FAS 133 will not impact NRG. The
clarification to SFAS 161 is also not applicable to NRG, as
it only affects non-calendar year filers. NRG adopted the
provisions of this FSP related to FIN 45 on January 1,
2009, with no impact on the Companys results of
operations, financial position, or cash flows.
In September 2008, the EITF issued
EITF 08-5,
Issuers Accounting for Liabilities Measured at Fair
Value with a Third-Party Credit Enhancement, or
EITF 08-5.
EITF 08-5
requires issuers of liability instruments with third-party
credit enhancements to exclude the effect of the credit
enhancement when measuring the liabilitys fair value. The
effect of initially applying the requirements is included in the
change in the instruments fair value in the period of
adoption. Entities are required to disclose the valuation
technique used to measure the liabilities and to discuss any
changes in the valuation techniques used to measure those
liabilities in earlier periods. Entities will also need to
disclose the existence of a third-party credit enhancement on
the entitys issued debt.
EITF 08-5
is effective on a prospective basis in the first reporting
period beginning on or after December 15, 2008, with
earlier application permitted. NRG adopted
EITF 08-5
on January 1, 2009, with no impact on the Companys
results of operations, financial position, or cash flows.
In October 2008, the FASB issued FSP
No. FAS 157-3,
Determining the Fair Value of a Financial Asset When the
Market for That Asset Is Not Active, or FSP
FAS 157-3.
This FSP clarifies the application of SFAS 157 in a market
that is not active and provides an example to illustrate key
considerations in determining the fair value of a financial
asset when the market for that financial asset is not active.
FSP
FAS 157-3
is effective upon issuance, including prior periods for which
financial statements have not been issued. Revisions resulting
from a change in the valuation technique or its application
shall be accounted for as a change in accounting estimate under
SFAS No. 154, Accounting Changes and Error
Corrections, or SFAS 154. The disclosure provisions of
SFAS 154 for a change in accounting estimate are not
required for revisions resulting from a change in valuation
technique or its application. Although effective for the year
ended December 31, 2008, FSP
FAS 157-3
did not have an impact on the Companys results of
operations, financial position, or cash flows.
In November 2008, the EITF issued
EITF 08-6,
Equity Method Investment Accounting Considerations, or
EITF 08-6.
EITF 08-6
addresses questions about the potential effect of FAS 141R
and FAS 160 on equity-method accounting under APB 18.
EITF 08-6
generally continues existing practices under APB 18, including
the use of a cost-accumulation approach to initial measurement
of the investment. This EITF does not require the investor to
perform a separate impairment test on the underlying assets of
an equity method investment. However, an equity-method investor
is required to recognize its proportionate share of impairment
charges recognized by the investee, adjusted for basis
differences, if any, between the investees carrying amount
for the impaired assets and the cost allocated to such assets by
the investor. The investor is also required to perform an
overall other-than-temporary impairment test of its investment
in accordance with APB 18.
EITF 08-6
is effective for fiscal years beginning on or after
December 15, 2008 and interim periods within those fiscal
years, and shall be applied prospectively. Early application is
not permitted. The Company adopted
EITF 08-6
on January 1, 2009, with no impact on the Companys
results of operations, financial position, or cash flows.
In December 2008, the FASB issued FSP
No. FAS 140-4
and FIN 46(R)-8, Disclosures by Public Entities
(Enterprises) about Transfers of Financial assets and Interests
in Variable Interest Entities, or FSP
FAS 140-4
and
152
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
FIN 46R-8.
This FSP amends FASB Statement No. 140, Accounting for
Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities, to require public entities to provide
additional disclosures about transfers of financial assets. It
also amends FIN 46R to require public enterprises,
including sponsors that have a variable interest in a VIE, to
provide additional disclosures about their involvement with such
VIEs. FSP
FAS 140-4
and
FIN 46R-8
is effective immediately. NRG does not engage in transfers of
financial assets within the scope of FAS 140, so the
amendments in this FSP related to FAS 140 will not impact
NRG. The additional disclosure requirements related to
FIN 46R have been adopted by NRG and included in the
December 31, 2008 financial statements, with no impact on
the Companys results of operations, financial position, or
cash flows.
In December 2008, the FASB also issued FSP
No. FAS 132(R)-1 Employers Disclosures about
Postretirement Benefit Plan Assets, or FSP 132R-1. This
FSP amends FASB Statement No. 132 (revised 2003),
Employers Disclosures about Pensions and Other
Postretirement Benefits, to provide guidance and additional
transparency on an employers disclosures about plan assets
of a defined benefit pension or other postretirement plan,
including the concentrations of risk in those plans. The
effective date of FSP
FAS 132R-1
is for fiscal years beginning after December 15, 2009. The
enhanced disclosure requirements are relevant to NRG but will
not be effective until the first interim period of 2010, and
will not have an impact on the Companys results of
operations, financial position, or cash flows.
|
|
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
|
|
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
|
|
Second Quarter 2008
|
153
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
As of December 31, 2008, there were no assets and
liabilities classified as discontinued operations. The following
table summarizes the major classes of assets and liabilities
classified as discontinued operations as of December 31,
2007.
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
43
|
|
Restricted cash
|
|
|
4
|
|
Receivables, net
|
|
|
4
|
|
|
|
|
|
|
Current assets discontinued operations
|
|
$
|
51
|
|
|
|
|
|
|
Property, plant and equipment, net
|
|
$
|
61
|
|
Other non-current assets
|
|
|
32
|
|
|
|
|
|
|
Non-current assets discontinued operations
|
|
$
|
93
|
|
|
|
|
|
|
Current portion of long-term debt
|
|
$
|
10
|
|
Accounts payable trade
|
|
|
4
|
|
Other current liabilities
|
|
|
23
|
|
|
|
|
|
|
Current liabilities discontinued operations
|
|
$
|
37
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
51
|
|
Minority interest
|
|
|
1
|
|
Other non-current liabilities
|
|
|
24
|
|
|
|
|
|
|
Non-current liabilities discontinued
operations
|
|
$
|
76
|
|
|
|
|
|
|
Summarized results of discontinued operations for the years
ended December 31, 2008, 2007, and 2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
20
|
|
|
$
|
50
|
|
|
$
|
227
|
|
Operating costs and other expenses
|
|
|
9
|
|
|
|
27
|
|
|
|
224
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pre-tax income from operations of discontinued components
|
|
|
11
|
|
|
|
23
|
|
|
|
3
|
|
Income tax expense
|
|
|
3
|
|
|
|
6
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations of discontinued components
|
|
|
8
|
|
|
|
17
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Disposal of discontinued components pre-tax gain
|
|
|
273
|
|
|
|
|
|
|
|
80
|
|
Income tax expense
|
|
|
109
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on disposal of discontinued components, net of income
taxes
|
|
|
164
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
$
|
172
|
|
|
$
|
17
|
|
|
$
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The pre-tax gain on disposal of the Companys discontinued
operations for the years ended December 31, 2008, 2007 and
2006 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Segment
|
|
|
|
|
|
(In millions)
|
|
|
|
|
ITISA
|
|
$
|
273
|
|
|
$
|
|
|
|
$
|
|
|
|
International
|
Resource Recovery
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
Corporate
|
Flinders
|
|
|
|
|
|
|
|
|
|
|
60
|
|
|
International
|
Audrain
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total pre-tax gain on disposal of discontinued operations
|
|
$
|
273
|
|
|
$
|
|
|
|
$
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ITISA The assets and liabilities reported in
the balance sheet as of December 31, 2007 as discontinued
operations represent those of ITISA. On April 28, 2008, NRG
completed the sale of its 100% interest in Tosli, which held all
NRGs interest in ITISA, to Brookfield Renewable Power Inc.
(previously Brookfield Power Inc.), a wholly-owned subsidiary of
Brookfield Asset Management Inc. In addition, the purchase price
adjustment contingency under the sale agreement was resolved on
August 7, 2008. In connection with the sale, NRG received
$300 million of cash proceeds from Brookfield, and removed
$163 million of assets, including $59 million of cash,
$122 million of liabilities, including $63 million of
debt, and $15 million in foreign currency translation
adjustment from its 2008 consolidated balance sheet.
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.
Acquisition
of Texas Genco LLC, or Texas Genco
On February 2, 2006, NRG acquired Texas Genco, 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 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
$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
debt.
155
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The acquisition of Texas Genco 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; and (v) cash on hand.
The acquisition of Texas Genco 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 $1,782 million
and was recorded as goodwill.
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 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.
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.
156
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 4
|
Fair
Value of Financial Instruments
|
The estimated carrying values and fair values of NRGs
recorded financial instruments related to continuing operations
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
Carrying Amount
|
|
|
Fair Value
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
Funds deposited by counterparties
|
|
|
754
|
|
|
|
|
|
|
|
754
|
|
|
|
|
|
Restricted cash
|
|
|
16
|
|
|
|
29
|
|
|
|
16
|
|
|
|
29
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
494
|
|
|
|
85
|
|
|
|
494
|
|
|
|
85
|
|
Investment in available-for-sale securities (classified within
other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
7
|
|
|
|
32
|
|
|
|
7
|
|
|
|
32
|
|
Marketable equity securities
|
|
|
2
|
|
|
|
7
|
|
|
|
2
|
|
|
|
7
|
|
Trust fund investments
|
|
|
305
|
|
|
|
390
|
|
|
|
305
|
|
|
|
390
|
|
Notes receivable
|
|
|
156
|
|
|
|
126
|
|
|
|
166
|
|
|
|
138
|
|
Derivative assets
|
|
|
5,485
|
|
|
|
1,184
|
|
|
|
5,485
|
|
|
|
1,184
|
|
Long-term debt, including current portion
|
|
|
8,026
|
|
|
|
8,180
|
|
|
|
7,496
|
|
|
|
8,164
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
760
|
|
|
|
14
|
|
|
|
760
|
|
|
|
14
|
|
Derivative liabilities
|
|
|
4,489
|
|
|
|
1,676
|
|
|
|
4,489
|
|
|
|
1,676
|
|
For cash and cash equivalents, funds deposited by
counterparties, restricted cash, and cash collateral paid and
received in support of energy risk management activities, 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 US
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 long-term
debt is based on quoted market prices for these instruments that
are publicly traded, or estimated based on the income approach
valuation technique for non-publicly traded debt using current
interest rates for similar instruments with equivalent credit
quality.
Adoption
of SFAS No. 157
The Company partially adopted SFAS 157 on January 1,
2008, delaying application for non-financial assets and
non-financial liabilities as permitted. This statement
establishes a framework for measuring fair value, and expands
disclosures about fair value measurements.
157
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
SFAS 157 establishes a fair value hierarchy that
prioritizes the inputs to valuation techniques used to measure
fair value into three levels as follows:
|
|
|
|
|
Level 1 quoted prices (unadjusted) in active
markets for identical assets or liabilities that the Company has
the ability to access as of the measurement date. NRGs
financial assets and liabilities utilizing Level 1 inputs
include active exchange-traded securities, energy derivatives,
and trust fund investments.
|
|
|
|
Level 2 inputs other than quoted prices
included within Level 1 that are directly observable for
the asset or liability or indirectly observable through
corroboration with observable market data. NRGs financial
assets and liabilities utilizing Level 2 inputs include
fixed income securities, exchange-based derivatives, and over
the counter derivatives such as swaps, options and forwards.
|
|
|
|
Level 3 unobservable inputs for the asset or
liability only used when there is little, if any, market
activity for the asset or liability at the measurement date.
NRGs financial assets and liabilities utilizing
Level 3 inputs include infrequently-traded,
non-exchange-based derivatives and commingled investment funds,
and are measured using present value pricing models.
|
In accordance with SFAS 157, the Company determines the
level in the fair value hierarchy within which each fair value
measurement in its entirety falls, based on the lowest level
input that is significant to the fair value measurement in its
entirety.
Recurring
Fair Value Measurements
The following table presents assets and liabilities measured and
recorded at fair value on the Companys consolidated
balance sheet on a recurring basis and their level within the
fair value hierarchy as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,494
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
754
|
|
|
|
|
|
|
|
|
|
|
|
754
|
|
Restricted cash
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
494
|
|
Investment in available-for-sale securities (classified within
other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
7
|
|
Marketable equity securities
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Trust fund investments
|
|
|
167
|
|
|
|
107
|
|
|
|
31
|
|
|
|
305
|
|
Derivative assets
|
|
|
2,168
|
|
|
|
3,264
|
|
|
|
53
|
|
|
|
5,485
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
5,095
|
|
|
$
|
3,371
|
|
|
$
|
91
|
|
|
$
|
8,557
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash collateral received in support of energy risk management
activities
|
|
$
|
760
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
760
|
|
Derivative liabilities
|
|
|
2,186
|
|
|
|
2,299
|
|
|
|
4
|
|
|
|
4,489
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
2,946
|
|
|
$
|
2,299
|
|
|
$
|
4
|
|
|
$
|
5,249
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table reconciles, for the period ended
December 31, 2008, the beginning and ending balances for
financial instruments that are recognized at fair value in the
consolidated financial statements at least annually using
significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using Significant
|
|
|
|
Unobservable Inputs
|
|
|
|
(Level 3)
|
|
|
|
|
|
|
Trust Fund
|
|
|
|
|
|
|
|
|
|
Debt Securities
|
|
|
Investments
|
|
|
Derivatives
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance as of January 1, 2008
|
|
$
|
32
|
|
|
$
|
37
|
|
|
$
|
27
|
|
|
$
|
96
|
|
Total gains and losses (realized/unrealized) Included in earnings
|
|
|
(23
|
)
|
|
|
|
|
|
|
5
|
|
|
|
(18
|
)
|
Included in nuclear decommissioning obligations
|
|
|
|
|
|
|
(14
|
)
|
|
|
|
|
|
|
(14
|
)
|
Included in other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
27
|
|
|
|
27
|
|
Purchases/(sales), net
|
|
|
(2
|
)
|
|
|
7
|
|
|
|
(10
|
)
|
|
|
(5
|
)
|
Transfer into Level 3
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance as of December 31, 2008
|
|
$
|
7
|
|
|
$
|
31
|
|
|
$
|
49
|
|
|
$
|
87
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The amount of the total gains or losses for the period included
in earnings attributable to the change in unrealized gains and
losses relating to assets still held as of December 31, 2008
|
|
$
|
(23
|
)
|
|
$
|
|
|
|
$
|
(50
|
)
|
|
$
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized and unrealized gains and losses included in earnings
that are related to the debt securities are recorded in other
income, while those related to energy derivatives are recorded
in operating revenues.
Non-derivative
fair value measurements
NRGs debt securities are classified as Level 3 and
consist of non-traded debt instruments that are valued based on
an auction process.
The trust fund investments are held primarily to satisfy
NRGs nuclear decommissioning obligations. These trust fund
investments hold debt and equity securities directly and equity
securities indirectly through commingled funds. The fair values
of equity securities held directly by the trust funds are based
on quoted prices in active markets and are categorized in
Level 1. In addition, US Treasury securities are
categorized as Level 1 because they trade in a highly
liquid and transparent market. The fair values of fixed income
securities, excluding US Treasury securities, are based on
evaluated prices that reflect observable market information,
such as actual trade information of similar securities, adjusted
for observable differences and are categorized in Level 2.
Commingled funds, which are analogous to mutual funds, are
maintained by investment companies and hold certain investments
in accordance with a stated set of fund objectives. The fair
value of commingled funds are based on net asset values per fund
share (the unit of account), derived from the quoted prices in
active markets of the underlying equity securities. However,
because the shares in the commingled funds are not publicly
quoted, not traded in an active market and are subject to
certain restrictions regarding their purchase and sale, the
commingled funds are categorized in Level 3. See also
Note 6, Nuclear Decommissioning Trust Fund.
159
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Derivative
fair value measurements
A small portion of NRGs contracts are exchange-traded
contracts with readily available quoted market prices. The
majority of NRGs contracts are non exchange-traded
contracts valued using prices provided by external sources,
primarily price quotations available through brokers or
over-the-counter, on-line exchanges. For the majority of our
markets the Company receives quotes from multiple sources. To
the extent that the Company receives multiple quotes, NRG prices
reflect the average of the bid-ask mid-point prices obtained
from all sources that it believes provide the most liquid market
for the commodity. If the Company only receives one quote then
the mid point of the bid-ask spread for that quote is used. The
terms for which such price information is available vary by
commodity, region and product. The remainder of the assets and
liabilities represent contracts for which external sources or
observable market quotes are not available. These contracts are
valued based on various valuation techniques including but not
limited to internal models based on a fundamental analysis of
the market and extrapolation of observable market data with
similar characteristics. Contracts valued with prices provided
by models and other valuation techniques make up 5% of the total
fair value of all derivative contracts. The fair value of each
contract is discounted using a risk free interest rate. In
addition, the Company applies a credit reserve to reflect credit
risk which is calculated based on credit default swaps. To the
extent that NRGs net exposure under a specific master
agreement is an asset the Company is using the
counterpartys default swap rate. If the exposure under a
specific master agreement is a liability the Company is using
NRGs default swap rate. The credit reserve is added to the
discounted fair value to reflect the exit price that a market
participant would be willing to receive to assume NRGs
liabilities or that a market participant would be willing to pay
for NRGs assets. As of December 31, 2008 the credit
reserve resulted in a $22 million decrease in fair value
which is composed of a $10 million loss in OCI and a
$12 million loss in derivative revenue. The fair values in
each category reflect the level of forward prices and volatility
factors as of December 31, 2008 and may change as a result
of changes in these factors. Management uses its best estimates
to determine the fair value of commodity and derivative
contracts NRG holds and sells. These estimates consider various
factors including closing exchange and over-the-counter price
quotations, time value, volatility factors and credit exposure.
It is possible, however, that future market prices could vary
from those used in recording assets and liabilities from energy
marketing and trading activities and such variations could be
material.
Under the guidance of FSP
FIN 39-1,
entities may choose to offset cash collateral paid or received
against the fair value of derivative positions executed with the
same counterparties under the same master netting agreements.
The Company has chosen not to offset positions as defined in
this FSP. As of December 31, 2008, the Company
recorded $494 million of cash collateral paid and
$760 million of cash collateral received on its balance
sheet.
|
|
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, until the hedged
transactions occur and are recognized in earnings. 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 value accounting treatment. SFAS 133
applies to NRGs energy related commodity contracts,
interest rate swaps, and foreign exchange contracts.
160
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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, 2008, 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, 2008, 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, 2008, 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 also Note 21, Commitments and
Contingencies, for further discussion.
|
161
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Also, as of December 31, 2008, 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 2011.
|
|
|
|
Natural gas transportation contracts and storage agreements
through 2018.
|
|
|
|
Coal transportation contracts through 2016.
|
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, 2008, all of NRGs interest rate
swap arrangements had been designated as either cash flow or
fair value hedges. As of December 31, 2008, 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.
162
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, 2008, 2007 and 2006, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy-Related
|
|
|
|
|
|
|
|
|
|
Commodities
|
|
|
Interest Rate
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
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
|
)
|
Realized from OCI during period due to unwinding of
previously deferred amounts
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Changes in fair value of hedge contracts
gains/(losses)
|
|
|
640
|
|
|
|
(59
|
)
|
|
|
581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2008
|
|
$
|
406
|
|
|
$
|
(91
|
)
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/(losses) expected to unwind from OCI during next
12 months, net of $176 tax
|
|
$
|
278
|
|
|
$
|
(1
|
)
|
|
$
|
277
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2008, the net balance in OCI relating to
SFAS 133 was an unrecognized gain of approximately
$315 million, which is net of $194 million in income
taxes. NRG expects $277 million of net deferred gains on
derivative instruments accumulated in OCI to be recognized in
earnings during the next twelve months.
As of July 31, 2008, our regression analysis for natural
gas prices to ERCOT power prices did not meet the required
threshold for cash flow hedge accounting for calendar years 2012
and 2013. As a result, we de-designated our 2012 and 2013 ERCOT
cash flow hedges as of this day. We will continue to monitor the
correlations in this market, and if the regression analysis
meets the required thresholds in the future, we may elect to
re-designate these transactions as cash flow hedges.
163
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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 economic
hedges that did not qualify for cash flow hedge accounting,
ineffectiveness on cash flow hedges, and trading activity on
NRGs statement of operations. These amounts are included
within operating revenues.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Unrealized mark-to-market results
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized (gains)/losses on
settled positions related to economic hedges
|
|
$
|
(38
|
)
|
|
$
|
(128
|
)
|
|
$
|
116
|
|
Reversal of previously recognized unrealized
gains on settled positions related to trading activity
|
|
|
(32
|
)
|
|
|
(32
|
)
|
|
|
(26
|
)
|
Net unrealized gains on open positions
related to economic hedges
|
|
|
524
|
|
|
|
20
|
|
|
|
144
|
|
(Loss)/gain on ineffectiveness associated
with open positions treated as cash flow hedges
|
|
|
(24
|
)
|
|
|
14
|
|
|
|
28
|
|
Net unrealized gains on open positions
related to trading activity
|
|
|
95
|
|
|
|
49
|
|
|
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total unrealized mark-to-market results
|
|
$
|
525
|
|
|
$
|
(77
|
)
|
|
$
|
295
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the year ended December 31, 2008, the unrealized gain
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives of
$525 million is comprised of $500 million of fair
value increases in forward sales of electricity and fuel,
$70 million loss from the reversal of mark-to-market gains,
which ultimately settled as financial revenues, and
$95 million of gains associated with our trading activity.
The $500 million of fair value increases in forward sales
of electricity and fuel includes a loss of approximately
$24 million due to the ineffectiveness associated with
financial forward contracted electric and gas sales.
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, 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.
164
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Discontinued Hedge Accounting During 2008, a
relatively mild summer season in the Northeast resulted in
falling power prices and expected lower power generation for the
remainder of 2008 and calendar year 2009. As such, NRG
discontinued cash flow hedge accounting for certain contracts
related to commodity price risk previously accounted for as cash
flow hedges for 2008 and 2009. These contracts were originally
entered into as hedges of forecasted sales by baseload plants.
As a result, $31 million of gain previously deferred in OCI
was recognized in earnings for the year ended December 31,
2008.
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
|
)
|
|
|
|
|
|
Concentration
of 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 credit risk through credit policies that include:
(i) an established credit approval process, (ii) a
daily monitoring of counterparties 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 seeks to
mitigate counterparty risk with a diversified portfolio of
counterparties, including ten participants under its first and
second lien structure. The Company also has credit protection
within various agreements to call on additional collateral
support if and when necessary. Cash margin is collected and held
at NRG to cover the credit risk of the counterparty until
positions settle.
As of December 31, 2008, total credit exposure to
substantially all counterparties was $2.0 billion and NRG
held collateral (cash and letters of credit) against those
positions of $788 million resulting in a net exposure of
$1.2 billion. Total credit exposure is discounted at the
risk free rate.
165
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table represents the credit quality and the net
counterparty credit exposure by industry sector. Net
counterparty credit risk is defined as the aggregate net asset
position for NRG with counterparties where netting is permitted
under the enabling agreement and includes all cash flow, mark to
market and NPNS and non-derivative transactions. The exposure is
shown net of collateral held, and includes amounts net of
receivables or payables.
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
|
Coal producers
|
|
|
16
|
%
|
Financial institutions
|
|
|
58
|
|
Utilities, energy, merchants and marketers
|
|
|
21
|
|
ISOs
|
|
|
5
|
|
|
|
|
|
|
Total as of December 31, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
|
Investment grade
|
|
|
81
|
%
|
Non-Investment grade
|
|
|
8
|
|
Non-rated
|
|
|
11
|
|
|
|
|
|
|
Total as of December 31, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
(a)
|
|
Credit exposure excludes California
tolling, uranium, coal transportation/railcar leases, New
England Reliability Must-Run, cooperative load contracts and
Texas Westmoreland coal contracts.
|
NRG has credit risk exposure to certain counterparties
representing more than 10% of total net exposure and the
aggregate of such counterparties was $241 million. No
counterparty represents more than 20% of total net credit
exposure. Approximately 80% of NRGs positions relating to
credit risk roll-off by the end of 2011. Changes in hedge
positions and market prices will affect credit exposure and
counterparty concentration. 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.
166
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 6
|
Nuclear
Decommissioning Trust Fund
|
NRGs nuclear decommissioning trust fund assets which are
for the decommissioning of 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 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. 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.
The following table summarizes the fair values of the securities
held in the trust funds as of December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
4
|
|
US government and federal agency obligations
|
|
|
21
|
|
|
|
21
|
|
Federal agency mortgage-backed securities
|
|
|
49
|
|
|
|
59
|
|
Commercial mortgage-backed securities
|
|
|
16
|
|
|
|
22
|
|
Corporate debt securities
|
|
|
37
|
|
|
|
44
|
|
Marketable equity securities
|
|
|
178
|
|
|
|
234
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
303
|
|
|
$
|
384
|
|
|
|
|
|
|
|
|
|
|
Inventory consists of:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Fuel oil
|
|
$
|
128
|
|
|
$
|
140
|
|
Coal/Lignite
|
|
|
189
|
|
|
|
174
|
|
Natural gas
|
|
|
11
|
|
|
|
16
|
|
Spare parts
|
|
|
127
|
|
|
|
121
|
|
|
|
|
|
|
|
|
|
|
Total Inventory
|
|
$
|
455
|
|
|
$
|
451
|
|
|
|
|
|
|
|
|
|
|
167
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 8
|
Capital
Leases 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 leases as of
December 31, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Capital Leases Receivable non-affiliates
|
|
|
|
|
|
|
|
|
VEAG Vereinigte Energiewerke AG, due August 31, 2021,
11.00%(a)
|
|
$
|
338
|
|
|
$
|
395
|
|
Other
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Leases non-affiliates
|
|
|
347
|
|
|
|
395
|
|
|
|
|
|
|
|
|
|
|
Notes Receivable affiliates
|
|
|
|
|
|
|
|
|
GenConn Energy LLC, due April 30, 2009, LIBOR +
3.75%(b)
current
|
|
|
36
|
|
|
|
|
|
Kraftwerke Schkopau GBR, indefinite maturity date,
5.89%-7.00%(c)
non-current
|
|
|
120
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
Notes Receivable affiliates
|
|
|
156
|
|
|
|
126
|
|
|
|
|
|
|
|
|
|
|
Subtotal Capital leases and notes receivable
|
|
|
503
|
|
|
|
521
|
|
|
|
|
|
|
|
|
|
|
Less current maturities:
|
|
|
|
|
|
|
|
|
Capital leases
|
|
|
32
|
|
|
|
30
|
|
Notes receivable GenConn
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal current maturities
|
|
|
68
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
Total Capital leases and notes receivable
noncurrent
|
|
$
|
435
|
|
|
$
|
491
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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)
|
|
NRG has entered into a short-term
$45 million note receivable facility with GenConn Energy
LLC to fund project liquidity needs.
|
|
(c)
|
|
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, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
Depreciable
|
|
|
|
2008
|
|
|
2007
|
|
|
Lives
|
|
|
|
(In millions)
|
|
|
|
|
|
Facilities and equipment
|
|
$
|
12,193
|
|
|
$
|
11,829
|
|
|
|
1-40 Years
|
|
Land and improvements
|
|
|
593
|
|
|
|
584
|
|
|
|
|
|
Nuclear fuel
|
|
|
225
|
|
|
|
181
|
|
|
|
5 Years
|
|
Office furnishings and equipment
|
|
|
73
|
|
|
|
84
|
|
|
|
2-10 Years
|
|
Construction in progress
|
|
|
804
|
|
|
|
337
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
13,888
|
|
|
|
13,015
|
|
|
|
|
|
Accumulated depreciation
|
|
|
(2,343
|
)
|
|
|
(1,695
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
11,545
|
|
|
$
|
11,320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 10
|
Goodwill
and Other Intangibles
|
Goodwill NRGs goodwill arose in
connection with the acquisitions of Texas Genco and Padoma. As
of December 31, 2008 and 2007, goodwill was approximately
$1.7 billion and $1.8 billion, respectively. In
accordance with SFAS 141, goodwill associated with the
Texas Genco acquisition decreased by $68 million during
2008 due to an adjustment to deferred tax liabilities originally
established under the 2006 purchase price allocation. 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 the fourth
quarter, or more often if events or circumstances, such as
adverse changes in the business climate, indicate there may be
impairment. As of December 31, 2008, there was no
impairment to goodwill. As of December 31, 2008, NRG had
approximately $786 million of goodwill that is deductible
for US income tax purposes in future periods.
Intangible Assets NRG acquired
intangible assets as part of the Companys acquisition of
Texas Genco 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 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Contracts
|
|
|
|
|
|
|
|
December 31, 2008
|
|
Allowances
|
|
|
Power
|
|
|
Fuel
|
|
|
Water
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2008
|
|
$
|
916
|
|
|
$
|
92
|
|
|
$
|
171
|
|
|
$
|
64
|
|
|
$
|
2
|
|
|
$
|
1,245
|
|
Additions
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
9
|
|
Transfer to held for sale
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Fully amortized intangible assets
|
|
|
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
(64
|
)
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross amount
|
|
|
916
|
|
|
|
58
|
|
|
|
171
|
|
|
|
|
|
|
|
5
|
|
|
|
1,150
|
|
Less accumulated amortization
|
|
|
(155
|
)
|
|
|
(58
|
)
|
|
|
(122
|
)
|
|
|
|
|
|
|
|
|
|
|
(335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
761
|
|
|
$
|
|
|
|
$
|
49
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
169
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Contracts
|
|
|
|
|
|
|
|
December 31, 2007
|
|
Allowances
|
|
|
Power
|
|
|
Fuel
|
|
|
Water
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2007
|
|
$
|
913
|
|
|
$
|
92
|
|
|
$
|
171
|
|
|
$
|
64
|
|
|
$
|
|
|
|
$
|
1,240
|
|
Additions
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents NRGs amortization of
intangible assets for the years ended December 31, 2008,
2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Emission allowances
|
|
$
|
41
|
|
|
$
|
40
|
|
|
$
|
44
|
|
Fuel contracts
|
|
|
20
|
|
|
|
37
|
|
|
|
65
|
|
Water contracts
|
|
|
|
|
|
|
36
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amortization in cost of operations
|
|
$
|
61
|
|
|
$
|
113
|
|
|
$
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power contract amortization recorded as a reduction to operating
revenues
|
|
$
|
|
|
|
$
|
|
|
|
$
|
43
|
|
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)
|
|
|
2009
|
|
$
|
40
|
|
|
$
|
26
|
|
|
$
|
66
|
|
2010
|
|
|
52
|
|
|
|
6
|
|
|
|
58
|
|
2011
|
|
|
52
|
|
|
|
2
|
|
|
|
54
|
|
2012
|
|
|
45
|
|
|
|
2
|
|
|
|
47
|
|
2013
|
|
|
20
|
|
|
|
2
|
|
|
|
22
|
|
The weighted average remaining amortization period is
3.4 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, 2008, the
value of emission allowances held-for-sale is $4 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, 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.
170
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The following table summarizes the estimated amortization
related to NRGs out-of-market contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December
31,
|
|
Coal
|
|
|
Gas Swaps
|
|
|
Power Contracts
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2009
|
|
$
|
19
|
|
|
$
|
56
|
|
|
$
|
80
|
|
|
$
|
155
|
|
2010
|
|
|
6
|
|
|
|
51
|
|
|
|
28
|
|
|
|
85
|
|
2011
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
21
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
22
|
|
2013
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
19
|
|
|
|
Note 11
|
Debt and
Capital Leases
|
Long-term debt and capital leases consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
Interest
|
|
|
|
2008
|
|
|
2007
|
|
|
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)
|
|
|
1,217
|
|
|
|
1,199
|
|
|
|
7.25
|
|
Term Loan Facility, due 2013
|
|
|
2,642
|
|
|
|
2,816
|
|
|
|
L+1.5 for 2008/
L+1.75 for 2007
|
(f)
|
NRG Non-Recourse Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
CSF, notes and preferred interests, due 2009 and
2010(b)
|
|
|
332
|
|
|
|
333
|
|
|
|
5.45-13.23
|
|
NRG Peaker Finance Co. LLC, bonds, due June
2019(c)
|
|
|
229
|
|
|
|
235
|
|
|
|
L+1.07
|
(f)
|
NRG Energy Center Minneapolis LLC, senior secured notes,
due 2013 and
2017(d)
|
|
|
86
|
|
|
|
97
|
|
|
|
7.12-7.31
|
|
Other
|
|
|
20
|
|
|
|
|
|
|
|
L + 0.45
|
(f)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal long term debt
|
|
|
8,026
|
|
|
|
8,180
|
|
|
|
|
|
Capital leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau capital lease, due 2021
|
|
|
142
|
|
|
|
181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
8,168
|
|
|
|
8,361
|
|
|
|
|
|
Less current
maturities(e)
|
|
|
464
|
|
|
|
466
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,704
|
|
|
$
|
7,895
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
Includes fair value adjustment as of December 31, 2008 and
2007 of $17 million and $(1) million, respectively,
reflecting an adjustment 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 acquisition.
|
|
(b)
|
Includes discount of $(1) million as of December 31,
2008.
|
|
(c)
|
Includes discount of $(37) million and $(43) million
as of December 31, 2008 and 2007, respectively.
|
|
(d)
|
Includes premium of $2 million and $3 million as of
December 31, 2008 and 2007, respectively.
|
|
(e)
|
Includes discount of $6 million and $7 million on the
NRG Peaker Finance debt as of December 31, 2008 and 2007,
respectively, and a premium of $1 million on NRG Energy
Center Minneapolis debt as of December 31, 2008 and 2007.
|
|
|
(f) |
L+ equals LIBOR plus x%
|
171
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
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. In addition, the Company entered into a
fixed to floating interest rate swap in 2004 with a notional
amount as of December 31, 2008 of $400 million and a
maturity date of December 15, 2013.
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, 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 February 1, 2010, discounted at a
Treasury rate plus 0.50%. On or after February 1, 2010, 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
applicable redemption date:
|
|
|
|
|
|
|
Redemption
|
|
Redemption Period
|
|
Percentage
|
|
|
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
|
%
|
172
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Prior to February 1, 2011, NRG may redeem all or a portion
of the 2016 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 103.688% of the
note, plus interest payments due on the note from the date of
redemption through February 1, 2011, discounted at a
Treasury rate plus 0.50%. On or after February 1, 2011, 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
applicable redemption date:
|
|
|
|
|
|
|
Redemption
|
|
Redemption Period
|
|
Percentage
|
|
|
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.
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 payments due on the note
from the date of redemption through January 15, 2012,
discounted at a Treasury rate plus 0.50%. 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:
|
|
|
|
|
|
|
Redemption
|
|
Redemption Period
|
|
Percentage
|
|
|
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
|
%
|
Senior
Credit Facility
As of December 31, 2008, NRG has a Senior Credit Facility
which is 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 $1.3 billion senior first priority
secured synthetic letter of credit facility, or the Synthetic
Letter of Credit Facility. The Senior Credit Facility is the
result of a refinancing by the Company which occurred on
June 8, 2007, and for which a charge of $35 million
was recorded to the Companys results of operations for the
year ended December 31, 2007, primarily related to the
write-off of previously deferred financing costs. Among other
things, this refinancing resulted in a 0.25% reduction on the
spread that the Company pays on its Term Loan Facility and
Synthetic Letter of Credit Facility. The pricing on the
Companys Term Loan Facility and Synthetic Letter of Credit
Facility is also subject to further reductions upon the
achievement of certain financial ratios. On December 31,
2007, the Company used cash on hand to prepay, without penalty,
$300 million of its Term Loan Facility under the Senior
Credit Facility. With this prepayment, the Company met a
financial ratio by the end of 2007 that resulted in a further
0.25% reduction in the interest rate on both its Term Loan
Facility and Synthetic Letter of Credit Facility. The prepayment
was credited against the Companys mandatory annual offer
required under the Senior Credit Facility, as hereinafter
discussed.
As of December 31, 2008, NRG had issued $440 million
of letters of credit under the Synthetic Letter of Credit
Facility, leaving $860 million available for future
issuances. There were no letters of credit issued under the
173
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Companys Revolving Credit Facility as of December 31,
2008, leaving $1.0 billion available for borrowings, of
which approximately $900 million could be used to issue
additional letters of credit.
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. NRG has the option to prepay the
Senior Credit Facility in whole or in part at any time.
Beginning in 2008, NRG must annually offer a portion of its
excess cash flow (as defined in the Senior Credit Facility) to
its first lien lenders under the Term Loan Facility. The
percentage of the 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 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 2009 mandatory offer related to 2008, and, as
such, the Company has reclassified approximately
$197 million of Term Loan Facility maturity from a
non-current to a current liability as of December 31, 2008.
The 2008 mandatory offer related to 2007 was $446 million,
against which the Company made a prepayment of $300 million
in December 2007. Of the remaining $146 million, the
lenders accepted a repayment of $143 million in March 2008.
The amount retained by the Company was used for investments,
capital expenditures and other items as permitted by the Senior
Credit Facility. As of December 31, 2007, the Company
reclassified approximately $146 million of the Term Loan
Facility maturity from a non-current to a current liability.
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.
174
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, 2008 are as follows:
|
|
|
|
|
Maturity
|
|
Notional Value
|
|
|
March 31, 2009
|
|
$
|
150 million
|
|
March 31, 2010
|
|
$
|
190 million
|
|
March 31, 2011
|
|
$
|
1.55 billion
|
|
NRG
Non-Recourse Debt
Debt
Related to Capital Allocation Program
During the third quarter 2006, the Company formed CSF I and CSF
II, two wholly-owned unrestricted subsidiaries 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 CS.
Both the notes and the preferred interests are non-recourse debt
to NRG or any of its restricted subsidiaries, with the debt
collateralized by the NRG common stock held by CSF I and CSF II.
In addition, the assets of CSF I and CSF II are not available to
the creditors of NRG or the Companys other subsidiaries.
At December 31, 2008, CSF I and CSF II held 12,441,973 and
9,528,930 shares of NRG common stock, respectively,
reflected within treasury stock on the Companys
consolidated balance sheet.
As of December 31, 2007, the notes and preferred interests
of CSF I and II contained a feature considered an embedded
derivative, which requires NRG to pay to CS at maturity, either
in cash or stock at NRGs option, the excess of NRGs
then current stock price over a Threshold Price. This Threshold
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. As a result of the early settlement
described below in August 2008 by the CSF I extension, as of
December 31, 2008 only the notes and preferred interests of
CSF II contain the embedded derivative feature. This CSF II
embedded derivative has a Threshold Price of $40.80 per share
and the maximum number of shares collateralizing the embedded
derivatives is 7,623,211 shares. As of December 31,
2008, based on the Companys stock price, the CSF II
embedded derivative was out-of-the money and had no redemption
value.
CSF I Extension In March 2008, the Company
executed an arrangement with CS to extend the notes and
preferred interest maturities of CSF I from October 2008 to June
2010. In addition, the settlement date of the embedded
derivative, or CSF I CAGR, was extended 30 days to early
December 2008. As part of this extension arrangement, the
Company contributed 795,503 treasury shares to CSF I as
additional collateral to maintain a blended interest rate in the
CSF I facility of approximately 7.5%. Accordingly, the amount
due at maturity in June 2010, including accrued interest, for
the CSF I notes and preferred interests will be
$248 million. In August 2008, the Company amended the CSF I
notes and preferred interests to early settle the CSF I CAGR.
Accordingly, NRG made a cash payment of $45 million to CS
for the benefit of CSF I, which was recorded to interest
expense in the Companys Consolidated Statement of
Operations.
Notes As of December 31, 2008 and 2007,
CSF I and II had a total of $249 million in notes in
connection with Phase I of the Capital Allocation Program that
mature in two tranches: $112 million for CSF II in October
2009, plus accrued interest at an annual rate of 6.11%, and the
balance of $137 million for CSF I in June 2010, plus
accrued interest at an annual rate of 5.45%.
Preferred Interests As of December 31,
2008 and 2007, total preferred interests issued and outstanding
by CSF I and II were approximately $84 million to CS.
These preferred interests are classified as a liability per
SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity,
because they embody a fixed unconditional obligation that
these two unrestricted subsidiaries must settle. The
175
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
preferred interests also mature in two tranches:
$31 million for CSF II in October 2009, plus accrued
interest at an annual rate of 13.23%, and the balance of
$53 million for CSF I in June 2010, plus accrued
interest at an annual rate of 12.65%.
Project
Financings
The following are descriptions of certain indebtedness of
NRGs project subsidiaries that remain outstanding as of
December 31, 2008. The indebtedness described below is
non-recourse to NRG, unless otherwise noted.
Other
In 2008, NINA and NRG Repowering Holdings LLC, or NRG
Repowering, each obtained a $20 million revolving credit
facility to provide working capital which permits NINA and NRG
Repowering to make cash draws or issue letters of credit. The
facilities mature on April 21, 2011 for NINA and
August 12, 2011 for NRG Repowering. The facilities provide
for customary events of default, which include, among others:
nonpayment of principal or interest; breach of other agreements
in the facility; the rendering of judgments to pay certain
amounts of money against NINA or NRG Repowering and their
subsidiaries; and certain events of bankruptcy or insolvency.
Borrowings under the facilities accrue interest at LIBOR or a
base rate, plus a spread and are secured by substantially all of
the assets of the respective borrower. As of December 31,
2008, NINA and NRG Repowering each had borrowed approximately
$10 million.
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, 2008, approximately $266 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 $31 million remained outstanding as of
December 31, 2008. In July 2002, NRG Thermal Minneapolis
issued an additional $55 million of 7.25% Series A
notes due August 2017, of which approximately $39 million
remained outstanding as of December 31, 2008, and
$20 million of 7.12% Series B notes due August 2017,
of which approximately $14 million remained outstanding as
of December 31, 2008. 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.
176
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
Capital
Leases
Saale
Energie GmbH
Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has
a 41.9% participation in 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 US GAAP. Calls for
funds are made to the partners based on their participation
interest as cash is needed. As of December 31, 2008, the
capital lease obligation at SEG was approximately
$142 million.
The KSGbR issued debt to fund Schkopau pursuant to multiple
facilities totaling approximately 785 million. As of
December 31, 2008, approximately 185 million
(approximately $258 million) remained outstanding at
Schkopau. Interests on the individual loans accrue at fixed
rates averaging 5.30% per annum, with maturities occurring
between 2009 and 2015. SEG remains liable to the lenders as a
partner in KSGbR, but there is no recourse to NRG.
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, 2008 are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2009
|
|
$
|
464
|
|
2010
|
|
|
258
|
|
2011
|
|
|
85
|
|
2012
|
|
|
67
|
|
2013
|
|
|
2,352
|
|
Thereafter
|
|
|
4,942
|
|
|
|
|
|
|
Total
|
|
$
|
8,168
|
|
|
|
|
|
|
NRGs future minimum lease payments for capital leases
included above as of December 31, 2008 are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2009
|
|
$
|
87
|
|
2010
|
|
|
23
|
|
2011
|
|
|
14
|
|
2012
|
|
|
13
|
|
2013
|
|
|
13
|
|
Thereafter
|
|
|
172
|
|
|
|
|
|
|
Total minimum obligations
|
|
|
322
|
|
Interest
|
|
|
180
|
|
|
|
|
|
|
Present value of minimum obligations
|
|
|
142
|
|
Current portion
|
|
|
72
|
|
|
|
|
|
|
Long-term obligations
|
|
$
|
70
|
|
|
|
|
|
|
177
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 12
|
Benefit
Plans and Other Postretirement Benefits
|
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 by
eligible Texas based employees. NRG expects to contribute
approximately $60 million to the Companys three
pension plans in 2009, $29 million of which related to the
Companys 2008 benefit obligation as a result of the weak
market performance of plan assets 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 were 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
Pension Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Service cost benefits earned
|
|
$
|
14
|
|
|
$
|
15
|
|
|
$
|
17
|
|
Interest cost on benefit obligation
|
|
|
18
|
|
|
|
17
|
|
|
|
15
|
|
Expected return on plan assets
|
|
|
(14
|
)
|
|
|
(11
|
)
|
|
|
(7
|
)
|
Amortization of unrecognized net gain
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
17
|
|
|
$
|
21
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
178
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
Other Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Service cost benefits earned
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
3
|
|
Interest cost on benefit obligation
|
|
|
6
|
|
|
|
5
|
|
|
|
4
|
|
Amortization of unrecognized prior service cost
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
9
|
|
|
$
|
7
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A comparison of the pension benefit obligation, other post
retirement benefit obligations, and related plan assets as of
December 31, 2008 and 2007 for NRGs plans on a
combined basis is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Benefit obligation at January 1
|
|
$
|
290
|
|
|
$
|
294
|
|
|
$
|
83
|
|
|
$
|
80
|
|
Service cost
|
|
|
14
|
|
|
|
15
|
|
|
|
2
|
|
|
|
2
|
|
Interest cost
|
|
|
18
|
|
|
|
17
|
|
|
|
6
|
|
|
|
5
|
|
Plan amendments
|
|
|
|
|
|
|
(4
|
)
|
|
|
5
|
|
|
|
|
|
Actuarial gain
|
|
|
(19
|
)
|
|
|
(13
|
)
|
|
|
(4
|
)
|
|
|
(2
|
)
|
Benefit payments
|
|
|
(12
|
)
|
|
|
(19
|
)
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31
|
|
|
291
|
|
|
|
290
|
|
|
|
91
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
|
168
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
(60
|
)
|
|
|
7
|
|
|
|
|
|
|
|
|
|
Employer contributions
|
|
|
99
|
|
|
|
58
|
|
|
|
1
|
|
|
|
1
|
|
Benefit payments
|
|
|
(12
|
)
|
|
|
(20
|
)
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
|
195
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at December 31 excess of obligation
over assets
|
|
$
|
(96
|
)
|
|
$
|
(122
|
)
|
|
$
|
(91
|
)
|
|
$
|
(83
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in NRGs balance sheets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
Other Postretirement
|
|
|
Pension Benefits
|
|
Benefits
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(In millions)
|
|
Current liabilities
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
|
|
Non-current liabilities
|
|
|
96
|
|
|
|
122
|
|
|
|
89
|
|
|
|
83
|
|
179
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
|
(In millions)
|
|
Unrecognized (gain)/loss
|
|
$
|
21
|
|
|
$
|
(36
|
)
|
|
$
|
(6
|
)
|
|
$
|
1
|
|
Prior service (credit)/cost
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
5
|
|
|
|
|
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Net loss/(gain)
|
|
$
|
55
|
|
|
$
|
(8
|
)
|
|
$
|
(4
|
)
|
|
$
|
(2
|
)
|
Amortization of net actuarial loss
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service (credit)/cost
|
|
|
|
|
|
|
(4
|
)
|
|
|
5
|
|
|
|
|
|
Amortization for prior service cost
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in other comprehensive loss/(income)
|
|
$
|
56
|
|
|
$
|
(12
|
)
|
|
$
|
|
|
|
$
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in net periodic pension cost and other
comprehensive income
|
|
$
|
73
|
|
|
$
|
9
|
|
|
$
|
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 minimal.
The following table presents the balances of significant
components of NRGs domestic pension plan:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Projected benefit obligation
|
|
$
|
291
|
|
|
$
|
290
|
|
Accumulated benefit obligation
|
|
|
251
|
|
|
|
236
|
|
Fair value of plan assets
|
|
|
195
|
|
|
|
168
|
|
The following table presents the significant assumptions used to
calculate NRGs benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
Weighted-Average
|
|
Pension Benefits
|
|
|
Other Postretirement
Benefits
|
|
Assumptions
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Discount rate
|
|
|
6.88%
|
|
|
|
6.56%
|
|
|
|
6.88%
|
|
|
|
6.56%
|
|
Rate of compensation increase
|
|
|
4.00-4.50%
|
|
|
|
4.00-4.50%
|
|
|
|
N/A
|
|
|
|
N/A
|
|
Health care trend rate
|
|
|
|
|
|
|
|
|
|
|
9.5% grading
to 5.5% in 2016
|
|
|
|
9.5% grading
to 5.5% in 2016
|
|
180
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
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Discount rate
|
|
|
6.56
|
%
|
|
|
5.92
|
%
|
|
|
5.50
|
%
|
|
|
6.56%
|
|
|
|
5.92%
|
|
|
|
5.50%
|
|
Expected return on plan assets
|
|
|
7.50
|
%
|
|
|
8.00
|
%
|
|
|
8.00
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
Rate of compensation increase
|
|
|
4.00-4.50
|
%
|
|
|
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
|
|
|
|
11.5% grading
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, 2008 and 2007
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
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 75%
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 US and non-US equities, as
well as among growth, value, small and large capitalization
stocks.
NRGs pension plan assets weighted average allocation as of
December 31, 2008 and 2007 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
US Equity
|
|
|
50-55
|
%
|
|
|
50-55
|
%
|
International Equity
|
|
|
15
|
%
|
|
|
15
|
%
|
US Fixed Income
|
|
|
30-35
|
%
|
|
|
30-35
|
%
|
181
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)
|
|
|
2009
|
|
$
|
13
|
|
|
$
|
3
|
|
|
$
|
|
|
2010
|
|
|
15
|
|
|
|
3
|
|
|
|
|
|
2011
|
|
|
16
|
|
|
|
4
|
|
|
|
|
|
2012
|
|
|
18
|
|
|
|
4
|
|
|
|
|
|
2013
|
|
|
20
|
|
|
|
4
|
|
|
|
|
|
2014-2018
|
|
|
133
|
|
|
|
30
|
|
|
|
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
|
)
|
Effect on postretirement benefit obligation
|
|
|
7
|
|
|
|
(6
|
)
|
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, 2008 and 2007, NRG reimbursed STPNOC
approximately $6 million and $12 million,
respectively, towards its defined benefit plans. In 2009, NRG
expects to reimburse STPNOC approximately $5 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Funded status STPNOC benefit plans
|
|
$
|
(48
|
)
|
|
$
|
(20
|
)
|
|
$
|
(27
|
)
|
|
$
|
(22
|
)
|
Net periodic benefit costs
|
|
|
5
|
|
|
|
4
|
|
|
|
3
|
|
|
|
3
|
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income
|
|
|
27
|
|
|
|
4
|
|
|
|
6
|
|
|
|
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
$17 million, $16 million, and $15 million for the
years ended December 31, 2008, 2007 and 2006, respectively.
182
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 13
|
Capital
Structure
|
The following table reflects the changes in NRGs common
stock issued and outstanding for the year ended
December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized
|
|
|
Issued
|
|
|
Treasury
|
|
|
Outstanding
|
|
|
Balance as of December 31, 2006
|
|
|
500,000,000
|
|
|
|
274,248,264
|
|
|
|
(29,601,162
|
)
|
|
|
244,647,102
|
|
Retirement of shares
|
|
|
|
|
|
|
(14,094,962
|
)
|
|
|
14,094,962
|
|
|
|
|
|
Additional Share Repurchases
|
|
|
|
|
|
|
|
|
|
|
(2,037,700
|
)
|
|
|
(2,037,700
|
)
|
Capital Allocation Plan Phase II
|
|
|
|
|
|
|
|
|
|
|
(7,006,700
|
)
|
|
|
(7,006,700
|
)
|
Shares issued from LTIP
|
|
|
|
|
|
|
1,132,227
|
|
|
|
|
|
|
|
1,132,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
|
500,000,000
|
|
|
|
261,285,529
|
|
|
|
(24,550,600
|
)
|
|
|
236,734,929
|
|
Capital Allocation Plan Phase II
|
|
|
|
|
|
|
|
|
|
|
(4,691,883
|
)
|
|
|
(4,691,883
|
)
|
Shares issued from LTIP
|
|
|
|
|
|
|
1,004,176
|
|
|
|
|
|
|
|
1,004,176
|
|
5.75% Preferred Stock conversion
|
|
|
|
|
|
|
1,309,495
|
|
|
|
|
|
|
|
1,309,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
|
500,000,000
|
|
|
|
263,599,200
|
|
|
|
(29,242,483
|
)
|
|
|
234,356,717
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
distributed by the Companys transfer agent on May 31,
2007. All share amounts for all periods presented have been
adjusted to reflect the stock split.
Common
Stock
NRGs authorized common stock consists of 500 million
shares of NRG stock. Common stock issued as of December 31,
2008 and 2007 was 263,599,200 and 261,285,529 shares,
respectively, at a par value of $0.01 per share. Common stock
issued and outstanding as of December 31, 2008 and 2007
were 234,356,717 and 236,734,929, respectively.
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, 2008:
|
|
|
|
|
|
|
Common Stock
|
|
Equity Instrument
|
|
Reserve Balance
|
|
|
4% Convertible perpetual preferred
|
|
|
26,151,972
|
|
3.625% Convertible perpetual preferred
|
|
|
16,000,000
|
|
5.75% Mandatory convertible preferred
|
|
|
19,210,505
|
|
Long term incentive plan
|
|
|
13,561,565
|
|
|
|
|
|
|
Total
|
|
|
74,924,042
|
|
|
|
|
|
|
Treasury
Stock
As of December 31, 2008 and 2007, NRG has treasury shares
of 29,242,483 and 24,550,600, respectively and are held at cost
of approximately $823 million and $638 million,
respectively.
In December 2007, the Company initiated its 2008 Capital
Allocation Plan, with the repurchase of 2,037,700 shares of
NRG common stock during that month for approximately
$85 million. In February 2008,
183
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
the Companys Board of Directors authorized an additional
$200 million in common share repurchases that raised the
total 2008 Capital Allocation Plan to approximately
$300 million. In the first quarter 2008, the Company
repurchased 1,281,600 shares of NRG common stock for
approximately $55 million. In the third quarter 2008, the
Company repurchased an additional 3,410,283 of NRG common stock
for approximately $130 million. As of December 31,
2008, NRG had repurchased a total of 6,729,583 shares of
NRG common stock at a cost of approximately $270 million as
part of its 2008 Capital Allocation Plan.
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.
Employee
Stock Purchase Plan
In May 2008, NRG shareholders approved the adoption of the NRG
Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to
which eligible employees may elect to withhold up to 10% of
their eligible compensation to purchase shares of NRG common
stock at 85% of its fair market value on the exercise date. An
exercise date occurs each June 30 and December 31. The
initial six month employee withholding period began July 1,
2008 and ended December 31, 2008. As of December 31,
2008, there were 500,000 shares of treasury stock reserved
for issuance under the ESPP. In January 2009, 41,706 shares
of common stock were issued to employee account from treasury
stock.
Preferred
Stock
As of December 31, 2008 and 2007, the Company had
10,000,000 shares of preferred stock authorized. As of
December 31, 2008, 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. Each share
of the 5.75% Preferred Stock will automatically convert into a
number of shares of 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, illustrated in the
following table:
|
|
|
|
|
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
|
|
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
184
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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.
The holders of the 5.75% Preferred Stock may elect to convert at
any time prior to the Conversion Date at the minimum conversion
rate of 8.2712. As of December 31, 2008,
158,320 shares of 5.75% Preferred Stock were converted
early into 1,309,495 shares of common stock at the election
of the holders. As of February 2, 2009, an additional
142,400 shares of 5.75% Preferred Stock was converted into
1,177,818 shares of common stock in 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.
As of December 31, 2008 and 2007, 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.
As of February 2, 2009, 100 shares of the 4% Preferred
Stock were converted into 5,000 shares of common stock in
2009. 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 (i) 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 (ii) any other class or series of 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 CS in a private placement. As of December 31,
2008 and 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
185
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
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. The conversion
feature is considered an embedded derivative per SFAS 133
that is exempt from derivative accounting as its excluded
from the scope pursuant to paragraph 11(a) of SFAS 133.
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
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.
186
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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 equity method
investments, as of December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Economic
|
|
Name
|
|
Geographic Area
|
|
|
Interest
|
|
|
MIBRAG
|
|
|
Germany
|
|
|
|
50.0
|
%
|
Sherbino I Wind Farm LLC
|
|
|
USA
|
|
|
|
50.0
|
%
|
Saguaro Power Company
|
|
|
USA
|
|
|
|
50.0
|
%
|
GenConn Energy LLC
|
|
|
USA
|
|
|
|
50.0
|
%
|
Gladstone Power Station
|
|
|
Australia
|
|
|
|
37.5
|
%
|
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,
2008, 2007 and 2006, NRGs equity earnings from MIBRAG were
approximately $31 million, $36 million and
$30 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.
Sherbino I Wind Farm LLC NRG owns a
50% interest in Sherbino, a joint venture with BP. Sherbino is a
150MW wind farm consisting of 50 Vestas 3 MW wind turbine
generators, which commenced commercial operations in October
2008. NRG contributed approximately $84 million to its
equity investment in Sherbino in 2008. For the year ended
December 31, 2008, NRGs equity earnings from Sherbino
were $8 million.
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 years ended
December 31, 2008, 2007 and 2006 NRGs equity loss
from Saguaro was $2 million, $3 million and
$1 million.
GenConn Energy LLC NRG owns a 50%
interest in GenConn, a limited liability company formed in
February 2008 by NRG and The United Illuminating Company, or UI,
for the construction and operation of two 200 MW peaking
facilities in Connecticut through GenConns wholly-owned
subsidiaries, GenConn Devon, LLC, or Devon, and GenConn
Middletown LLC, or Middletown. Devon and Middletown have each
entered into
30-year cost
of service type contracts with Connecticut Light &
Power, or CL&P, as mandated by the DPUC, commencing when
the facilities reach commercial operations, currently expected
to be 2010 and 2011, respectively.
187
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
The project is expected to be funded through equity
contributions from the owners and non-recourse, project level
debt. As of December 31, 2008, NRG has made a nominal
equity investment in GenConn. In addition, as discussed in
Note 8, Capital Leases and Notes Receivable, NRG
entered into a short-term $45 million note receivable
facility with GenConn to fund NRGs proportionate
share of project liquidity needs. GenConn had borrowed
$36 million under this facility as of December 31,
2008. As discussed in Note 25, Guarantees, NRG has
guaranteed its proportionate share of GenConns payments to
a vendor under turbine purchase agreements for the Devon and
Middletown sites, effective until such time as GenConn has
obtained financing for each of the respective projects. As of
December 31, 2008, NRGs potential remaining
obligation under the guarantees is $54 million. NRGs
maximum exposure to loss is limited to its equity investments
and note receivable, as well as its remaining potential
obligation under the turbine purchase guarantees.
As discussed in Note 20, Related Party Transactions,
a subsidiary of NRG has entered into construction management
agreements with Devon and Middletown, and recognized
approximately $1 million of revenue for the year ended
December 31, 2008.
GenConn is considered a VIE under FIN 46R, but NRG is not
the primary beneficiary of GenConn and accounts for its 50%
interest under the equity method. GenConn is a development stage
entity, and is not expected to begin generating revenues until
2010; therefore NRG recognized no equity earnings from the joint
venture for the year ended December 31, 2008.
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 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, 2008, 2007 and 2006, NRGs equity
earnings from Gladstone were approximately $21 million,
$21 million and $25 million, respectively.
On June 8, 2006, NRG announced the sale of the
Companys 37.5% equity interest in Gladstone, and its
associated 100% owned NRG Gladstone Operating Services to
Transfield Services Infrastructure B.V, or Transfield Services,
of Australia. On October 9, 2008, Transfield Services
signed a deed of termination which terminates the sale and
purchase agreement signed in June 2006.
188
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
Note 15
|
Gains/(Losses)
on Sales of Equity Method Investments
|
Gains or losses are recognized on completion of the sale. The
Company had no sales of equity method investments during the
year ended December 31, 2008. Gains/(losses) on sales of
equity method investments recorded in other income/expense in
the Companys consolidated statements of operations for the
years ended December 31, 2007 and 2006 include the
following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Segment
|
|
|
|
(In millions)
|
|
|
|
|
|
Powersmith Cogeneration
|
|
$
|
1
|
|
|
$
|
|
|
|
|
Corporate
|
|
Latin American Funds
|
|
|
|
|
|
|
3
|
|
|
|
International
|
|
James River Power LLC
|
|
|
|
|
|
|
(6
|
)
|
|
|
Corporate
|
|
Cadillac
|
|
|
|
|
|
|
11
|
|
|
|
Corporate
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total gains on sales of equity method investments
|
|
$
|
1
|
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 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.
189
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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 if-converted method is also used to determine the
dilutive effect of embedded derivatives in the Companys
3.625% Preferred Stock, and CSF preferred interests and notes.
The reconciliation of NRGs basic earnings per common share
to diluted earnings per share for the years ended
December 31, 2008, 2007 and 2006 is shown in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Basic earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
1,016
|
|
|
$
|
569
|
|
|
$
|
543
|
|
Preferred stock dividends
|
|
|
(55
|
)
|
|
|
(55
|
)
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
|
961
|
|
|
|
514
|
|
|
|
491
|
|
Discontinued operations, net of tax
|
|
|
172
|
|
|
|
17
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1,133
|
|
|
$
|
531
|
|
|
$
|
569
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
235.0
|
|
|
|
240.2
|
|
|
|
258.0
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
4.09
|
|
|
$
|
2.14
|
|
|
$
|
1.90
|
|
Discontinued operations, net of tax
|
|
|
0.73
|
|
|
|
0.07
|
|
|
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4.82
|
|
|
$
|
2.21
|
|
|
$
|
2.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
190
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Diluted earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
$
|
961
|
|
|
$
|
514
|
|
|
$
|
491
|
|
Add preferred stock dividends for dilutive preferred stock
|
|
|
46
|
|
|
|
46
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted income from continuing operations available to common
stockholders
|
|
|
1,007
|
|
|
|
560
|
|
|
|
534
|
|
Discontinued operations, net of tax
|
|
|
172
|
|
|
|
17
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
1,179
|
|
|
$
|
577
|
|
|
$
|
612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
235.0
|
|
|
|
240.2
|
|
|
|
258.0
|
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method)
|
|
|
2.3
|
|
|
|
3.8
|
|
|
|
2.8
|
|
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
|
|
|
|
37.5
|
|
|
|
39.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total dilutive shares
|
|
|
274.8
|
|
|
|
287.5
|
|
|
|
300.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations available to common
stockholders
|
|
$
|
3.66
|
|
|
$
|
1.95
|
|
|
$
|
1.78
|
|
Discontinued operations, net of tax
|
|
|
0.63
|
|
|
|
0.06
|
|
|
|
0.26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
4.29
|
|
|
$
|
2.01
|
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions of shares)
|
|
|
Equity compensation NQSOs and PUs
|
|
|
1.9
|
|
|
|
0.1
|
|
|
|
0.7
|
|
Embedded derivative of 3.625% redeemable perpetual preferred
stock
|
|
|
16.0
|
|
|
|
12.2
|
|
|
|
16.0
|
|
Embedded derivatives of CSF preferred interests and notes
|
|
|
7.6
|
|
|
|
16.1
|
|
|
|
18.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
25.5
|
|
|
|
28.4
|
|
|
|
35.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
191
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL
STATEMENTS (Continued)
|
|
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 including wind and nuclear development.
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, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Customer A Northeast region
|
|
|
|
%
|
|
|
|
%
|
|
|
10
|
%
|
Customer B Texas region
|
|
|
11
|
|
|
|
|
|
|
|
|
|
Customer C Texas region
|
|
|
11
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22
|
%
|
|
|
27
|
%
|
|
|
10
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
192
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
4,026
|
|
|
$
|
1,630
|
|
|
$
|
746
|
|
|
$
|
171
|
|
|
$
|
158
|
|
|
$
|
154
|
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
|
$
|
6,885
|
|
Operating expenses
|
|
|
1,890
|
|
|
|
1,087
|
|
|
|
579
|
|
|
|
105
|
|
|
|
133
|
|
|
|
122
|
|
|
|
52
|
|
|
|
(5
|
)
|
|
|
3,963
|
|
Depreciation and amortization
|
|
|
451
|
|
|
|
109
|
|
|
|
67
|
|
|
|
8
|
|
|
|
|
|
|
|
10
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
1,685
|
|
|
|
434
|
|
|
|
100
|
|
|
|
58
|
|
|
|
25
|
|
|
|
22
|
|
|
|
(53
|
)
|
|
|
2
|
|
|
|
2,273
|
|
Equity in earnings/(loss) of unconsolidated affiliates
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
Other income, net
|
|
|
9
|
|
|
|
12
|
|
|
|
1
|
|
|
|
1
|
|
|
|
5
|
|
|
|
|
|
|
|
20
|
|
|
|
(31
|
)
|
|
|
17
|
|
Interest expense
|
|
|
(100
|
)
|
|
|
(56
|
)
|
|
|
(51
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
(6
|
)
|
|
|
(420
|
)
|
|
|
19
|
|
|
|
(620
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
1,603
|
|
|
|
390
|
|
|
|
50
|
|
|
|
51
|
|
|
|
82
|
|
|
|
16
|
|
|
|
(453
|
)
|
|
|
(10
|
)
|
|
|
1,729
|
|
Income tax expense
|
|
|
692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
911
|
|
|
|
390
|
|
|
|
50
|
|
|
|
51
|
|
|
|
63
|
|
|
|
16
|
|
|
|
(455
|
)
|
|
|
(10
|
)
|
|
|
1,016
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
911
|
|
|
$
|
390
|
|
|
$
|
50
|
|
|
$
|
51
|
|
|
$
|
235
|
|
|
$
|
16
|
|
|
$
|
(455
|
)
|
|
$
|
(10
|
)
|
|
$
|
1,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
$
|
92
|
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
25
|
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
490
|
|
Capital expenditures
|
|
|
238
|
|
|
|
208
|
|
|
|
14
|
|
|
|
35
|
|
|
|
|
|
|
|
11
|
|
|
|
509
|
|
|
|
|
|
|
|
1,015
|
|
Goodwill
|
|
|
1,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
1,718
|
|
Total assets
|
|
$
|
12,899
|
|
|
$
|
1,667
|
|
|
$
|
933
|
|
|
$
|
264
|
|
|
$
|
973
|
|
|
$
|
208
|
|
|
$
|
20,208
|
|
|
$
|
(12,344
|
)
|
|
$
|
24,808
|
|
193
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
|
|
Gains on sale of equity method investment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 from 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
|
|
194
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
|
|
Gains 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 from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
729
|
|
|
$
|
404
|
|
|
$
|
48
|
|
|
$
|
12
|
|
|
$
|
129
|
|
|
$
|
13
|
|
|
$
|
(656
|
)
|
|
$
|
(58
|
)
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
195
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The income tax provision from continuing operations for the
years ended December 31, 2008, 2007 and 2006 consisted of
the following amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
US Federal
|
|
$
|
89
|
|
|
$
|
(6
|
)
|
|
$
|
(26
|
)
|
State
|
|
|
31
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Foreign
|
|
|
17
|
|
|
|
20
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137
|
|
|
|
13
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
US Federal
|
|
|
539
|
|
|
|
347
|
|
|
|
288
|
|
State
|
|
|
35
|
|
|
|
47
|
|
|
|
38
|
|
Foreign
|
|
|
2
|
|
|
|
(30
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
576
|
|
|
|
364
|
|
|
|
330
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax
|
|
$
|
713
|
|
|
$
|
377
|
|
|
$
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
41.2
|
%
|
|
|
39.9
|
%
|
|
|
37.2
|
%
|
The following represents the domestic and foreign components of
income from continuing operations before income tax expense for
the years ended December 31, 2008, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
US
|
|
$
|
1,644
|
|
|
$
|
860
|
|
|
$
|
767
|
|
Foreign
|
|
|
85
|
|
|
|
86
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,729
|
|
|
$
|
946
|
|
|
$
|
865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
196
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
A reconciliation of the US federal statutory rate of 35% to
NRGs effective rate from continuing operations for the
years ended December 31, 2008, 2007 and 2006 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions, except percentages)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,729
|
|
|
$
|
946
|
|
|
$
|
865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
605
|
|
|
|
331
|
|
|
|
303
|
|
State taxes, net of federal benefit
|
|
|
73
|
|
|
|
46
|
|
|
|
34
|
|
Foreign operations
|
|
|
(10
|
)
|
|
|
(13
|
)
|
|
|
(21
|
)
|
Subpart F taxable income
|
|
|
2
|
|
|
|
|
|
|
|
11
|
|
Valuation allowance, including change
in state effective rate
|
|
|
(12
|
)
|
|
|
6
|
|
|
|
(10
|
)
|
Change in state effective tax rate
|
|
|
(11
|
)
|
|
|
|
|
|
|
21
|
|
Claimant reserve settlements
|
|
|
|
|
|
|
|
|
|
|
(28
|
)
|
Change in local German effective
tax rates
|
|
|
|
|
|
|
(29
|
)
|
|
|
|
|
Foreign dividends
|
|
|
32
|
|
|
|
26
|
|
|
|
1
|
|
Non-deductible interest
|
|
|
26
|
|
|
|
10
|
|
|
|
3
|
|
Permanent differences, reserves, other
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
713
|
|
|
$
|
377
|
|
|
$
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
41.2
|
%
|
|
|
39.9
|
%
|
|
|
37.2
|
%
|
The effective income tax rate for the year ended
December 31, 2008 and 2007 differs from the
US statutory rate of 35% due to a taxable dividend from
foreign operations, including the provision of deferred taxes in
2008 on foreign income no longer expected to be permanently
reinvested overseas, and non-deductible interest. In addition,
earnings in foreign jurisdictions are taxed at rates lower than
the US 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
US. 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
US statutory rate.
For the year ended December 31, 2008, NRGs state
effective income tax rate has been reduced to 6%, which is lower
than its 2007 rate of 7%, due to increased operational
activities within the state of Texas in the current year. 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.
197
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, 2008
and 2007, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Discount/premium on notes
|
|
$
|
13
|
|
|
$
|
23
|
|
Emissions allowances
|
|
|
112
|
|
|
|
109
|
|
Difference between book and tax basis of property
|
|
|
1,477
|
|
|
|
1,568
|
|
Derivatives, net
|
|
|
440
|
|
|
|
|
|
Goodwill
|
|
|
73
|
|
|
|
45
|
|
Anticipated repatriation of foreign earnings
|
|
|
26
|
|
|
|
|
|
Cumulative translation adjustments
|
|
|
22
|
|
|
|
|
|
Investment in projects
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
2,163
|
|
|
|
1,751
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Deferred compensation, pension, accrued vacation and other
reserves
|
|
|
126
|
|
|
|
129
|
|
Derivatives, net
|
|
|
|
|
|
|
125
|
|
Differences between book and tax basis of contracts
|
|
|
377
|
|
|
|
577
|
|
Non-depreciable property
|
|
|
19
|
|
|
|
19
|
|
Intangibles amortization (excluding goodwill)
|
|
|
164
|
|
|
|
152
|
|
Equity compensation
|
|
|
22
|
|
|
|
15
|
|
Claimants reserve
|
|
|
10
|
|
|
|
7
|
|
US capital loss carryforwards
|
|
|
274
|
|
|
|
439
|
|
Foreign net operating loss carryforwards
|
|
|
66
|
|
|
|
80
|
|
State net operating loss carryforwards
|
|
|
28
|
|
|
|
|
|
Foreign capital loss carryforwards
|
|
|
1
|
|
|
|
1
|
|
Investments in projects
|
|
|
10
|
|
|
|
|
|
Deferred financing costs
|
|
|
10
|
|
|
|
12
|
|
Alternative minimum tax
|
|
|
20
|
|
|
|
3
|
|
Other
|
|
|
4
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
1,131
|
|
|
|
1,571
|
|
Valuation allowance
|
|
|
(359
|
)
|
|
|
(539
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
772
|
|
|
|
1,032
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
1,391
|
|
|
$
|
719
|
|
|
|
|
|
|
|
|
|
|
198
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes NRGs net deferred tax
position as of December 31, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Current deferred tax asset
|
|
$
|
|
|
|
$
|
124
|
|
Current deferred tax liability
|
|
|
201
|
|
|
|
|
|
Non-current deferred tax liability
|
|
|
1,190
|
|
|
|
843
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
1,391
|
|
|
$
|
719
|
|
|
|
|
|
|
|
|
|
|
Tax
Receivable and Payable
As of December 31, 2008, NRG recorded a current tax payable
of approximately $30 million that represents a tax
liability due to a domestic state tax of approximately
$24 million, as well as foreign taxes payable of
approximately $6 million. In addition, NRG has a domestic
tax receivable of $54 million.
Deferred
tax assets and valuation allowance
Net deferred tax balance As of
December 31, 2008 and 2007, NRG recorded a net deferred tax
liability of $1,032 million and $180 million, respectively.
However, due to an assessment of positive and negative evidence,
including 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 $359 and $539 million of
tax assets, thus a valuation allowance has remained, resulting
in a net deferred tax liability of $1,391 million and
$719 million as of December 31, 2008 and 2007,
respectively. 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, 2008.
NOL carryforwards For the years ended
December 31, 2008 and 2007, the Company generated total
domestic pretax book income of $1,644 million and
$860 million, respectively. As a result, a cumulative
domestic net operating loss, or NOL, in the amount
$245 million had been fully utilized as of
December 31, 2007 with the exception of certain state NOLs.
In addition, as of December 31, 2008, NRG has cumulative
foreign NOL carryforwards of $239 million of which
$41 million will expire starting 2011 through 2017 and of
which $198 million do not have an expiration date.
Valuation allowance As of December 31,
2008, 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 and income tax benefit of approximately
$162 million and $12 million respectively. In
accordance with SFAS 141R, any future reductions to
valuation allowance occurring after January 1, 2009 will be
credited to income tax expense rather than APIC.
APIC adjustment During 2008, the Company
recorded $14 million through APIC for various Fresh-Start
related book-tax differences.
APB
Opinion 23
Through 2007, it was managements intent to permanently
reinvest unremitted 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 have been recognized for the cumulative
translation adjustment as of December 31, 2007.
199
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Uncertain
tax benefits
NRG has identified certain unrecognized tax benefits whose
after-tax value was $527 million, of which $36 million
would impact the Companys income tax expense. Of the
$527 million in unrecognized tax benefits,
$491 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, or APIC. In accordance with SFAS 141R, any changes
to our uncertain tax benefits occurring after January 1,
2009 will be credited to income tax expense rather than APIC.
As of December 31, 2008, NRG has recorded a
$208 million non-current tax liability for unrecognized tax
benefits, resulting from taxable earnings for the period for
which there are no NOLs available to offset for financial
statement purposes. NRG accrued interest and penalties related
to these unrecognized tax benefits of approximately
$8 million as of December 31, 2008. 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 US federal jurisdiction and various state and foreign
jurisdictions including major operations located in Germany and
Australia. The Company is no longer subject to US 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.
The Company has been contacted for examination by the Internal
Revenue Service for years 2004 through 2006. The audit commenced
during the third quarter 2008 and is expected to continue for
approximately 18 to 24 months.
Sale of ITISA On April 28, 2008, NRG
completed the sale of its 100% interest in Tosli Acquisition
B.V., or Tosli, which held all NRGs interest in ITISA, to
Brookfield Renewable Power Inc. (previously Brookfield Power
Inc.), a wholly-owned subsidiary of Brookfield Asset Management
Inc. In addition, the purchase price adjustment contingency
under the sale agreement was resolved on August 7, 2008. In
connection with the sale, NRG recorded a capital gain of
$215 million which further reduced our uncertain tax
benefits.
The following table reconciles the total amounts of unrecognized
tax benefits at the beginning and end of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
(In millions)
|
|
|
Balance as of January 1
|
|
$
|
683
|
|
|
$
|
712
|
|
Increase due to current year positions
|
|
|
18
|
|
|
|
76
|
|
Decrease due to current year positions
|
|
|
(183
|
)
|
|
|
(105
|
)
|
Increase due to prior year positions
|
|
|
9
|
|
|
|
|
|
Decrease due to prior year positions
|
|
|
|
|
|
|
|
|
Decrease due to settlements and payments
|
|
|
|
|
|
|
|
|
Decrease due to statute expirations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits as of December 31
|
|
$
|
527
|
|
|
$
|
683
|
|
|
|
|
|
|
|
|
|
|
200
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Due to the classification of NOLs as capital losses for
financial statement purposes, $292 million of the
Companys $527 million unrecognized tax benefit will
expire as of December 31, 2009.
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
|
The Company adopted SFAS 123R, effective January 1,
2006, with no material effect on NRGs consolidated
statements of operations.
Long-Term
Incentive Plan, or LTIP
As of December 31, 2008 and 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
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
6,798,074 and 7,941,758 shares of common stock remaining
available for grants under NRGs LTIP as of
December 31, 2008 and 2007, respectively.
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. NRG
recognizes compensation costs for NQSOs on a straight-line
basis over the requisite service period for the entire award.
The maximum contractual term is ten years for approximately
1.1 million of NRGs outstanding NQSOs, and six
years for the remaining 2.9 million NQSOs.
The following table summarizes the Companys NQSO activity
as of December 31, 2008 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)
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2007
|
|
|
3,579,775
|
|
|
$
|
19.98
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
1,206,800
|
|
|
|
39.94
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(250,401
|
)
|
|
|
30.09
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(527,986
|
)
|
|
|
16.41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
4,008,188
|
|
|
|
25.84
|
|
|
|
4
|
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2008
|
|
|
2,009,205
|
|
|
|
17.55
|
|
|
|
4
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
201
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The weighted average grant date fair value of options granted
during the years ended December 31, 2008, 2007 and 2006 was
$10.33, $8.28, and $7.26, respectively. The total intrinsic
value of options exercised during the years ended
December 31, 2008, 2007 and 2006 was $14 million,
$11 million and $1 million, respectively and cash
received from the exercise of these options was $9 million,
$7 million and $1 million, respectively.
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, 2008, 2007 and 2006 with respect
to the Companys NQSOs are summarized below:
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Expected volatility
|
|
26.75%-44.00%
|
|
25.88%-27.28%
|
|
27.95%-29.64%
|
Expected term (in years)
|
|
4
|
|
4
|
|
4-6
|
Risk free rate
|
|
1.33%-3.09%
|
|
4.58%-4.68%
|
|
4.30%-5.05%
|
For 2006, expected volatility was calculated based on a blended
average of NRG and NRGs industry peers historical
two-year stock price volatility data. For 2008 and 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 summarizes the
Companys non-vested RSU awards as of December 31,
2008 and changes during the year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole)
|
|
|
Non-vested at December 31, 2007
|
|
|
1,588,316
|
|
|
$
|
26.99
|
|
Granted
|
|
|
166,400
|
|
|
|
39.84
|
|
Forfeited
|
|
|
(81,900
|
)
|
|
|
32.23
|
|
Vested
|
|
|
(610,820
|
)
|
|
|
19.38
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2008
|
|
|
1,061,996
|
|
|
|
32.97
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSUs vested during the years ended
December 31, 2008, 2007 and 2006, was $22 million,
$40 million and $11 million, respectively.
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.
202
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
The following table summarizes the Companys outstanding
DSU awards as of December 31, 2008 and changes during the
year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole)
|
|
|
Outstanding at December 31, 2007
|
|
|
268,994
|
|
|
$
|
18.06
|
|
Granted
|
|
|
29,614
|
|
|
|
35.12
|
|
Conversions
|
|
|
(37,840
|
)
|
|
|
28.41
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
260,768
|
|
|
|
18.50
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic values for DSUs outstanding as of
December 31, 2008, 2007 and 2006 were approximately
$6 million, $12 million, and $8 million
respectively. The aggregate intrinsic values for DSUs
converted to common stock for the years ended December 31,
2008, 2007 and 2006 were $1.5 million, $1.2 million
and $0.4 million, respectively.
Performance
Units, or PUs
PUs granted under the Companys LTIP fully vest three
years from the date of issuance. PUs granted prior to
January 1, 2009 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. PUs granted after January 1,
2009 are paid out upon vesting if the Measurement Price is equal
to or greater than 9% growth in the NRG stock price compounded
annually over three years, or the Threshold Price. The payout
for each PU will be equal to a pro-rated amount in between
one-half and one share of common stock if the Measurement Price
equals or exceeds the Threshold Price but less than the Target
Price. The payout for each PU will be equal to a pro-rated
amount in between one and two shares of common stock, if the
Measurement Price is equal to the Target Price but less than the
Maximum Price. The payout for each PU will be equal to two
shares of common stock if the Measurement Price is equal to or
greater than the Maximum Price.
The following table summarizes the Companys non-vested PU
awards as of December 31, 2008 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, 2007
|
|
|
536,764
|
|
|
$
|
20.18
|
|
Granted
|
|
|
233,700
|
|
|
|
26.99
|
|
Vested
|
|
|
(50,000
|
)
|
|
|
15.74
|
|
Forfeited
|
|
|
(60,900
|
)
|
|
|
21.65
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2008
|
|
|
659,564
|
|
|
|
22.81
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of PUs granted
during the years ended December 31, 2008, 2007 and 2006 was
$26.99, $22.43 and $17.62, respectively.
203
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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, 2008, 2007 and 2006 with respect to the
Companys PUs are summarized below:
|
|
|
|
|
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
Expected volatility
|
|
27.81%-48.06%
|
|
25.91%-27.28%
|
|
27.95%-29.64%
|
Expected term (in years)
|
|
3
|
|
3
|
|
3-5
|
Risk free rate
|
|
1.13%-2.89%
|
|
4.54%-4.69%
|
|
4.30%-5.04%
|
For 2006, expected volatility was calculated based on a blended
average of NRG and NRGs industry peers historical
two-year stock price volatility data. For 2008 and 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 123R for the
years ended December 31, 2008, 2007 and 2006 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, 2008. Minimum tax
withholdings of $10 million, $17 million and
$5 million paid by the Company during 2008, 2007 and 2006,
respectively, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested Compensation Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition Period
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized
|
|
|
Remaining
|
|
|
|
Compensation Expense
|
|
|
Total Cost
|
|
|
(In years)
|
|
|
|
Year Ended December 31
|
|
|
As of December 31
|
|
Award
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2008
|
|
|
|
(In millions, except weighted average data)
|
|
|
NQSOs
|
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
5
|
|
|
$
|
11
|
|
|
|
1.2
|
|
RSUs
|
|
|
12
|
|
|
|
10
|
|
|
|
10
|
|
|
|
18
|
|
|
|
1.2
|
|
DSUs
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
PUs
|
|
|
5
|
|
|
|
3
|
|
|
|
2
|
|
|
|
6
|
|
|
|
1.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
26
|
|
|
$
|
19
|
|
|
$
|
18
|
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit recognized
|
|
$
|
10
|
|
|
$
|
8
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employee
Stock Purchase Plan
In May 2008, NRG shareholders approved the adoption of the NRG
Energy, Inc. Employee Stock Purchase Plan, or ESPP, pursuant to
which eligible employees may elect to withhold up to 10% of
their eligible compensation to purchase shares of NRG common
stock at 85% of its fair market value on the exercise date. An
exercise date occurs each June 30 and December 31. The
initial six month employee withholding period began July 1,
2008 and ended December 31, 2008. As of December 31,
2008, there were 500,000 shares of treasury stock reserved
for issuance under the ESPP. In January 2009, 41,706 shares
were issued to employees accounts from the treasury
stock reserve for the ESPP.
204
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Other
Compensation Arrangements
NRG also sponsors certain cash-settled equity award programs,
under which employees are eligible to receive future cash
compensation upon fulfillment of the vesting criteria for the
particular program. The aggregate compensation expense for these
arrangements was approximately $1 million for the year
ended December 31, 2008.
|
|
Note 20
|
Related
Party Transactions
|
Operating
Agreements
NRG has entered into operation and maintenance agreements, or
O&M agreements, with certain Company equity investments.
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 has entered into construction management
agreements, or CMA agreements, with GenConn and Sherbino. Under
the CMA agreements NRG will receive fees for management, design
and construction services. NRG also renders technical consulting
services to MIBRAG under a consulting agreement and 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Revenues from Related Parties Included in Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
4
|
|
Gladstone
|
|
|
2
|
|
|
|
1
|
|
|
|
2
|
|
GenConn
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Sherbino
|
|
|
1
|
|
|
|
|
|
|
|
|
|
WCP(a)
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses from Related Parties Included in Cost of
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of purchased coal
|
|
$
|
57
|
|
|
$
|
43
|
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
For the period January 1, 2006
to March 31, 2006.
|
|
|
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 2027. 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, $40 million and
$37 million for the years ended December 31, 2008,
2007 and 2006, respectively.
205
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Future minimum lease commitments under operating leases for the
years ending after December 31, 2008 are as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2009
|
|
$
|
43
|
|
2010
|
|
|
41
|
|
2011
|
|
|
38
|
|
2012
|
|
|
33
|
|
2013
|
|
|
29
|
|
Thereafter
|
|
|
193
|
|
|
|
|
|
|
Total
|
|
$
|
377
|
|
|
|
|
|
|
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,
2008, 2007, and 2006, the Company purchased approximately
$1.8 billion, $1.7 billion and $1.8 billion,
respectively, under such arrangements.
As of December 31, 2008, the Companys commitments
under such outstanding agreements are estimated as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2009
|
|
$
|
1,513
|
|
2010
|
|
|
294
|
|
2011
|
|
|
183
|
|
2012
|
|
|
151
|
|
2013
|
|
|
31
|
|
Thereafter
|
|
|
206
|
|
|
|
|
|
|
Total(a)
|
|
$
|
2,378
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes those coal transportation
and lignite commitments for 2009 as no other nominations were
made as of December 31, 2008. Natural gas nomination is
through February 2010.
|
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 Limestone facility under an amended long-term
contract with Texas Westmoreland Coal Co, or TWCC. During 2007,
NRG and TWCC renegotiated a long-term contract that
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 the 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 was
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
ARO for mine reclamation costs increased by $5 million.
206
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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, 2008, the Company was obligated for the loan
of AUD 20 million (approximately US $14 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 liens to certain counterparties
on substantially all of the Companys assets. 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 out-of-the-money hedge agreements for forward sales of
power or MWh equivalents. To the extent that the underlying
hedge positions for a counterparty are in-the-money to NRG, the
counterparty would have no claim under the lien program. The
lien program limits the volumes that can be hedged, not the
value of underlying out-of-the money positions. The first lien
program does not require NRG to post collateral above any
threshold amount of exposure. 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 for the first 60 months and then declining
thereafter. Net exposure to a counterparty on all trades must be
positively correlated to the price of the relevant commodity for
the first lien to be available to that counterparty. The first
and second lien structure is not subject to unwind or
termination upon a ratings downgrade of a counterparty and has
no stated maturity date.
The Companys lien counterparties may have a claim on our
assets to the extent market prices exceed the hedged price. As
of December 31, 2008 and February 2, 2009, the first
lien exposure of net out-of-the-money positions to
counterparties on hedges was $88 million and
$43 million, respectively. As of December 31, 2008 and
February 2, 2009, there was no exposure to out-of-the-money
positions to counterparties on hedges under the second lien.
RepoweringNRG
Initiatives
NRG has made non-refundable payments of $188 million in
support of expected deliveries of wind turbines totaling
approximately $215 million through 2009. The Company
believes that these payments are necessary for the timely and
successful execution of related RepoweringNRG initiatives.
In addition, NRG has capitalized $30 million through
December 31, 2008 for the repowering of its El Segundo
generating facility in California. As a result of permitting
delays related to on-going Natural Resource Defense Counsel
claims, the El Segundo project is unlikely to reach its original
completion date of June 1, 2011.
207
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Contingencies
Set forth below is a description of the Companys material
legal proceedings. The Company believes that it has valid
defenses to these legal proceedings and intends to defend them
vigorously. 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, or
range of loss, can be reasonably estimated. In addition legal
cost are expensed as incurred. Management has assessed each of
the following 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. Unless specified below, the
Company is unable to predict the outcome of these legal
proceedings or reasonably estimate the scope or amount of any
associated costs and potential liabilities. As additional
information becomes available, management adjusts its assessment
and estimates of such contingencies accordingly. Because
litigation is subject to inherent uncertainties and unfavorable
rulings or developments, it is possible that the ultimate
resolution of the Companys liabilities and contingencies
could be at amounts that are different from its currently
recorded reserves and that such difference could be material.
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 affect NRGs consolidated
financial position, results of operations, or cash flows.
Exelon
Related Litigation
Delaware
Chancery Court
On November 11, 2008, Exelon and its wholly-owned
subsidiary Exelon Xchange filed a complaint against NRG and
NRGs Board of Directors. The complaint alleges, among
other things, that NRGs Board of Directors failed to give
due consideration and to take appropriate action in response to
the acquisition proposal announced by Exelon on October 19,
2008, in which Exelon offered to acquire all of the outstanding
shares of NRG common stock at an exchange ratio of 0.485 Exelon
shares for each NRG common share. The complaint seeks, among
other things, declaratory and injunctive relief:
(1) declaring that NRGs Board of Directors has
breached its fiduciary duties to the NRG stockholders by
rejecting and refusing to consider Exelons acquisition
proposal and by failing to exempt the proposed transaction from
application of Section 203 of the Delaware General
Corporation Law; (2) compelling NRGs Board of
Directors to approve Exelons acquisition proposal for
purposes of Section 203 of the Delaware General
Corporations Law; (3) declaring that the adoption of any
measure that would have the effect of impeding or interfering
with Exelons acquisition proposal constitutes a breach of
NRGs Board of Directors fiduciary duties; and
(4) enjoining the defendants from adopting any measures
that would have the effect of impeding or interfering with
Exelons acquisition proposal. On November 14, 2008,
NRG and NRGs Board of Directors filed a motion to dismiss
Exelons complaint on the grounds that it failed to state a
claim upon which relief can be granted. On January 28,
2009, NRG and NRGs Board of Directors filed their brief in
support of their motion to dismiss.
On December 11, the Louisiana Sheriffs
Pension & Relief Fund and City of St. Claire Shores
Police & Fire Retirement System, on behalf of
themselves and all others similarly situated, served a
previously filed complaint on NRG and its Board of Directors
alleging substantially similar allegations as the Exelon
complaint. On December 23, 2008, NRG and NRGs Board
of Directors filed a motion to dismiss the complaint on the
grounds that it failed to state a claim upon which relief can be
granted. On January 28, 2009, NRG and NRGs Board of
Directors filed their brief in support of their motion to
dismiss.
208
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Mercer
County, New Jersey Superior Court
On January 6, 2009, three lawsuits previously filed against
NRG and NRGs Board of Directors on behalf of individual
shareholders and all others similarly situated were consolidated
into one case in the Law Division of the Superior Court of
Mercer County, New Jersey. On January 21, 2009, the
plaintiffs filed an Amended Consolidated Complaint in which they
allege a single count of breach of fiduciary duty against
NRGs Board of Directors and seek injunctive relief:
(1) declaring that the action is a class action and
certifying plaintiffs as class plaintiffs and counsel as class
counsel; (2) declaring that defendants breached their
fiduciary duties by summarily rejecting the Exelon offer;
(3) ordering defendants to negotiate with respect to the
Exelon offer or with respect to another transaction to maximize
shareholder value; (4) ordering defendants to exempt
Exelons offer from Section 203 of the Delaware
General Corporations Law; (5) awarding compensatory damages
including interest; (6) awarding plaintiffs costs and fees;
and (7) granting other relief the Court deems proper. A
response is due on or before February 20, 2009.
California
Department of Water Resources
This matter concerns, among other contracts and other
defendants, the CDWR and its wholesale power contract with
subsidiaries of WCP (Generation) Holdings, Inc., or 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 of California. For WCP, the
alleged overcharges totaled approximately $940 million for
2001 and 2002. The complaint demanded that the FERC abrogate the
CDWR contract and sought refunds associated with revenues
collected under the contract. In 2003, the FERC rejected this
complaint, denied rehearing, and the case was appealed to the US
Court of Appeals for the Ninth Circuit, or Ninth Circuit, where
oral argument was held on December 8, 2004. On
December 19, 2006, the Ninth Circuit decided that in the
FERCs review of the contracts at issue, the FERC could not
rely on the Mobil-Sierra standard presumption of just and
reasonable rates, where such contracts were not reviewed by the
FERC with full knowledge of the then existing market conditions.
WCP and others sought review by the US Supreme Court. WCPs
appeal was not selected, but instead held by the Supreme Court.
In the appeal that was selected by the Supreme Court, on
June 26, 2008, the Supreme Court ruled (1) that the
Mobil-Sierra public interest standard of review applied
to contracts made under a sellers market-based rate
authority; (2) that the public interest bar
required to set aside a contract remains a very high one to
overcome; and (3) that the Mobil-Sierra presumption
of contract reasonableness applies when a contract is formed
during a period of market dysfunction unless (a) such
market conditions were caused by the illegal actions of one of
the parties or (b) the contract negotiations were tainted
by fraud or duress. In this related case, the US Supreme Court
affirmed the Ninth Circuits decision agreeing that the
case should be remanded to FERC to clarify FERCs 2003
reasoning regarding its rejection of the original complaint
relating to the financial burdens under the contracts at issue
and to alleged market manipulation at the time these contracts
were formed. As a result, the US Supreme Court then reversed and
remanded the WCP CDWR case to the Ninth Circuit for treatment
consistent with its June 26, 2008, decision in the related
case. On October 20, 2008, the Ninth Circuit asked the
parties in the remanded CDWR case, including WCP and the FERC,
whether that Court should answer a question the US Supreme Court
did not address in its June 26, 2008, decision; whether the
Mobil-Sierra doctrine applies to a third-party that was
not a signatory to any of the wholesale power contracts,
including the CDWR contract, at issue in the case. Without
answering that reserved question, on December 4, 2008, the
Ninth Circuit vacated its prior opinion and remanded the WCP
CDWR case back to the FERC for proceedings consistent with the
US Supreme Courts June 26, 2008, decision. On
December 15, 2008, WCP and the other seller-defendants
filed with FERC a Motion for Order Governing Proceedings on
Remand. On January 14, 2009, the Public Utilities
Commission of the State of California filed an Answer and Cross
Motion for an Order Governing Procedures on Remand, and on
January 28, 2009, WCP and the other seller-defendants filed
their reply.
209
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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 the 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.
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. On
December 18, 2008, NRG filed with the US Bankruptcy Court
for the Southern District of New York a Closing Report and an
Application for Final Decree Closing the Chapter 11 Case
for NRG Energy, Inc. et al and on December 29, 2008,
the court entered the Final Decree. As of December 21,
2008, the reserve held approximately $9,776,880 in cash and
1,282,783 shares of common stock. On December 21,
2008, the Company issued an instruction letter to The Bank of
New York Mellon to distribute all remaining cash and stock in
the Disputed Claims Reserve to NRGs creditors. On
January 12, 2009, The Bank of New York Mellon commenced the
distribution of all remaining cash and stock in the Disputed
Claim Reserve to the Companys creditors pursuant to
NRGs Chapter 11 bankruptcy plan.
210
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Note 22 Regulatory
Matters
NRG operates in a highly regulated industry and 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.
New England On July 16, 2007, the FERC
conditionally accepted, subject to refund, the RMR agreement
filed on April 26, 2007 by Norwalk Power for its units 1
and 2, specifying a June 19, 2007 effective date. On
December 4, 2008, Norwalk Power filed a Settlement
Agreement resolving the RMR agreement eligibility and rate
issues. The Settlement Agreement provides for an Annual Fixed
Revenue Requirement of $34 million for 2008 and
$32 million for 2009, continuing at a rate of
$32 million per year until FCM is implemented on
June 1, 2010. The FERC accepted the Settlement Agreement on
December 30, 2008.
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. The settlement, filed at the FERC on
September 29, 2006, provides for a capacity market
mechanism known as the RPM which is designed to provide a
long-term price signal through competitive forward auctions. On
December 22, 2006, the FERC issued an order accepting the
settlement, which was reaffirmed on rehearing by order dated
June 25, 2007. The RPM auctions have been conducted 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 May 30, 2008, the Maryland Public Service Commission
together with other load interests, filed at the FERC a
complaint against PJM challenging the results of the RPM
transition Base Residual Auctions for installed capacity, held
between April 2007 and January 2008. The complaint seeks to
replace the auction-determined results for installed capacity
for the 2008/2009, 2009/2010, and 2010/2011 delivery years with
administratively-determined prices. On September 19, 2008,
the FERC dismissed the complaint. The parties representing load
interests have sought rehearing of the dismissal of the
complaint. In a related proceeding, PJM filed proposed changes
to RPM on December 12, 2008.
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 US. 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 legislation
and regulations to mitigate the effects of GHG 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 2009
through 2013 to meet NRGs environmental commitments will
be approximately $1.2 billion (unaudited). These capital
expenditures, in general, are related to installation of
particulate,
SO2,
NOx,
and mercury controls to comply with federal and state air
quality rules and consent orders, 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. While this
estimate reflects anticipated schedules and controls related to
2008 court rulings that affect requirements for both CAIR and
CAMR, the full impact on the scope and timing of environmental
retrofits from any new or revised regulations cannot be
determined at this time.
211
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
Northeast
Region
NRG operates electric generating units located in Connecticut,
Delaware, Maryland, Massachusetts and New York which are
subject to RGGI. These units will have to surrender one
allowance for every US ton of
CO2
emitted with true up for
2009-2011
occurring in 2012. Allowances will be partially allocated in the
state of Delaware only. In 2008, NRG emitted approximately
12 million tonnes of
CO2
in RGGI states. NRG believes that to the extent
CO2
will not be fully reflected in wholesale electricity prices, the
direct financial impact on the Company is likely to be negative
as costs will be incurred in the course of securing the
necessary RGGI allowances and offsets at auction and in the
market.
In January 2006, NRGs Indian River Operations, Inc.
received a letter of informal notification from the DNREC
stating that the Company may be a potentially responsible party
with respect to a historic captive landfill. On October 1,
2007, NRG signed an agreement with DNREC to investigate the site
through the Voluntary
Clean-up
Program. On February 4, 2008, the DNREC issued findings
that 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
are completed, the Company is unable to predict the impact of
any required remediation.
On May 29, 2008, the DNREC issued an invitation to
NRGs Indian River Operations, Inc. to participate in the
development and performance of a Natural Resource Damage
Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG
is currently working with the DNREC and other trustees to close
out the property.
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 CAA from the USEPA seeking
information primarily related to physical changes made at the
Big Cajun II plant, and subsequently received a 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. NRG has evaluated the original and subsequent
claims and believes they have no merit. Nonetheless, NRG has had
discussions with the USEPA about resolving the claims and the
Company cannot predict with certainty the outcome of this matter.
212
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 December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In millions)
|
|
|
Interest paid, net of amount
capitalized(a)
|
|
$
|
563
|
|
|
$
|
598
|
|
|
$
|
450
|
|
Income taxes
paid(b)
|
|
|
46
|
|
|
|
22
|
|
|
|
18
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Reduction)/addition to fixed assets due to asset retirement
obligations
|
|
|
(39
|
)
|
|
|
7
|
|
|
|
15
|
|
Additions to fixed assets for accrued capital expenditures
|
|
|
116
|
|
|
|
|
|
|
|
|
|
Decrease to 5.75% preferred stock from conversion to common stock
|
|
|
(39
|
)
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
2008 interest paid includes
$45 million payment to settle the CSF I CAGR.
|
|
|
|
(b)
|
|
2008 and 2007 income taxes paid is
net of $2 and $6 million, respectively, of income tax
refunds 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 purchases and sale agreements,
commodity sale and purchase agreements, joint venture
agreements, EPC agreements, operation and maintenance
agreements, service agreements, settlement agreements, and other
types of contractual agreements with vendors and other third
parties, as well as affiliates. These contracts generally
indemnify the counterparty for tax, environmental liability,
litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these
agreements. In some cases, NRGs maximum potential
liability cannot be estimated, since 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 $7 million as of
December 31, 2008, 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,
|
|
|
|
2008
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2007
|
|
Guarantees
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Synthetic letters of credit
|
|
$
|
357
|
|
|
$
|
83
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
440
|
|
|
$
|
743
|
|
Unfunded letters of credit and surety bonds
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
8
|
|
Asset sales guarantee obligations
|
|
|
|
|
|
|
112
|
|
|
|
|
|
|
|
17
|
|
|
|
129
|
|
|
|
148
|
|
Commercial sales arrangements
|
|
|
192
|
|
|
|
13
|
|
|
|
|
|
|
|
800
|
|
|
|
1,005
|
|
|
|
791
|
|
Other guarantees
|
|
|
24
|
|
|
|
30
|
|
|
|
|
|
|
|
26
|
|
|
|
80
|
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total guarantees
|
|
$
|
578
|
|
|
$
|
238
|
|
|
$
|
|
|
|
$
|
843
|
|
|
$
|
1,659
|
|
|
$
|
1,722
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letters of credit and surety bonds As of
December 31, 2008, NRG and its consolidated subsidiaries
were contingently obligated for a total of approximately
$445 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
213
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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.
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.
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 US, 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. NRG has executed guarantees with
related parties for one of its subsidiarys obligations as
construction manager under EPC contracts for the construction of
the Sherbino wind farm and two peaking power plants at
GenConns Devon and Middletown sites. See Note 14,
Investments Accounted for by the Equity Method, for more
information on these equity investments. The Company does not
believe that it will be required to perform under these
guarantees.
In addition, GenConn has entered into turbine purchase
agreements for the Devon and Middletown sites. NRG has issued
guarantees for payment on its proportionate share of the unpaid
amounts under each of these purchase agreements. Each of the
guarantees will remain in place until such time as GenConn has
obtained financing for each of the respective projects. As of
December 31, 2008, NRGs potential remaining
obligation under the guarantees is $54 million in the
aggregate.
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 maximum exposures range from $1 million to
$300 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 and affiliates do not limit the amount or duration
of its obligations to perform under them, there exists a risk
that the Company may have
214
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
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.
Note 26 Jointly
Owned Plants
Certain NRG subsidiaries own undivided interests in
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
|
Property, Plant &
|
|
|
Accumulated
|
|
|
Construction in
|
|
As of December 31,
2008
|
|
Interest
|
|
|
Equipment
|
|
|
Depreciation
|
|
|
Progress
|
|
|
|
(In millions unless otherwise stated)
|
|
|
South Texas Project Units 1 and 2, Bay City, TX
|
|
|
44.00
|
%
|
|
$
|
2,918
|
|
|
$
|
(503
|
)
|
|
$
|
34
|
|
Big Cajun II Unit 3, New Roads, LA
|
|
|
58.00
|
|
|
|
174
|
|
|
|
(48
|
)
|
|
|
10
|
|
Cedar Bayou Unit 4, Baytown, TX
|
|
|
50.00
|
|
|
|
|
|
|
|
|
|
|
|
185
|
|
Keystone, Shelocta, PA
|
|
|
3.70
|
|
|
|
61
|
|
|
|
(15
|
)
|
|
|
20
|
|
Conemaugh, New Florence, PA
|
|
|
3.72
|
|
|
|
74
|
|
|
|
(19
|
)
|
|
|
1
|
|
215
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
|
|
|
|
2008
|
|
|
|
|
|
|
September 30
|
|
|
|
|
|
|
|
|
|
December 31
|
|
|
(As revised)
|
|
|
June 30
|
|
|
March 31
|
|
|
|
(In millions, except per share data)
|
|
|
Operating revenues
|
|
$
|
1,655
|
|
|
$
|
2,612
|
|
|
$
|
1,316
|
|
|
$
|
1,302
|
|
Operating income
|
|
|
595
|
|
|
|
1,371
|
|
|
|
57
|
|
|
|
250
|
|
Income/(loss) from continuing operations, net of income taxes
|
|
|
273
|
|
|
|
734
|
|
|
|
(39
|
)
|
|
|
48
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
168
|
|
|
|
4
|
|
Net income
|
|
$
|
273
|
|
|
$
|
734
|
|
|
$
|
129
|
|
|
$
|
52
|
|
Weighted average number of common shares outstanding
basic
|
|
|
233
|
|
|
|
235
|
|
|
|
236
|
|
|
|
236
|
|
Income/(loss) from continuing operations per weighted average
common share basic
|
|
$
|
1.11
|
|
|
$
|
3.07
|
|
|
$
|
(0.22
|
)
|
|
$
|
0.14
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
|
|
|
|
|
|
|
|
0.71
|
|
|
|
0.02
|
|
Net income per weighted average common share basic
|
|
$
|
1.11
|
|
|
$
|
3.07
|
|
|
$
|
0.49
|
|
|
$
|
0.16
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
276
|
|
|
|
277
|
|
|
|
236
|
|
|
|
245
|
|
Income/(loss) from continuing operations per weighted average
common share diluted
|
|
$
|
0.98
|
|
|
$
|
2.65
|
|
|
$
|
(0.22
|
)
|
|
$
|
0.14
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
|
|
|
|
|
|
|
|
0.71
|
|
|
|
0.02
|
|
Net income per weighted average common share diluted
|
|
$
|
0.98
|
|
|
$
|
2.65
|
|
|
$
|
0.49
|
|
|
$
|
0.16
|
|
216
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
$
|
1.05
|
|
|
$
|
0.54
|
|
|
$
|
0.19
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
0.02
|
|
|
|
0.02
|
|
|
|
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
|
|
Subsequent to filing of NRGs Quarterly Report on
Form 10-Q
for the period ended September 30, 2008, the Company
identified a $78 million overstatement of revenues
resulting from an error in the accounting for energy options for
the three months ended September 30, 2008. There was no
impact to the Companys year-to-date cash flows or
liquidity position. The impact on the September 30, 2008
balance sheet was an understatement of the current derivative
instruments valuation of $35 million and other current
liabilities of $113 million. There was an insignificant
impact on the 2007 results and 2008 first and second quarter
statements of operations and thus, NRG is not revising the
revenues reported in these previously issued interim financial
statements. NRG determined that the revenue recognition practice
used prior to September 30, 2008 resulted in the
unintentional recognition of excess amortization of premiums
during the earlier portion of the option contract terms. This
excess was reversed upon termination of the options, resulting
in no net misstatement over the life of the option. The interim
periods however were subject to misstatement depending upon the
volume and timing of option execution.
Although not material to the previously filed financial
statements, the correction of the third quarter option revenue
during the fourth quarter would have understated the fourth
quarter operating revenues and income by
217
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
$78 million. Accordingly, in this
Form 10-K,
the unaudited quarterly financial data is revised for the
quarter ended September 30, 2008. The net impact is as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
|
September 30, 2008
|
|
|
|
As reported
|
|
|
Adjustment
|
|
|
As revised
|
|
|
Operating revenues
|
|
$
|
2,690
|
|
|
$
|
(78
|
)
|
|
$
|
2,612
|
|
Operating income
|
|
|
1,449
|
|
|
|
(78
|
)
|
|
|
1,371
|
|
Income from continuing operations, net of income taxes
|
|
|
784
|
|
|
|
(50
|
)
|
|
|
734
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
784
|
|
|
$
|
(50
|
)
|
|
$
|
734
|
|
Weighted average number of common shares outstanding
basic
|
|
|
235
|
|
|
|
|
|
|
|
235
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
3.28
|
|
|
$
|
(0.21
|
)
|
|
$
|
3.07
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per weighted average common share basic
|
|
$
|
3.28
|
|
|
$
|
(0.21
|
)
|
|
$
|
3.07
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
277
|
|
|
|
|
|
|
|
277
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
2.83
|
|
|
$
|
(0.18
|
)
|
|
$
|
2.65
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per weighted average common share diluted
|
|
$
|
2.83
|
|
|
$
|
(0.18
|
)
|
|
$
|
2.65
|
|
218
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
Note 28
|
Condensed
Consolidating Financial Information
|
As of December 31, 2008, 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, 2008:
|
|
|
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
|
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
|
219
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Continued)
|
|
|
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, 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.
220
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,504
|
|
|
$
|
405
|
|
|
$
|
|
|
|
$
|
(24
|
)
|
|
$
|
6,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,321
|
|
|
|
303
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
3,598
|
|
Depreciation and amortization
|
|
|
618
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
General and administrative
|
|
|
64
|
|
|
|
14
|
|
|
|
241
|
|
|
|
|
|
|
|
319
|
|
Development costs
|
|
|
(1
|
)
|
|
|
7
|
|
|
|
40
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,002
|
|
|
|
351
|
|
|
|
285
|
|
|
|
(26
|
)
|
|
|
4,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
2,502
|
|
|
|
54
|
|
|
|
(285
|
)
|
|
|
2
|
|
|
|
2,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
276
|
|
|
|
|
|
|
|
1,601
|
|
|
|
(1,877
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
(2
|
)
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
Other income/(expense), net
|
|
|
23
|
|
|
|
11
|
|
|
|
(15
|
)
|
|
|
(2
|
)
|
|
|
17
|
|
Interest expense
|
|
|
(183
|
)
|
|
|
(114
|
)
|
|
|
(323
|
)
|
|
|
|
|
|
|
(620
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
114
|
|
|
|
(42
|
)
|
|
|
1,263
|
|
|
|
(1,879
|
)
|
|
|
(544
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
2,616
|
|
|
|
12
|
|
|
|
978
|
|
|
|
(1,877
|
)
|
|
|
1,729
|
|
Income tax expense/(benefit)
|
|
|
1,001
|
|
|
|
19
|
|
|
|
(307
|
)
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
1,615
|
|
|
|
(7
|
)
|
|
|
1,285
|
|
|
|
(1,877
|
)
|
|
|
1,016
|
|
Income(loss) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
269
|
|
|
|
(97
|
)
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
1,615
|
|
|
$
|
262
|
|
|
$
|
1,188
|
|
|
$
|
(1,877
|
)
|
|
$
|
1,188
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
221
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING BALANCE SHEETS
December 31,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
(2
|
)
|
|
$
|
159
|
|
|
$
|
1,337
|
|
|
$
|
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
|
|
|
|
|
|
|
|
754
|
|
|
|
|
|
|
|
754
|
|
Restricted cash
|
|
|
7
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Accounts receivable-trade, net
|
|
|
422
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
464
|
|
Inventory
|
|
|
443
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
455
|
|
Derivative instruments valuation
|
|
|
4,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,600
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
494
|
|
Prepayments and other current assets
|
|
|
130
|
|
|
|
37
|
|
|
|
278
|
|
|
|
(230
|
)
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
6,094
|
|
|
|
259
|
|
|
|
2,369
|
|
|
|
(230
|
)
|
|
|
8,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
10,725
|
|
|
|
791
|
|
|
|
29
|
|
|
|
|
|
|
|
11,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
651
|
|
|
|
18
|
|
|
|
11,941
|
|
|
|
(12,610
|
)
|
|
|
|
|
Equity investments in affiliates
|
|
|
26
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
490
|
|
Capital leases and note receivable, less current portion
|
|
|
598
|
|
|
|
435
|
|
|
|
3,177
|
|
|
|
(3,775
|
)
|
|
|
435
|
|
Goodwill
|
|
|
1,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,718
|
|
Intangible assets, net
|
|
|
797
|
|
|
|
16
|
|
|
|
2
|
|
|
|
|
|
|
|
815
|
|
Nuclear decommissioning trust fund
|
|
|
303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
303
|
|
Derivative instruments valuation
|
|
|
870
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
885
|
|
Other non-current assets
|
|
|
9
|
|
|
|
4
|
|
|
|
112
|
|
|
|
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
4,972
|
|
|
|
937
|
|
|
|
15,247
|
|
|
|
(16,385
|
)
|
|
|
4,771
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
21,791
|
|
|
$
|
1,987
|
|
|
$
|
17,645
|
|
|
$
|
(16,615
|
)
|
|
$
|
24,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
67
|
|
|
$
|
235
|
|
|
$
|
229
|
|
|
$
|
(67
|
)
|
|
$
|
464
|
|
Accounts payable trade
|
|
|
(1,302
|
)
|
|
|
429
|
|
|
|
1,324
|
|
|
|
|
|
|
|
451
|
|
Derivative instruments valuation
|
|
|
3,976
|
|
|
|
3
|
|
|
|
2
|
|
|
|
|
|
|
|
3,981
|
|
Deferred income taxes
|
|
|
503
|
|
|
|
31
|
|
|
|
(333
|
)
|
|
|
|
|
|
|
201
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
760
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
760
|
|
Accrued expenses and other current liabilities
|
|
|
507
|
|
|
|
48
|
|
|
|
333
|
|
|
|
(164
|
)
|
|
|
724
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
4,511
|
|
|
|
746
|
|
|
|
1,555
|
|
|
|
(231
|
)
|
|
|
6,581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
2,730
|
|
|
|
1,021
|
|
|
|
7,728
|
|
|
|
(3,775
|
)
|
|
|
7,704
|
|
Nuclear decommissioning reserve
|
|
|
284
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
284
|
|
Nuclear decommissioning trust liability
|
|
|
218
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218
|
|
Deferred income taxes
|
|
|
705
|
|
|
|
(187
|
)
|
|
|
672
|
|
|
|
|
|
|
|
1,190
|
|
Derivative instruments valuation
|
|
|
348
|
|
|
|
46
|
|
|
|
114
|
|
|
|
|
|
|
|
508
|
|
Out-of-market contracts
|
|
|
291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
291
|
|
Other non-current liabilities
|
|
|
405
|
|
|
|
44
|
|
|
|
220
|
|
|
|
|
|
|
|
669
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
4,981
|
|
|
|
924
|
|
|
|
8,734
|
|
|
|
(3,775
|
)
|
|
|
10,864
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
9,492
|
|
|
|
1,670
|
|
|
|
10,289
|
|
|
|
(4,006
|
)
|
|
|
17,445
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minority Interest
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
247
|
|
Stockholders Equity
|
|
|
12,292
|
|
|
|
317
|
|
|
|
7,109
|
|
|
|
(12,609
|
)
|
|
|
7,109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
21,791
|
|
|
$
|
1,987
|
|
|
$
|
17,645
|
|
|
$
|
(16,615
|
)
|
|
$
|
24,808
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
222
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Energy,
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,615
|
|
|
$
|
262
|
|
|
$
|
1,188
|
|
|
$
|
(1,877
|
)
|
|
$
|
1,188
|
|
Adjustments to reconcile net income to net cash provided by
operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions in excess/(less than) equity in earnings of
unconsolidated affiliates
|
|
|
(274
|
)
|
|
|
(46
|
)
|
|
|
(1,601
|
)
|
|
|
1,877
|
|
|
|
(44
|
)
|
Depreciation and amortization
|
|
|
618
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
Amortization of nuclear fuel
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
Amortization and write-off of deferred financing costs and debt
discount/premiums
|
|
|
|
|
|
|
7
|
|
|
|
22
|
|
|
|
|
|
|
|
29
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(270
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
Loss on disposals and sales of assets
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
Impairment charges and asset write downs
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
23
|
|
Changes in derivatives
|
|
|
(482
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
(484
|
)
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
312
|
|
|
|
(16
|
)
|
|
|
466
|
|
|
|
|
|
|
|
762
|
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
Gain on sale of emission allowances
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(417
|
)
|
Cash provided/(used) by changes in other working capital, net of
disposition affects
|
|
|
745
|
|
|
|
88
|
|
|
|
(635
|
)
|
|
|
|
|
|
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
1,894
|
|
|
|
47
|
|
|
|
(507
|
)
|
|
|
|
|
|
|
1,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
(238
|
)
|
|
|
|
|
|
|
696
|
|
|
|
(458
|
)
|
|
|
|
|
Capital expenditures
|
|
|
(597
|
)
|
|
|
(294
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
(899
|
)
|
Decrease in restricted cash
|
|
|
(6
|
)
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
45
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
10
|
|
Purchases of emission allowances
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
Proceeds from sale of emission allowances
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(616
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(616
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
582
|
|
Proceeds from sale of assets
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Equity investment in unconsolidated affiliate
|
|
|
|
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
(84
|
)
|
Proceeds from sale of discontinued operations, net of cash
divested
|
|
|
|
|
|
|
(59
|
)
|
|
|
300
|
|
|
|
|
|
|
|
241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
(794
|
)
|
|
|
(373
|
)
|
|
|
953
|
|
|
|
(458
|
)
|
|
|
(672
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans
|
|
|
(1,059
|
)
|
|
|
315
|
|
|
|
286
|
|
|
|
458
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
(55
|
)
|
Payment of financing element of acquired derivatives
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
(185
|
)
|
Proceeds from sale of minority interest in subsidiary
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(4
|
)
|
Payments of short and long-term debt
|
|
|
|
|
|
|
(60
|
)
|
|
|
(174
|
)
|
|
|
|
|
|
|
(234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(1,102
|
)
|
|
|
323
|
|
|
|
(121
|
)
|
|
|
458
|
|
|
|
(442
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
(2
|
)
|
|
|
39
|
|
|
|
325
|
|
|
|
|
|
|
|
362
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
|
|
|
|
120
|
|
|
|
1,012
|
|
|
|
|
|
|
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
(2
|
)
|
|
$
|
159
|
|
|
$
|
1,337
|
|
|
$
|
|
|
|
$
|
1,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
223
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
|
|
|
3,130
|
|
|
|
248
|
|
|
|
|
|
|
|
|
|
|
|
3,378
|
|
Depreciation and amortization
|
|
|
630
|
|
|
|
24
|
|
|
|
4
|
|
|
|
|
|
|
|
658
|
|
General and administrative
|
|
|
102
|
|
|
|
18
|
|
|
|
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.
|
224
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
|
|
$
|
|
|
|
$
|
120
|
|
|
$
|
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
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85
|
|
Prepayments and other current assets
|
|
|
97
|
|
|
|
34
|
|
|
|
195
|
|
|
|
(152
|
)
|
|
|
174
|
|
Current assets discontinued operations
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
51
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
2,240
|
|
|
|
264
|
|
|
|
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
|
|
Capital leases and notes receivable, less current portion
|
|
|
360
|
|
|
|
491
|
|
|
|
3,779
|
|
|
|
(4,139
|
)
|
|
|
491
|
|
Goodwill
|
|
|
1,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,786
|
|
Intangible assets, net
|
|
|
859
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
873
|
|
Nuclear decommissioning trust fund
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384
|
|
Derivative instruments valuation
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150
|
|
Other non-current assets
|
|
|
25
|
|
|
|
1
|
|
|
|
164
|
|
|
|
|
|
|
|
190
|
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
4,202
|
|
|
|
996
|
|
|
|
13,730
|
|
|
|
(14,536
|
)
|
|
|
4,392
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
17,270
|
|
|
$
|
1,730
|
|
|
$
|
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
|
|
|
(695
|
)
|
|
|
348
|
|
|
|
731
|
|
|
|
|
|
|
|
384
|
|
Derivative instruments valuation
|
|
|
916
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
917
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Accrued expenses and other current liabilities
|
|
|
321
|
|
|
|
62
|
|
|
|
145
|
|
|
|
(69
|
)
|
|
|
459
|
|
Current liabilities discontinued operations
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
639
|
|
|
|
730
|
|
|
|
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
|
|
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
|
|
|
7,338
|
|
|
|
1,265
|
|
|
|
9,211
|
|
|
|
(4,291
|
)
|
|
|
13,523
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
247
|
|
Stockholders Equity
|
|
|
9,932
|
|
|
|
465
|
|
|
|
5,504
|
|
|
|
(10,397
|
)
|
|
|
5,504
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
17,270
|
|
|
$
|
1,730
|
|
|
$
|
14,962
|
|
|
$
|
(14,688
|
)
|
|
$
|
19,274
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
225
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, 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
|
|
|
630
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
661
|
|
Amortization of nuclear fuel
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
|
|
Amortization and write-off 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
|
|
|
218
|
|
|
|
96
|
|
|
|
(305
|
)
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
1,992
|
|
|
|
166
|
|
|
|
(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 assets
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Purchase of securities
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
(49
|
)
|
Proceeds from sale of discontinued operations and assets, net of
cash divested
|
|
|
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, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
(20
|
)
|
|
|
(294
|
)
|
|
|
669
|
|
|
|
|
|
|
|
355
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
20
|
|
|
|
414
|
|
|
|
343
|
|
|
|
|
|
|
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
|
|
|
$
|
120
|
|
|
$
|
1,012
|
|
|
$
|
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
226
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
|
|
|
3,038
|
|
|
|
225
|
|
|
|
2
|
|
|
|
|
|
|
|
3,265
|
|
Depreciation and amortization
|
|
|
562
|
|
|
|
23
|
|
|
|
5
|
|
|
|
|
|
|
|
590
|
|
General and administrative
|
|
|
82
|
|
|
|
14
|
|
|
|
180
|
|
|
|
|
|
|
|
276
|
|
Development costs
|
|
|
32
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,714
|
|
|
|
262
|
|
|
|
191
|
|
|
|
|
|
|
|
4,167
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,568
|
|
|
|
41
|
|
|
|
(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
|
|
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
|
|
|
1,487
|
|
|
|
171
|
|
|
|
337
|
|
|
|
(1,130
|
)
|
|
|
865
|
|
Income tax expense
|
|
|
549
|
|
|
|
42
|
|
|
|
(269
|
)
|
|
|
|
|
|
|
322
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
938
|
|
|
|
129
|
|
|
|
606
|
|
|
|
(1,130
|
)
|
|
|
543
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
63
|
|
|
|
15
|
|
|
|
|
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
938
|
|
|
$
|
192
|
|
|
$
|
621
|
|
|
$
|
(1,130
|
)
|
|
$
|
621
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
227
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year
Ended December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
938
|
|
|
$
|
192
|
|
|
$
|
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/(used) by changes in other working capital, net of
acquisition and disposition affects
|
|
|
(557
|
)
|
|
|
216
|
|
|
|
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, 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.
|
228
NRG
ENERGY, INC.
SCHEDULE
II. VALUATION AND QUALIFYING ACCOUNTS
For the
Years Ended December 31, 2008, 2007, and 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
|
Charged to
|
|
|
Charged to
|
|
|
|
|
|
|
|
|
|
Beginning of
|
|
|
Costs and
|
|
|
Other
|
|
|
Additions/
|
|
|
Balance at
|
|
|
|
Period
|
|
|
Expenses
|
|
|
Accounts
|
|
|
(Deductions)
|
|
|
End of Period
|
|
|
|
(In millions)
|
|
|
Allowance for doubtful accounts, deducted from accounts
receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2008
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3
|
|
Year ended December 31, 2007
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1
|
|
Year ended December 31, 2006
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1
|
)
|
|
$
|
1
|
|
Income tax valuation allowance, deducted from deferred tax
assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2008
|
|
$
|
539
|
|
|
$
|
(12
|
)
|
|
$
|
(6
|
)
|
|
$
|
(162
|
)
|
|
$
|
359
|
|
Year ended December 31, 2007
|
|
$
|
581
|
|
|
$
|
6
|
|
|
$
|
8
|
|
|
$
|
(56
|
)
|
|
$
|
539
|
|
Year ended December 31, 2006
|
|
$
|
836
|
|
|
$
|
(10
|
)
|
|
$
|
(81
|
)
|
|
$
|
(164
|
)
|
|
$
|
581
|
|
229
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)
Clint C. Freeland
Chief Financial Officer
(Principal Financial Officer)
James J. Ingoldsby
Chief Accounting Officer
(Principal Accounting Officer)
Date: February 12, 2009
230
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 12, 2009.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ David
W. Crane
David
W. Crane
|
|
President, Chief Executive Officer and Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Howard
E. Cosgrove
Howard
E. Cosgrove
|
|
Chairman of the Board
|
|
February 12, 2009
|
|
|
|
|
|
/s/ John
F. Chlebowski
John
F. Chlebowski
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Lawrence
S. Coben
Lawrence
S. Coben
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Stephen
L. Cropper
Stephen
L. Cropper
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ William
E. Hantke
William
E. Hantke
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Paul
W. Hobby
Paul
W. Hobby
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Kathleen
A. McGinty
Kathleen
A. McGinty
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Anne
C. Schaumburg
Anne
C. Schaumburg
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Herbert
H. Tate
Herbert
H. Tate
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Thomas
H. Weidemeyer
Thomas
H. Weidemeyer
|
|
Director
|
|
February 12, 2009
|
|
|
|
|
|
/s/ Walter
R. Young
Walter
R. Young
|
|
Director
|
|
February 12, 2009
|
231
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.(35)
|
|
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 Amendment to 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 February 27,
2008.(36)
|
|
3
|
.8
|
|
Second Certificate of Amendment to 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 8, 2008.(37)
|
|
3
|
.9
|
|
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)
|
232
|
|
|
|
|
|
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)
|
|
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)
|
233
|
|
|
|
|
|
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)
|
|
10
|
.8*
|
|
Annual Incentive Plan for Designated Corporate Officers.(9)
|
|
10
|
.9
|
|
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)
|
|
10
|
.10
|
|
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
|
.11
|
|
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
|
.12
|
|
Stock Purchase Agreement, dated as of August 10, 2005, by
and between NRG Energy, Inc. and Credit Suisse First Boston
Capital LLC.(17)
|
|
10
|
.13
|
|
Agreement with respect to the Stock Purchase Agreement, dated
December 19, 2008, by and between NRG Energy, Inc. and
Credit Suisse First Boston Capital LLC.(1)
|
|
10
|
.14
|
|
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
|
.15
|
|
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).(25)
|
|
10
|
.16*
|
|
Amended and Restated Employment Agreement, dated
December 4, 2008, between NRG Energy, Inc. and David
Crane.(1)
|
|
10
|
.17*
|
|
CFO Compensation Table.(38)
|
|
10
|
.18
|
|
Limited Liability Company Agreement of NRG Common Stock Finance
I LLC.(27)
|
|
10
|
.19
|
|
Limited Liability Company Agreement of NRG Common Stock
Finance II LLC.(27)
|
|
10
|
.20
|
|
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
|
.21
|
|
Amendment Agreement, dated February 27, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(36)
|
|
10
|
.22
|
|
Amendment Agreement, dated August 8, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(37)
|
|
10
|
.23
|
|
Amendment Agreement, dated December 19, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(1)
|
|
10
|
.24
|
|
Agreement with respect to Note Purchase Agreement, dated
December 19, 2008, by and among NRG Common Stock Finance I
LLC, Credit Suisse International, and Credit Suisse Securities
(USA) LLC.(1)
|
|
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
|
|
Amendment Agreement, dated December 19, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance II
LLC, Credit Suisse International, and Credit Suisse Securities
(USA) LLC.(1)
|
|
10
|
.27
|
|
Agreement with respect to Note Purchase Agreement, dated
December 19, 2008, by and among NRG Common Stock
Finance II LLC, Credit Suisse International, and Credit
Suisse Securities (USA) LLC.(1)
|
|
10
|
.28
|
|
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
|
.29
|
|
Preferred Interest Amendment Agreement, dated February 27,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(36)
|
|
10
|
.30
|
|
Preferred Interest Amendment Agreement, dated August 8,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(37)
|
|
10
|
.31
|
|
Preferred Interest Amendment Agreement, dated December 19,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(1)
|
234
|
|
|
|
|
|
10
|
.32
|
|
Agreement with respect to Preferred Interest Purchase Agreement,
dated December 19, 2008, by and among NRG Common Stock
Finance I LLC, Credit Suisse International, and Credit Suisse
Securities (USA) LLC.(1)
|
|
10
|
.33
|
|
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
|
.34
|
|
Preferred Interest Amendment Agreement, dated December 19,
2008, by and among NRG Common Stock Finance II LLC, Credit
Suisse International, and Credit Suisse Securities (USA) LLC.(1)
|
|
10
|
.35
|
|
Agreement with respect to Preferred Interest Purchase Agreement,
dated December 19, 2008, by and among NRG Common Stock
Finance II LLC, Credit Suisse International, and Credit
Suisse Securities (USA) LLC.(1)
|
|
10
|
.36
|
|
Common Interest Purchase Agreement, dated August 4, 2006,
between NRG Energy, Inc. and NRG Common Stock Finance I LLC.(27)
|
|
10
|
.37
|
|
Common Interest Purchase Agreement, dated August 4, 2006,
between NRG Energy, Inc. and NRG Common Stock Finance II
LLC.(27)
|
|
10
|
.38
|
|
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
|
.39*
|
|
Amended and Restated Long-Term Incentive Plan, dated
December 8, 2006.(31)
|
|
10
|
.40*
|
|
NRG Energy, Inc. Executive
Change-in-Control
and General Severance Agreement, dated December 9, 2008.(1)
|
|
10
|
.41
|
|
Amended and Restated Contribution Agreement (NRG), dated
March 25, 2008, by and among Texas Genco Holdings, Inc.,
NRG South Texas LP and NRG Nuclear Development Company LLC and
Certain Subsidiaries Thereof.(36)
|
|
10
|
.42
|
|
Contribution Agreement (Toshiba), dated February 29, 2008,
by and between Toshiba Corporation and NRG Nuclear Development
Company LLC.(36)
|
|
10
|
.43
|
|
Multi-Unit
Agreement, dated February 29, 2008, by and among Toshiba
Corporation, NRG Nuclear Development Company LLC and NRG Energy,
Inc.(36)
|
|
10
|
.44
|
|
Amended and Restated Operating Agreement of Nuclear Innovation
North America LLC, dated May 1, 2008(36)
|
|
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)
|
|
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 Clint C. Freeland.(1)
|
|
31
|
.3
|
|
Rule 13a-14(a)/15d-14(a)
certification of James J. Ingoldsby.(1)
|
|
32
|
|
|
Section 1350 Certification.(1)
|
|
|
|
* |
|
Exhibit relates to compensation arrangements. |
|
|
|
Portions of this exhibit have been redacted and are subject to a
confidential treatment request filed with the Secretary of the
Securities and Exchange Commission pursuant to
Rule 24b-2
under the Securities Exchange Act of 1934, as amended. |
|
(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. |
235
|
|
|
(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. |
|
(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. |
|
(35) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on February 28, 2008. |
|
(36) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on May 1, 2008. |
|
(37) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on October 30, 2008. |
|
(38) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 9, 2008. |
236