FORM 10-Q
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-Q
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þ
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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o
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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 quarterly period ended:
September 30, 2008
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Commission File Number:
001-15891
NRG Energy, Inc.
(Exact name of Registrant as
specified in its charter)
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Delaware
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41-1724239
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(State or other jurisdiction
of
incorporation or organization)
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(I.R.S. Employer
Identification No.)
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211 Carnegie Center Princeton,
New Jersey
(Address of principal
executive offices)
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08540
(Zip Code)
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(609) 524-4500
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such 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 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)
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Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act).
Yes o
No þ
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 and Exchange Act of 1934
subsequent to the distribution of securities under a plan
confirmed by a
court.
Yes þ No o
As of October 23, 2008, there were 233,047,222 shares
of common stock outstanding, par value $0.01 per share.
TABLE OF
CONTENTS
Index
2
CAUTIONARY
STATEMENT REGARDING FORWARD LOOKING INFORMATION
This Quarterly Report on
Form 10-Q
includes forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of
the Exchange Act. The words believes,
projects, anticipates,
plans, expects, intends,
estimates and similar expressions are intended to
identify forward-looking statements. These forward-looking
statements involve known and unknown risks, uncertainties and
other factors which may cause NRGs 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 Part I,
Item 1A, of the Companys Annual Report on
Form 10-K,
for the year ended December 31, 2007, including 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 independent system operators, or ISOs, or regional
transmission organizations, or RTOs, that result in a failure to
adequately compensate NRGs generation units for all of its
costs;
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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
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NRGs ability to achieve its strategy of regularly
returning capital to shareholders.
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Forward-looking statements speak only as of the date they were
made, and NRG 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 Quarterly Report on
Form 10-Q
should not be construed as exhaustive.
3
GLOSSARY
OF TERMS
When the following terms and abbreviations appear in the text of
this report, they have the meanings indicated below:
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Acquisition |
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February 2, 2006 acquisition of Texas Genco LLC, now
referred to as the Companys Texas region |
ABWR |
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Advanced Boiling Water Reactor |
ANPR |
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Advanced Notice of Proposed Rulemaking |
ARO |
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Asset Retirement Obligation |
BACT |
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Best Available Control Technology |
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 |
BP |
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BP Alternative Energy North America Inc. |
BTU |
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British Thermal Unit |
CAA |
|
Clean Air Act |
CAIR |
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Clean Air Interstate Rule |
CAMR |
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Clean Air Mercury Rule |
CDWR |
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California Department of Water Resources |
CL&P |
|
Connecticut Light & Power |
CO2 |
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Carbon dioxide |
COLA |
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Combined Operating License Application |
CS |
|
Credit Suisse Group |
CSF I |
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NRG Common Stock Finance I LLC |
CSF II |
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NRG Common Stock Finance II LLC |
DNREC |
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Delaware Department of Natural Resources |
DPUC |
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Connecticut Department of Public Utility Control |
EFOR |
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Equivalent Forced Outage Rates considers the
equivalent impact that forced de-ratings have in addition to
full forced outages |
EPC |
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Engineering, Procurement and Construction |
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 |
ESPP |
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Employee Stock Purchase Plan |
Exchange Act |
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The Securities Exchange Act of 1934, as amended |
FASB |
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Financial Accounting Standards Board, the designated
organization for establishing standards for financial accounting
and reporting |
FCM |
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Forward Capacity Market |
FERC |
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Federal Energy Regulatory Commission |
FIN |
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FASB Interpretation |
FIN 48 |
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FIN 48, Accounting for Uncertainty in Income Taxes |
FSP |
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FASB Staff Position |
GHG |
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Greenhouse Gases |
IGCC |
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Integrated Gasification Combined Cycle |
ISO |
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Independent System Operator, also referred to as Regional
Transmission Organization, or RTO |
ISO-NE |
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ISO New England, Inc. |
ITISA |
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Itiquira Energetica S.A. |
kW |
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Kilowatts |
kWh |
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Kilowatt-hours |
LFRM |
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Locational Forward Reserve Market |
LIBOR |
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London Inter-Bank Offer Rate |
LMP |
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Locational Marginal Prices |
LTIP |
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Long-Term Incentive Plan |
MACT |
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Maximum Achievable Control Technology |
Merit Order |
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A term used for the ranking of power stations in terms of
increasing order of fuel costs |
MMBtu |
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Million British Thermal Units |
MOU |
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Memorandum of Understanding |
4
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GLOSSARY OF TERMS (contd) |
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MRTU |
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Market Redesign and Technology Upgrade |
MW |
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Megawatts |
MWh |
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Saleable megawatt hours net of internal/parasitic load
megawatt-hours |
NAAQS |
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National Ambient Air Quality Standard |
NEPOOL |
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New England Power Pool |
Net Exposure |
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Counterparty credit exposure to NRG, net of collateral |
NiMo |
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Niagara Mohawk Power Corporation |
NINA |
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Nuclear Innovation North America LLC |
NOx |
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Nitrogen oxide |
NOL |
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Net Operating Loss |
NOV |
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Notice of Violation |
NPNS |
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Normal Purchase Normal Sale |
NRC |
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Nuclear Regulatory Commission |
NYISO |
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New York Independent System Operator |
NYPA |
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New York Power Authority |
OCI |
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Other Comprehensive Income |
Phase II 316(b) Rule |
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A section of the Clean Water Act regulating cooling water intake
structures |
PJM |
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PJM Interconnection LLC |
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 |
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 |
PPA |
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Power Purchase Agreement |
PPM |
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Parts per Million |
PSD |
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Prevention of Significant Deterioration |
PUCT |
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The Public Utility Commission of Texas |
Repowering |
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Replacing, rebuilding, or redeveloping 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 |
RepoweringNRG |
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NRGs program designed to develop, finance, construct and
operate new, highly efficient, environmentally responsible
capacity over the next decade |
Revolving Credit Facility |
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NRGs $1 billion senior secured credit facility which
matures on February 2, 2011 |
RGGI |
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Regional Greenhouse Gas Initiative |
RMR |
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Reliability Must-Run |
RPM |
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Reliability Pricing Model term for capacity market
in PJM market |
RTO |
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Regional Transmission Organization, also referred to as an
Independent System Operator, or ISO |
Sarbanes-Oxley |
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Sarbanes-Oxley Act of 2002 |
SEC |
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United States Securities and Exchange Commission |
Securities Act |
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The Securities Act of 1933, as amended |
Senior Credit Facility |
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NRGs senior secured facility, which is comprised of a Term
B loan facility and a $1.3 billion Letter of Credit
Facility which mature on February 1, 2013, and a
$1 billion Revolving Credit Facility, which matures on
February 2, 2011 |
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 |
SFAS |
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Statement of Financial Accounting Standards issued by the FASB |
SFAS 109 |
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SFAS No. 109, Accounting for Income
Taxes |
SFAS 133 |
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SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities |
SFAS 141R |
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SFAS No. 141 (revised 2007), Business
Combinations |
SFAS 157 |
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SFAS No. 157, Fair Value
Measurements |
5
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GLOSSARY OF TERMS (contd) |
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SFAS 160 |
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SFAS No. 160, Noncontrolling Interest in
Consolidated Financial Statements |
SFAS 161 |
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SFAS No. 161, Disclosure about Derivative
Instruments and Hedging Activities an amendment of
FASB Statement No. 133 |
Sherbino |
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Sherbino I Wind Farm LLC |
SO2 |
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Sulfur dioxide |
SOP |
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Statement of Position issued by the American Institute of
Certified Public Accountants |
STP |
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South Texas Project Nuclear generating facility
located near Bay City, Texas in which NRG owns a 44% interest |
STPNOC |
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South Texas Project Nuclear Operating Company |
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 |
Term B loan |
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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 |
Texas Genco |
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Texas Genco LLC, now referred to as the Companys Texas
region |
Texas West |
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The West Zone of Texas ERCOT power market |
Tosli |
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Tosli Acquisition B.V. |
US |
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United States of America |
USEPA |
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United States Environmental Protection Agency |
US GAAP |
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Accounting principles generally accepted in the United States |
VAR |
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Value at Risk |
WCP |
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WCP (Generation) Holdings, LLC |
6
PART I
FINANCIAL INFORMATION
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ITEM 1
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CONDENSED
CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
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NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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Three Months Ended September 30
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Nine Months Ended September 30
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(In millions, except for per share amounts)
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2008
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2007
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2008
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2007
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Operating Revenues
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Total operating revenues
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$
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2,690
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$
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1,772
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$
|
5,308
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$
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4,607
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Operating Costs and Expenses
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Cost of operations
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|
997
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|
939
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2,812
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|
2,560
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Depreciation and amortization
|
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|
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|
156
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|
|
|
160
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|
|
|
478
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|
|
|
481
|
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General and administrative
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75
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|
78
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233
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234
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Development costs
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13
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49
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29
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108
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Total operating costs and expenses
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1,241
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1,226
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3,552
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3,383
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Gain on sale of assets
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16
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Operating Income
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1,449
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|
|
|
546
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|
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1,756
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1,240
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Other Income/(Expense)
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Equity in earnings of unconsolidated affiliates
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58
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19
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35
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40
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Other (loss)/income, net
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(7
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)
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14
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14
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44
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Refinancing expense
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(35
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)
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Interest expense
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(186
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)
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(169
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)
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(481
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)
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(520
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)
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Total other expense
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(135
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)
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(136
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)
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(432
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)
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(471
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)
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Income From Continuing Operations Before Income Taxes
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1,314
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|
|
410
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1,324
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|
769
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|
|
|
Income tax expense
|
|
|
|
|
530
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|
|
|
145
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|
|
|
531
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|
|
|
300
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|
|
|
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|
Income From Continuing Operations
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|
|
|
|
784
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|
|
|
265
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|
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|
793
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|
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469
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Income from discontinued operations, net of income tax expense
|
|
|
|
|
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|
|
|
3
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|
|
|
172
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|
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|
13
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|
|
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Net Income
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|
|
784
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|
|
|
268
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|
|
965
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|
|
|
482
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|
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|
Dividends for preferred shares
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|
|
|
|
13
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|
|
|
13
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|
41
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|
|
|
41
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|
|
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|
Income Available for Common Stockholders
|
|
|
|
$
|
771
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|
|
$
|
255
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|
|
$
|
924
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|
|
$
|
441
|
|
|
|
Weighted average number of common shares outstanding
basic
|
|
|
|
|
235
|
|
|
|
239
|
|
|
|
236
|
|
|
|
241
|
|
|
|
Income from continuing operations per weighted average common
share basic
|
|
|
|
$
|
3.28
|
|
|
$
|
1.05
|
|
|
$
|
3.19
|
|
|
$
|
1.78
|
|
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
|
|
|
|
|
|
0.02
|
|
|
|
0.73
|
|
|
|
0.05
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Basic
|
|
|
|
$
|
3.28
|
|
|
$
|
1.07
|
|
|
$
|
3.92
|
|
|
$
|
1.83
|
|
|
|
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
|
|
277
|
|
|
|
285
|
|
|
|
278
|
|
|
|
287
|
|
|
|
Income from continuing operations per weighted average common
share diluted
|
|
|
|
$
|
2.83
|
|
|
$
|
0.92
|
|
|
$
|
2.83
|
|
|
$
|
1.61
|
|
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
|
|
|
|
|
|
0.01
|
|
|
|
0.62
|
|
|
|
0.05
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Diluted
|
|
|
|
$
|
2.83
|
|
|
$
|
0.93
|
|
|
$
|
3.45
|
|
|
$
|
1.66
|
|
|
|
|
|
See notes to condensed consolidated financial statements.
7
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
December 31, 2007
|
|
|
|
|
|
(In millions, except
shares)
|
|
(unaudited)
|
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,483
|
|
|
$
|
1,132
|
|
Restricted cash
|
|
|
32
|
|
|
|
29
|
|
Accounts receivable, less allowance for doubtful accounts of $3
and $1, respectively
|
|
|
531
|
|
|
|
482
|
|
Inventory
|
|
|
456
|
|
|
|
451
|
|
Derivative instruments valuation
|
|
|
4,190
|
|
|
|
1,034
|
|
Deferred income taxes
|
|
|
|
|
|
|
124
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
544
|
|
|
|
85
|
|
Prepayments and other current assets
|
|
|
203
|
|
|
|
174
|
|
Current assets discontinued operations
|
|
|
|
|
|
|
51
|
|
|
|
Total current assets
|
|
|
7,439
|
|
|
|
3,562
|
|
|
|
Property, plant and equipment, net of accumulated
depreciation of $2,184 and $1,695, respectively
|
|
|
11,472
|
|
|
|
11,320
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
428
|
|
|
|
425
|
|
Notes receivable and capital lease, less current portion
|
|
|
450
|
|
|
|
491
|
|
Goodwill
|
|
|
1,786
|
|
|
|
1,786
|
|
Intangible assets, net of accumulated amortization of $425 and
$372, respectively
|
|
|
822
|
|
|
|
873
|
|
Nuclear decommissioning trust fund
|
|
|
333
|
|
|
|
384
|
|
Derivative instruments valuation
|
|
|
816
|
|
|
|
150
|
|
Other non-current assets
|
|
|
134
|
|
|
|
176
|
|
Intangible assets held-for-sale
|
|
|
3
|
|
|
|
14
|
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
93
|
|
|
|
Total other assets
|
|
|
4,772
|
|
|
|
4,392
|
|
|
|
Total Assets
|
|
$
|
23,683
|
|
|
$
|
19,274
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
122
|
|
|
$
|
466
|
|
Accounts payable
|
|
|
367
|
|
|
|
384
|
|
Derivative instruments valuation
|
|
|
4,022
|
|
|
|
917
|
|
Deferred income taxes
|
|
|
16
|
|
|
|
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
154
|
|
|
|
14
|
|
Accrued expenses and other current liabilities
|
|
|
629
|
|
|
|
459
|
|
Current liabilities discontinued operations
|
|
|
|
|
|
|
37
|
|
|
|
Total current liabilities
|
|
|
5,310
|
|
|
|
2,277
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
8,059
|
|
|
|
7,895
|
|
Nuclear decommissioning reserve
|
|
|
320
|
|
|
|
307
|
|
Nuclear decommissioning trust liability
|
|
|
252
|
|
|
|
326
|
|
Deferred income taxes
|
|
|
1,083
|
|
|
|
843
|
|
Derivative instruments valuation
|
|
|
1,158
|
|
|
|
759
|
|
Out-of-market contracts
|
|
|
336
|
|
|
|
628
|
|
Other non-current liabilities
|
|
|
568
|
|
|
|
412
|
|
Non-current liabilities discontinued operations
|
|
|
|
|
|
|
76
|
|
|
|
Total non-current liabilities
|
|
|
11,776
|
|
|
|
11,246
|
|
|
|
Total Liabilities
|
|
|
17,086
|
|
|
|
13,523
|
|
|
|
Minority interest
|
|
|
7
|
|
|
|
|
|
3.625% convertible perpetual preferred stock (at liquidation
value, net of issuance costs)
|
|
|
247
|
|
|
|
247
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
Preferred stock (at liquidation value, net of issuance costs)
|
|
|
892
|
|
|
|
892
|
|
Common stock
|
|
|
3
|
|
|
|
3
|
|
Additional paid-in capital
|
|
|
4,135
|
|
|
|
4,092
|
|
Retained earnings
|
|
|
2,194
|
|
|
|
1,270
|
|
Less treasury stock, at cost 29,242,483 and
24,550,600 shares, respectively
|
|
|
(823
|
)
|
|
|
(638
|
)
|
Accumulated other comprehensive loss
|
|
|
(58
|
)
|
|
|
(115
|
)
|
|
|
Total Stockholders Equity
|
|
|
6,343
|
|
|
|
5,504
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
23,683
|
|
|
$
|
19,274
|
|
|
|
See notes to condensed consolidated financial statements.
8
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2008
|
|
|
2007
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
965
|
|
|
$
|
482
|
|
Adjustments to reconcile net income to net cash provided by
operating activities Distributions and equity in (earnings) of
unconsolidated affiliates
|
|
|
(24
|
)
|
|
|
(23
|
)
|
Depreciation and amortization
|
|
|
478
|
|
|
|
483
|
|
Amortization of nuclear fuel
|
|
|
31
|
|
|
|
42
|
|
Amortization and write-off of financing costs and debt
discount/premiums
|
|
|
22
|
|
|
|
59
|
|
Amortization of intangibles and out-of-market contracts
|
|
|
(226
|
)
|
|
|
(112
|
)
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
427
|
|
|
|
232
|
|
Changes in nuclear decommissioning trust liability
|
|
|
8
|
|
|
|
23
|
|
Changes in derivatives
|
|
|
(110
|
)
|
|
|
41
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(320
|
)
|
|
|
(107
|
)
|
Loss/(gain) on disposals and sales of assets
|
|
|
13
|
|
|
|
(16
|
)
|
Gain on sale of discontinued operations
|
|
|
(273
|
)
|
|
|
|
|
Gain on sale of emission allowances
|
|
|
(52
|
)
|
|
|
(31
|
)
|
Amortization of unearned equity compensation
|
|
|
21
|
|
|
|
19
|
|
Cash provided/(used) by changes in other working capital
|
|
|
81
|
|
|
|
(116
|
)
|
|
|
Net Cash Provided by Operating Activities
|
|
|
1,041
|
|
|
|
976
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(649
|
)
|
|
|
(309
|
)
|
Increase in restricted cash, net
|
|
|
(3
|
)
|
|
|
(18
|
)
|
Decrease in notes receivable
|
|
|
20
|
|
|
|
26
|
|
Purchases of emission allowances
|
|
|
(6
|
)
|
|
|
(152
|
)
|
Proceeds from sale of emission allowances
|
|
|
75
|
|
|
|
170
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(441
|
)
|
|
|
(193
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
434
|
|
|
|
170
|
|
Proceeds from sale of discontinued operations, net of cash
divested
|
|
|
241
|
|
|
|
|
|
Proceeds from sale of assets
|
|
|
14
|
|
|
|
57
|
|
Decrease in trust fund balances
|
|
|
|
|
|
|
19
|
|
Equity investment in unconsolidated affiliate
|
|
|
(17
|
)
|
|
|
|
|
Other
|
|
|
|
|
|
|
(2
|
)
|
|
|
Net Cash Used by Investing Activities
|
|
|
(332
|
)
|
|
|
(232
|
)
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
(41
|
)
|
|
|
(41
|
)
|
Payment of financing element of acquired derivatives
|
|
|
(49
|
)
|
|
|
|
|
Payment for treasury stock
|
|
|
(185
|
)
|
|
|
(268
|
)
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
8
|
|
|
|
|
|
Proceeds from sale of minority interest in subsidiary
|
|
|
50
|
|
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
20
|
|
|
|
1,411
|
|
Payment of deferred debt issuance costs
|
|
|
(2
|
)
|
|
|
(5
|
)
|
Payments for short and long-term debt
|
|
|
(202
|
)
|
|
|
(1,472
|
)
|
|
|
Net Cash Used by Financing Activities
|
|
|
(401
|
)
|
|
|
(375
|
)
|
|
|
Change in cash from discontinued operations
|
|
|
43
|
|
|
|
(16
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
7
|
|
|
|
Net Increase in Cash and Cash Equivalents
|
|
|
351
|
|
|
|
360
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
1,132
|
|
|
|
777
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
1,483
|
|
|
$
|
1,137
|
|
|
|
See notes to condensed consolidated financial statements.
9
NRG
ENERGY, INC.
NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
|
|
Note 1
|
Basis of
Presentation
|
NRG Energy, Inc., or NRG, or the Company, is a wholesale power
generation company with a significant presence in major
competitive power markets in the United States. NRG is engaged
in the ownership, development, construction and operation of
power generation facilities, the transacting in and trading of
fuel and transportation services, and the trading of energy,
capacity and related products in the United States and select
international markets.
The accompanying unaudited interim condensed consolidated
financial statements have been prepared in accordance with the
SECs regulations for interim financial information and
with the instructions to
Form 10-Q.
Accordingly, they do not include all of the information and
notes required by generally accepted accounting principles for
complete financial statements. The accounting policies NRG
follows are set forth in Note 2, Summary of Significant
Accounting Policies, to the Companys financial
statements in its Annual Report on
Form 10-K
for the year ended December 31, 2007. The following notes
should be read in conjunction with such policies and other
disclosures in the
Form 10-K.
Interim results are not necessarily indicative of results for a
full year.
In the opinion of management, the accompanying unaudited interim
consolidated financial statements contain all material
adjustments consisting of normal and recurring accruals
necessary to present fairly the Companys consolidated
financial position as of September 30, 2008, the results of
operations for the three and nine months ended
September 30, 2008 and 2007, and cash flows for the nine
months ended September 30, 2008 and 2007. Certain
prior-year amounts have been reclassified for comparative
purposes.
Use of
Estimates
The preparation of consolidated financial statements in
accordance with generally accepted accounting principles
requires management to make estimates and assumptions. These
estimates and assumptions impact the reported amount of assets
and liabilities and disclosures of contingent assets and
liabilities as of the date of the consolidated financial
statements. They also impact the reported amount of net earnings
during the reporting period. Actual results could be different
from these estimates.
Cash
and Cash Equivalents
Cash and cash equivalents at September 30, 2008 are
predominantly held in money market funds invested in treasury
securities or treasury repurchase agreements.
Investment
Accounted for by the Equity Method
In February 2008, a wholly-owned subsidiary of NRG entered into
a
50/50
joint venture with a subsidiary of BP Alternative Energy North
America Inc., or BP, to build and own the Sherbino I Wind Farm
LLC, or Sherbino. This is a 150 MW wind project consisting
of 50 Vestas 3 MW wind turbine generators, located in the
West Zone of Texas ERCOT power market, or Texas West. The
project will be funded through a combination of equity
contributions from the owners and non-recourse project-level
debt. NRG delivered a $59 million promissory note to
Sherbino to support its initial capital contribution, payable no
later than December 1, 2008, made an additional
$17 million cash contribution in April 2008, and expects to
contribute another $11 million by year end, bringing its
total expected equity contribution to approximately
$87 million. NRG has posted a letter of credit in this
amount. NRGs maximum exposure to loss is limited to its
expected equity investments. Sherbino commenced commercial
operations in October 2008.
Sherbino has entered into a long-term natural gas swap to
mitigate a portion of power price risk for its expected power
generation. As the changes in natural gas prices and in Texas
West power prices do not meet the required correlation for cash
flow hedge accounting, Sherbino will account for the natural gas
swap hedge under mark-to-market accounting.
NRG accounts for its investment in Sherbino under the equity
method of accounting. NRGs share of mark-to-market results
of the natural gas swap, a loss of $9 million for the nine
months ended September 30, 2008, is included in NRGs
equity in earnings of Sherbino. NRGs investment at
September 30, 2008, net of its promissory note commitment,
is $7 million, which is included in Equity
Investments in Affiliates on the condensed
consolidated balance sheet.
10
Other
Cash Flow Information
NRGs non-cash investing activities for the nine months
ended September 30, 2008 included capital expenditures of
$60 million for which the associated liability is reflected
within accrued expenses.
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 Financial Accounting Standards Board, or
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 did not have a material impact on the
Companys consolidated financial position, statement of
operations, and cash flows. The Company is currently evaluating
the impact of the deferred portion of SFAS 157 on the
Companys consolidated financial position, statement of
operations, and cash flows.
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.
NRG has non-qualified stock options for which it has
insufficient historical exercise data and therefore estimates
the expected term using the simplified method, as allowed under
Staff Accounting Bulletin, or SAB, No. 107, Share Based
Payment, or SAB 107. In December 2007, the SEC issued
SAB No. 110, Certain Assumptions Used in Valuation
Methods, which eliminates the December 31, 2007
expiration of SAB 107s permission to use this
simplified method. NRG will therefore continue to use this
simplified method, for as long as the Company deems it to be the
most appropriate method.
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
requires an acquirer to recognize and measure in its financial
statements the identifiable assets acquired, the liabilities
assumed, and any noncontrolling interest in the acquiree at fair
value at the acquisition date. 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. As discussed further in Note 12, Income
Taxes, SFAS 141R will change the application of fresh
start accounting to certain of the Companys unrecognized
tax benefits. NRG is currently evaluating the impact of this
statement upon its adoption on the Companys results of
operations, financial position and cash flows.
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 is currently evaluating the impact of this
statement upon its adoption on the Companys results of
operations, financial position and cash flows.
11
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, Accounting for Derivative Instruments
and Hedging Activities, as amended or SFAS 133, and its
related interpretations, 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. The enhanced disclosures regarding
derivative and hedging instruments required by SFAS 161 are
relevant to NRG, but will not have an 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.
FSP
FAS 142-3
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 No. 142, Goodwill and Other Intangible Assets.
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
is currently evaluating the impact of this statement upon its
adoption 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. FSP
APB 14-1
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 is currently evaluating the impact of this statement upon
its adoption on the Companys results of operations,
financial position and cash flows.
In June 2008, the Emerging Issues Task Force, or 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, 2008, and interim periods
within those fiscal years. NRG is currently evaluating the
impact of this statement upon its adoption on the Companys
results of operations, financial position and cash flows.
In September 2008, the FASB issued FSP
FAS 133-1
and
FIN 45-4,
Disclosures about Credit Derivatives and Certain Guarantees:
An Amendment of FASB Statement No. 133 and FASB
Interpretation No. 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 45
Guarantors Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of
Others to require additional disclosures about credit
derivatives, credit derivatives embedded in a hybrid instrument,
and the current status of the payment/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 there will be no
impact on NRG related to credit derivatives. The clarification
to SFAS 161 is not applicable to NRG as it only affects
non-calendar year filers. The enhanced disclosures regarding the
current status of the payment/performance risk of guarantees are
relevant to NRG, but will not have an 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. The fair value measurement
requirements and enhanced disclosures regarding existence of
third-party credit enhancements on the entitys issued debt
and valuation techniques will not have an impact on the
Companys results of operations, financial position, or
cash flows.
12
On October 10, 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 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 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
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 period
ended September 30, 2008,
FSP 157-3
did not have an impact on the Companys results of
operations, financial position, or cash flows.
|
|
Note 2
|
Comprehensive
Income/(Loss)
|
The following table summarizes the components of the
Companys comprehensive income, net of tax.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
(In millions)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Net income
|
|
$
|
784
|
|
|
$
|
268
|
|
|
$
|
965
|
|
|
$
|
482
|
|
|
|
|
|
Changes in derivative activity
|
|
|
1,112
|
|
|
|
46
|
|
|
|
112
|
|
|
|
(278
|
)
|
|
|
Foreign currency translation adjustment
|
|
|
(104
|
)
|
|
|
39
|
|
|
|
(54
|
)
|
|
|
65
|
|
|
|
Unrealized gain/(loss) on available-for-sale securities
|
|
|
(4
|
)
|
|
|
|
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
|
|
Other comprehensive income/(loss), net of tax
|
|
$
|
1,004
|
|
|
$
|
85
|
|
|
$
|
57
|
|
|
$
|
(212
|
)
|
|
|
|
|
Comprehensive income
|
|
$
|
1,788
|
|
|
$
|
353
|
|
|
$
|
1,022
|
|
|
$
|
270
|
|
|
|
|
|
The following table summarizes the changes in the Companys
accumulated other comprehensive loss, net of tax.
|
|
|
|
|
(In millions)
|
|
|
|
As of September 30,
|
|
2008
|
|
|
|
Accumulated other comprehensive loss as of December 31, 2007
|
|
$
|
(115
|
)
|
Changes in derivative activity
|
|
|
112
|
|
Foreign currency translation adjustments
|
|
|
(54
|
)
|
Unrealized loss on available-for-sale securities
|
|
|
(1
|
)
|
|
|
Accumulated other comprehensive loss as of September 30,
2008
|
|
$
|
(58
|
)
|
|
|
13
|
|
Note 3
|
Discontinued
Operations
|
NRG has classified material business operations and gains/losses
recognized on sale as discontinued operations for projects that
were sold or have met the required criteria for such
classification. The financial results for the affected
businesses have been accounted for as discontinued operations.
The assets and liabilities reported in the balance sheet as of
December 31, 2007 as discontinued operations represent
those of Itiquira Energetica S.A., or 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 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 condensed consolidated balance sheet.
Summarized operating results for the Companys discontinued
operations, consisting of ITISAs activities, were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Operating revenues
|
|
$
|
|
|
|
$
|
13
|
|
|
$
|
20
|
|
|
$
|
36
|
|
|
|
Operating costs and other expenses
|
|
|
|
|
|
|
7
|
|
|
|
9
|
|
|
|
18
|
|
|
|
|
|
Pre-tax income from operations of discontinued components
|
|
|
|
|
|
|
6
|
|
|
|
11
|
|
|
|
18
|
|
|
|
Income tax expense
|
|
|
|
|
|
|
3
|
|
|
|
3
|
|
|
|
5
|
|
|
|
|
|
Income from operations of discontinued components
|
|
|
|
|
|
|
3
|
|
|
|
8
|
|
|
|
13
|
|
|
|
|
|
Disposal of discontinued components pre-tax gain
|
|
|
3
|
|
|
|
|
|
|
|
273
|
|
|
|
|
|
|
|
Income tax expense
|
|
|
3
|
|
|
|
|
|
|
|
109
|
|
|
|
|
|
|
|
|
|
Gain on disposal of discontinued components, net of income tax
|
|
|
|
|
|
|
|
|
|
|
164
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of income tax expense
|
|
$
|
|
|
|
$
|
3
|
|
|
$
|
172
|
|
|
$
|
13
|
|
|
|
|
|
|
|
Note 4
|
Fair
Value of Financial Instruments
|
Fair
Value of Long-Term Debt
The Companys long-term debt is recorded at carrying value
on the Companys consolidated balance sheet. The carrying
amounts and fair value of the Companys long-term debt as
of September 30, 2008 and December 31, 2007 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2008
|
|
|
December 31, 2007
|
|
|
|
|
|
|
|
|
|
Carrying
|
|
|
Fair
|
|
|
Carrying
|
|
|
Fair
|
|
(In millions)
|
|
|
|
Amount
|
|
|
Value
|
|
|
Amount
|
|
|
Value
|
|
|
|
Long-term debt, including current portion
|
|
|
|
$
|
8,028
|
|
|
$
|
7,218
|
|
|
$
|
8,180
|
|
|
$
|
8,164
|
|
|
|
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.
14
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.
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 September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Fair Value
|
As of September 30, 2008
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
|
Investment in available-for-sale securities (classified within
other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
|
Marketable equity securities
|
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
Trust fund investments
|
|
|
|
|
180
|
|
|
|
135
|
|
|
|
20
|
|
|
|
335
|
|
|
|
Derivative assets
|
|
|
|
|
2,152
|
|
|
|
2,832
|
|
|
|
22
|
|
|
|
5,006
|
|
|
|
|
|
Total assets
|
|
|
|
$
|
2,337
|
|
|
$
|
2,967
|
|
|
$
|
52
|
|
|
$
|
5,356
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
$
|
2,153
|
|
|
$
|
3,023
|
|
|
$
|
4
|
|
|
$
|
5,180
|
|
|
|
|
|
The following table reconciles, for the period ended
September 30, 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)
|
(In millions)
|
|
|
|
|
|
|
Trust Fund
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2008
|
|
|
|
Debt Securities
|
|
|
Investments
|
|
|
Derivatives
|
|
|
Total
|
|
|
|
|
Beginning balance as of January 1, 2008
|
|
|
|
$
|
32
|
|
|
$
|
37
|
|
|
$
|
27
|
|
|
$
|
96
|
|
|
|
Total gains and losses (realized/unrealized)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
(19
|
)
|
|
|
(41
|
)
|
|
|
Included in nuclear decommissioning obligations
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
(9
|
)
|
|
|
Included in other comprehensive income
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
28
|
|
|
|
Purchases/(sales), net
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
(17
|
)
|
|
|
(26
|
)
|
|
|
Transfer into Level 3
|
|
|
|
|
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
Ending balance as of September 30, 2008
|
|
|
|
$
|
10
|
|
|
$
|
20
|
|
|
$
|
18
|
|
|
$
|
48
|
|
|
|
|
|
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 September 30,
2008
|
|
|
|
$
|
22
|
|
|
$
|
|
|
|
$
|
19
|
|
|
$
|
41
|
|
|
|
|
|
15
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
Note 5 Nuclear Decommissioning Trust Fund.
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 we receive quotes from multiple sources. To the extent
that we receive multiple quotes our 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 we only receive 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 11% 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, we apply a credit reserve
to reflect credit risk which is calculated based on published
default probabilities. To the extent that our net exposure under
a specific master agreement is an asset we are using the
counterpartys risk of default. If the exposure under a
specific master agreement is a liability we are using NRGs
probability of default. 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 September 30, 2008 the credit
reserve resulted in a $6 million decrease in fair value
which is composed of a $5 million gain in OCI and an
$11 million loss in derivative revenue. The fair values in
each category reflect the level of forward prices and volatility
factors as of September 30, 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 derivative positions in the
financial statements against the fair value of the amounts
recognized as cash collateral paid or received under those
arrangements. The Company has credit arrangements within various
agreements to call on or pay additional collateral support. The
Company has chosen not to offset positions as defined in this
FSP. As of September 30, 2008, the Company recorded
$544 million of cash collateral paid and $154 million
of cash collateral received on its balance sheet.
16
|
|
Note 5
|
Nuclear
Decommissioning Trust Fund
|
NRGs nuclear decommissioning trust fund assets which are
for the decommissioning of South Texas Project, or STP, are
primarily comprised of securities recorded at fair value based
on actively quoted market prices. NRG accounts for these trust
fund assets per SFAS 71, Accounting for the Effects of
Certain Types of Regulation, because the Companys
nuclear decommissioning activities are regulated by the Public
Utility Commission of Texas, or PUCT. Although the owners of STP
are responsible for the management of decommissioning STP, the
cost of decommissioning is the responsibility of the Texas
ratepayers. As such, NRG does not bear the cost for these
decommissioning responsibilities, except to the extent that NRG
has a prudence obligation with respect to the management of the
trust funds and 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 September 30, 2008 and
December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
September 30, 2008
|
|
|
December 31, 2007
|
|
|
|
|
Cash and cash equivalents
|
|
|
$ 1
|
|
|
|
$ 4
|
|
|
|
US government and federal agency obligations
|
|
|
26
|
|
|
|
21
|
|
|
|
Federal agency mortgage-backed securities
|
|
|
65
|
|
|
|
59
|
|
|
|
Commercial mortgage-backed securities
|
|
|
23
|
|
|
|
22
|
|
|
|
Corporate debt securities
|
|
|
39
|
|
|
|
44
|
|
|
|
Marketable equity securities
|
|
|
179
|
|
|
|
234
|
|
|
|
|
|
Total
|
|
|
$ 333
|
|
|
|
$ 384
|
|
|
|
|
|
|
|
Note 6
|
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 Normal Purchase Normal Sale, or 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 Other Comprehensive Income, or OCI, until the hedged
transactions occur and are recognized in earnings. The
ineffective portion of a cash flow hedge is immediately
recognized in earnings.
Accumulated
Other Comprehensive Income
The following tables summarize the effects of SFAS 133 on
NRGs OCI balance attributable to hedged derivatives, net
of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Energy
|
|
|
Interest
|
|
|
|
|
Three months ended September 30, 2008
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
Accumulated OCI balance at June 30, 2008
|
|
$
|
(1,235
|
)
|
|
$
|
(30
|
)
|
|
$
|
(1,265
|
)
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
Mark-to-market of hedge contracts
|
|
|
1,088
|
|
|
|
(2
|
)
|
|
|
1,086
|
|
|
|
Accumulated OCI balance at September 30, 2008
|
|
$
|
(121
|
)
|
|
$
|
(32
|
)
|
|
$
|
(153
|
)
|
|
|
Gains expected to be realized from OCI during the next
12 months, net of $53 tax
|
|
$
|
81
|
|
|
$
|
|
|
|
$
|
81
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Energy
|
|
|
Interest
|
|
|
|
|
|
|
Three months ended September 30, 2007
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
|
Accumulated OCI balance at June 30, 2007
|
|
$
|
(145
|
)
|
|
$
|
30
|
|
|
$
|
(115
|
)
|
|
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts
|
|
|
(10
|
)
|
|
|
(1
|
)
|
|
|
(11
|
)
|
|
|
Mark-to-market of hedge contracts
|
|
|
86
|
|
|
|
(29
|
)
|
|
|
57
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2007
|
|
$
|
(69
|
)
|
|
$
|
|
|
|
$
|
(69
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Energy
|
|
|
Interest
|
|
|
|
|
|
|
Nine months ended September 30, 2008
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
|
Accumulated OCI balance at December 31, 2007
|
|
$
|
(234
|
)
|
|
$
|
(31
|
)
|
|
$
|
(265
|
)
|
|
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts
|
|
|
32
|
|
|
|
|
|
|
|
32
|
|
|
|
Mark-to-market of hedge contracts
|
|
|
81
|
|
|
|
(1
|
)
|
|
|
80
|
|
|
|
|
|
Accumulated OCI balance at September 30, 2008
|
|
$
|
(121
|
)
|
|
$
|
(32
|
)
|
|
$
|
(153
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Energy
|
|
|
Interest
|
|
|
|
|
|
|
Nine months ended September 30, 2007
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
|
Accumulated OCI balance at December 31, 2006
|
|
$
|
193
|
|
|
$
|
16
|
|
|
$
|
209
|
|
|
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts
|
|
|
(37
|
)
|
|
|
(1
|
)
|
|
|
(38
|
)
|
|
|
Mark-to-market of hedge contracts
|
|
|
(225
|
)
|
|
|
(15
|
)
|
|
|
(240
|
)
|
|
|
|
|
Accumulated OCI balance at September 30, 2007
|
|
$
|
(69
|
)
|
|
$
|
|
|
|
$
|
(69
|
)
|
|
|
|
|
As of September 30, 2008 and 2007, the net balances in OCI
relating to SFAS 133 were unrecognized losses of
approximately $153 million and $69 million, which were
net of income taxes of $102 million and $46 million,
respectively.
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 July 31, 2008. 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.
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Unrealized mark-to-market results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
$
|
(7
|
)
|
|
$
|
(17
|
)
|
|
$
|
(32
|
)
|
|
$
|
(109
|
)
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
(9
|
)
|
|
|
(3
|
)
|
|
|
(20
|
)
|
|
|
(23
|
)
|
|
|
Net unrealized gains on open positions related to economic hedges
|
|
|
439
|
|
|
|
1
|
|
|
|
180
|
|
|
|
22
|
|
|
|
(Loss)/gain on ineffectiveness associated with open positions
treated as cash flow hedges
|
|
|
352
|
|
|
|
9
|
|
|
|
(27
|
)
|
|
|
32
|
|
|
|
Net unrealized gains on open positions related to trading
activity
|
|
|
26
|
|
|
|
16
|
|
|
|
57
|
|
|
|
37
|
|
|
|
|
|
Total unrealized mark-to-market results
|
|
$
|
801
|
|
|
$
|
6
|
|
|
$
|
158
|
|
|
$
|
(41
|
)
|
|
|
|
|
Discontinued Hedge Accounting During the
third quarter of 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
three and nine months ended September 30, 2008.
18
Debt
Related to NRG Common Stock Finance I, LLC
In March 2008, the Company executed an arrangement with Credit
Suisse, or CS, to extend the notes and preferred interest
maturities of NRG Common Stock Finance I, LLC, or
CSF I, from October 2008 to June 2010. In addition, the
settlement date of an embedded derivative, or CSFI CAGR, which
is based on NRGs share price appreciation beyond a 20%
compound annual growth rate since the original date of purchase
by CSF I, 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 CSFI CAGR. Accordingly,
NRG made a cash payment of $45 million to CS for the
benefit of CSFI, which was recorded to interest expense in the
Companys Consolidated Statement of Operations.
Senior
Credit Facility
Beginning in 2008, NRG must annually offer a portion of its
excess cash flow (as defined in the Senior Credit Facility) for
the prior year to its first lien lenders under the
Companys Term B loan. 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. The mandatory annual offer required for
2008 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 can be used for investments, capital expenditures and
other items as permitted by the Senior Credit Facility.
|
|
Note 8
|
Changes
in Capital Structure
|
The following table reflects the changes in NRGs common
stock issued and outstanding during the nine months ended
September 30, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized
|
|
|
Issued
|
|
|
Treasury
|
|
|
Outstanding
|
|
|
|
|
Balance as of December 31, 2007
|
|
|
500,000,000
|
|
|
|
261,285,529
|
|
|
|
(24,550,600
|
)
|
|
|
236,734,929
|
|
|
|
2008 Capital Allocation Program
|
|
|
|
|
|
|
|
|
|
|
(4,691,883
|
)
|
|
|
(4,691,883
|
)
|
|
|
Shares issued from LTIP
|
|
|
|
|
|
|
984,176
|
|
|
|
|
|
|
|
984,176
|
|
|
|
|
|
Balance as of September 30, 2008
|
|
|
500,000,000
|
|
|
|
262,269,705
|
|
|
|
(29,242,483
|
)
|
|
|
233,027,222
|
|
|
|
|
|
Treasury
Stock
In December 2007, the Company initiated its 2008 Capital
Allocation Program, 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 Program 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
September 30, 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 Program.
19
|
|
Note 9
|
Equity
Compensation
|
Non-Qualified
Stock Options, or NQSOs
The following table summarizes the Companys NQSO activity
as of September 30, 2008 and the changes during the nine
months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Aggregate
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Intrinsic
|
|
|
|
|
|
|
|
|
Average
|
|
|
Value
|
|
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
(In millions)
|
|
|
|
|
Outstanding as of December 31, 2007
|
|
|
3,579,775
|
|
|
$
|
19.98
|
|
|
|
|
|
|
|
Granted
|
|
|
1,174,200
|
|
|
|
40.48
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(148,536
|
)
|
|
|
32.79
|
|
|
|
|
|
|
|
Exercised
|
|
|
(507,986
|
)
|
|
|
16.29
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at September 30, 2008
|
|
|
4,097,453
|
|
|
|
25.84
|
|
|
$
|
|
|
|
|
Exercisable at September 30, 2008
|
|
|
2,056,803
|
|
|
$
|
17.54
|
|
|
|
15
|
|
|
|
|
|
The weighted average grant date fair value of NQSOs
granted for the nine months ending September 30, 2008 was
$10.61.
Restricted
Stock Units, or RSUs
The following table summarizes the Companys non-vested RSU
awards as of September 30, 2008 and changes during the nine
months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Grant-Date
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
Units
|
|
|
Per Unit
|
|
|
|
|
Non-vested as of December 31, 2007
|
|
|
1,588,316
|
|
|
$
|
26.99
|
|
|
|
Granted
|
|
|
163,200
|
|
|
|
40.22
|
|
|
|
Vested
|
|
|
(610,760
|
)
|
|
|
19.38
|
|
|
|
Forfeited
|
|
|
(71,320
|
)
|
|
|
31.13
|
|
|
|
|
|
Non-vested as of September 30, 2008
|
|
|
1,069,436
|
|
|
$
|
33.08
|
|
|
|
|
|
Performance
Units, or PUs
The following table summarizes the Companys non-vested PU
awards as of September 30, 2008 and changes during the nine
months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
Grant- Date
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
|
|
Units
|
|
|
Per Unit
|
|
|
|
|
Non-vested as of December 31, 2007
|
|
|
536,764
|
|
|
$
|
20.18
|
|
|
|
Granted
|
|
|
227,300
|
|
|
|
27.75
|
|
|
|
Vested
|
|
|
(50,000
|
)
|
|
|
15.74
|
|
|
|
Forfeited
|
|
|
(59,700
|
)
|
|
|
21.49
|
|
|
|
|
|
Non-vested as of September 30, 2008
|
|
|
654,364
|
|
|
$
|
23.05
|
|
|
|
|
|
In the third quarter 2008, 100,000 shares of common stock
were issued for performance units that vested in accordance with
the plan payout provisions.
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 ends December 31, 2008. There are
500,000 shares of treasury stock reserved for issuance
under the ESPP.
20
|
|
Note 10
|
Earnings
Per Share
|
Basic earnings per common share is computed by dividing net
income adjusted for 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.
The reconciliation of basic earnings per common share to diluted
earnings per share is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
(In millions, except per share data)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Basic earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
784
|
|
|
$
|
265
|
|
|
$
|
793
|
|
|
$
|
469
|
|
|
|
Preferred stock dividends
|
|
|
(13
|
)
|
|
|
(13
|
)
|
|
|
(41
|
)
|
|
|
(41
|
)
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
|
771
|
|
|
|
252
|
|
|
|
752
|
|
|
|
428
|
|
|
|
Discontinued operations, net of income tax expense
|
|
|
|
|
|
|
3
|
|
|
|
172
|
|
|
|
13
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
771
|
|
|
$
|
255
|
|
|
$
|
924
|
|
|
$
|
441
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
234.8
|
|
|
|
239.4
|
|
|
|
235.7
|
|
|
|
240.5
|
|
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
3.28
|
|
|
$
|
1.05
|
|
|
$
|
3.19
|
|
|
$
|
1.78
|
|
|
|
Discontinued operations, net of income tax expense
|
|
|
|
|
|
|
0.02
|
|
|
|
0.73
|
|
|
|
0.05
|
|
|
|
|
|
Net income
|
|
$
|
3.28
|
|
|
$
|
1.07
|
|
|
$
|
3.92
|
|
|
$
|
1.83
|
|
|
|
|
|
Diluted earnings per share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
$
|
771
|
|
|
$
|
252
|
|
|
$
|
752
|
|
|
$
|
428
|
|
|
|
Add preferred stock dividends for dilutive preferred stock
|
|
|
11
|
|
|
|
11
|
|
|
|
34
|
|
|
|
34
|
|
|
|
|
|
Adjusted income from continuing operations available to common
shareholders
|
|
|
782
|
|
|
|
263
|
|
|
|
786
|
|
|
|
462
|
|
|
|
Discontinued operations, net of tax
|
|
|
|
|
|
|
3
|
|
|
|
172
|
|
|
|
13
|
|
|
|
|
|
Net income available to common stockholders
|
|
$
|
782
|
|
|
$
|
266
|
|
|
$
|
958
|
|
|
$
|
475
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
234.8
|
|
|
|
239.4
|
|
|
|
235.7
|
|
|
|
240.5
|
|
|
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method)
|
|
|
2.2
|
|
|
|
3.8
|
|
|
|
3.0
|
|
|
|
3.7
|
|
|
|
Incremental shares attributable to embedded derivatives of
certain financial instruments (if-converted method)
|
|
|
2.0
|
|
|
|
4.6
|
|
|
|
1.8
|
|
|
|
4.9
|
|
|
|
Incremental shares attributable to assumed conversion features
of outstanding preferred stock (if-converted method)
|
|
|
37.5
|
|
|
|
37.5
|
|
|
|
37.5
|
|
|
|
37.5
|
|
|
|
|
|
Total dilutive shares
|
|
|
276.5
|
|
|
|
285.3
|
|
|
|
278.0
|
|
|
|
286.6
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations available to common
shareholders
|
|
$
|
2.83
|
|
|
$
|
0.92
|
|
|
$
|
2.83
|
|
|
$
|
1.61
|
|
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
0.01
|
|
|
|
0.62
|
|
|
|
0.05
|
|
|
|
|
|
Net income
|
|
$
|
2.83
|
|
|
$
|
0.93
|
|
|
$
|
3.45
|
|
|
$
|
1.66
|
|
|
|
|
|
21
Effects
on Earnings per Share
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
(In millions of shares)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Equity compensation
|
|
|
1.8
|
|
|
|
|
|
|
|
1.4
|
|
|
|
0.4
|
|
|
|
Embedded derivative of 3.625% convertible perpetual preferred
stock
|
|
|
14.0
|
|
|
|
13.2
|
|
|
|
14.2
|
|
|
|
13.0
|
|
|
|
Embedded derivative of preferred interests and notes issued by
CSF I and CSF II
|
|
|
8.3
|
|
|
|
16.7
|
|
|
|
8.3
|
|
|
|
16.6
|
|
|
|
|
|
Total
|
|
|
24.1
|
|
|
|
29.9
|
|
|
|
23.9
|
|
|
|
30.0
|
|
|
|
|
|
|
|
Note 11
|
Segment
Reporting
|
The Companys segment structure reflects NRGs core
areas of operation which are primarily the geographic regions of
the Companys wholesale power generation, thermal and
chilled water business, and corporate activities. Within
NRGs wholesale power generation operations, there are
distinct components with separate operating results and
management structures for the following regions: Texas,
Northeast, South Central, West and International.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2008
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
Operating revenues
|
|
$
|
1,661
|
|
|
$
|
677
|
|
|
$
|
233
|
|
|
$
|
40
|
|
|
|
$
41
|
|
|
$
|
36
|
|
|
$
|
3
|
|
|
$
|
(1
|
)
|
|
$
|
2,690
|
|
|
|
Depreciation and amortization
|
|
|
108
|
|
|
|
26
|
|
|
|
16
|
|
|
|
2
|
|
|
|
|
|
|
|
3
|
|
|
|
1
|
|
|
|
|
|
|
|
156
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
1,050
|
|
|
|
351
|
|
|
|
24
|
|
|
|
13
|
|
|
|
25
|
|
|
|
4
|
|
|
|
(152
|
)
|
|
|
(1
|
)
|
|
|
1,314
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
594
|
|
|
$
|
351
|
|
|
$
|
24
|
|
|
$
|
13
|
|
|
|
$
19
|
|
|
$
|
4
|
|
|
$
|
(220
|
)
|
|
$
|
(1
|
)
|
|
$
|
784
|
|
|
|
|
|
Total assets
|
|
$
|
12,102
|
|
|
$
|
1,634
|
|
|
$
|
942
|
|
|
$
|
53
|
|
|
|
$
1,002
|
|
|
$
|
212
|
|
|
$
|
19,006
|
|
|
$
|
(11,268
|
)
|
|
$
|
23,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2007
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
Operating revenues
|
|
$
|
956
|
|
|
$
|
502
|
|
|
$
|
200
|
|
|
$
|
33
|
|
|
|
$
38
|
|
|
$
|
36
|
|
|
$
|
7
|
|
|
$
|
|
|
|
$
|
1,772
|
|
|
|
Depreciation and amortization
|
|
|
113
|
|
|
|
25
|
|
|
|
17
|
|
|
|
1
|
|
|
|
|
|
|
|
3
|
|
|
|
1
|
|
|
|
|
|
|
|
160
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
275
|
|
|
|
171
|
|
|
|
18
|
|
|
|
13
|
|
|
|
25
|
|
|
|
4
|
|
|
|
(96
|
)
|
|
|
|
|
|
|
410
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
161
|
|
|
$
|
171
|
|
|
$
|
17
|
|
|
$
|
13
|
|
|
|
$
54
|
|
|
$
|
4
|
|
|
$
|
(152
|
)
|
|
$
|
|
|
|
$
|
268
|
|
|
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2008
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
Operating revenues
|
|
$
|
3,061
|
|
|
$
|
1,302
|
|
|
$
|
584
|
|
|
$
|
127
|
|
|
$
|
122
|
|
|
$
|
114
|
|
|
$
|
1
|
|
|
$
|
(3
|
)
|
|
$
|
5,308
|
|
|
|
Depreciation and amortization
|
|
|
334
|
|
|
|
77
|
|
|
|
50
|
|
|
|
6
|
|
|
|
|
|
|
|
8
|
|
|
|
3
|
|
|
|
|
|
|
|
478
|
|
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
1,131
|
|
|
|
365
|
|
|
|
57
|
|
|
|
38
|
|
|
|
72
|
|
|
|
11
|
|
|
|
(339
|
)
|
|
|
(11
|
)
|
|
|
1,324
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
644
|
|
|
$
|
365
|
|
|
$
|
57
|
|
|
$
|
38
|
|
|
$
|
229
|
|
|
$
|
11
|
|
|
$
|
(368
|
)
|
|
$
|
(11
|
)
|
|
$
|
965
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2007
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
Operating revenues
|
|
$
|
2,526
|
|
|
$
|
1,239
|
|
|
$
|
514
|
|
|
$
|
90
|
|
|
$
|
102
|
|
|
$
|
122
|
|
|
$
|
29
|
|
|
$
|
(15
|
)
|
|
$
|
4,607
|
|
|
|
Depreciation and amortization
|
|
|
341
|
|
|
|
74
|
|
|
|
51
|
|
|
|
2
|
|
|
|
|
|
|
|
9
|
|
|
|
4
|
|
|
|
|
|
|
|
481
|
|
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
624
|
|
|
|
319
|
|
|
|
24
|
|
|
|
26
|
|
|
|
60
|
|
|
|
32
|
|
|
|
(304
|
)
|
|
|
(12
|
)
|
|
|
769
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
Net income/(loss)
|
|
$
|
355
|
|
|
$
|
319
|
|
|
$
|
23
|
|
|
$
|
26
|
|
|
$
|
88
|
|
|
$
|
32
|
|
|
$
|
(349
|
)
|
|
$
|
(12
|
)
|
|
$
|
482
|
|
|
|
|
|
Income tax expense from continuing operations for the three
months and nine months ended September 30, 2008 was
$530 million and $531 million, respectively, compared
to $145 million and $300 million for the three and
nine months ended September 30, 2007, respectively. The
income tax expense for the three months and nine months ended
September 30, 2008 included domestic tax expense of
$523 million and $515 million, respectively, and
foreign tax expense of $7 million and $16 million,
respectively. The income tax expense for the three and nine
months ended September 30, 2007 included domestic tax
expense of $171 million and $314 million,
respectively, and a foreign tax benefit of $26 million and
$14 million, respectively.
A reconciliation of the US statutory rate to NRGs
effective tax rate from continuing operations is as follows:
|
|
|
|
|
|
|
|
|
|
|
(In millions except percentages)
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
2008
|
|
|
2007
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,324
|
|
|
$
|
769
|
|
|
|
|
|
Tax at 35%
|
|
|
463
|
|
|
|
269
|
|
|
|
State taxes
|
|
|
62
|
|
|
|
37
|
|
|
|
Valuation allowance
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
Foreign operations
|
|
|
(10
|
)
|
|
|
(5
|
)
|
|
|
Foreign dividend
|
|
|
5
|
|
|
|
21
|
|
|
|
Non-deductible interest
|
|
|
24
|
|
|
|
7
|
|
|
|
Change in German tax rate
|
|
|
|
|
|
|
(30
|
)
|
|
|
Section 199 Manufacturing Deduction
|
|
|
(17
|
)
|
|
|
(3
|
)
|
|
|
Other permanent differences including subpart F income
|
|
|
5
|
|
|
|
3
|
|
|
|
|
|
Income tax expense
|
|
$
|
531
|
|
|
$
|
300
|
|
|
|
|
|
Effective income tax rate
|
|
|
40.1
|
%
|
|
|
39.0
|
%
|
|
|
|
|
The effective income tax rate for the nine months ended
September 30, 2008 and 2007 differs from the US statutory
rate of 35% due to a taxable dividend from foreign operations
and non-deductible interest, offset by earnings in foreign
jurisdictions that are taxed at rates lower than the US
statutory rate.
23
Tax
Payable
As of September 30, 2008, NRG recorded a current tax
payable of $191 million for domestic federal and state taxes.
Deferred
tax assets and valuation allowance
Net deferred tax balance As of
September 30, 2008, NRG recorded a net deferred tax
liability of $560 million. 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 $539 million of tax assets, thus a valuation allowance
has remained, resulting in a net deferred tax liability of
$1,099 million.
NOL carryforwards As of September 30,
2008, the Company had cumulative foreign NOL carryforwards of
$253 million, of which $54 million will expire
starting in 2011 through 2017 and $199 million do not have
an expiration date.
Uncertain
tax benefits
NRG has identified certain unrecognized tax benefits whose
after-tax value was $709 million, of which $36 million
would impact the Companys income tax expense. Of the
$709 million in unrecognized tax benefits,
$673 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 September 30, 2008, NRG has recorded a
$138 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
$4 million as of September 30, 2008. The Company
recognizes interest and penalties related to unrecognized tax
benefits in income tax expense. For the nine months ended
September 30, 2008, 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.
24
|
|
Note 13
|
Benefit
Plans and Other Postretirement Benefits
|
NRG
Defined Benefit Plans
NRG sponsors and operates three defined benefit pension and
other postretirement plans. The NRG Plan for Bargained Employees
and the NRG Plan for Non-Bargained Employees are maintained
solely for eligible legacy NRG participants. A third plan, the
Texas Genco Retirement Plan, is maintained for participation
solely by eligible Texas-based employees. The total amount of
employer contributions paid for the nine months ended
September 30, 2008 was $57 million. NRG expects to
make $7 million in further contributions for the remainder
of 2008.
The net periodic pension cost related to all of the
Companys defined benefit pension plans includes the
following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plans
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
(In millions)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Service cost benefits earned
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
11
|
|
|
$
|
11
|
|
|
|
Interest cost on benefit obligation
|
|
|
4
|
|
|
|
4
|
|
|
|
13
|
|
|
|
13
|
|
|
|
Net gain
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
Expected return on plan assets
|
|
|
(4
|
)
|
|
|
(3
|
)
|
|
|
(11
|
)
|
|
|
(9
|
)
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
4
|
|
|
$
|
4
|
|
|
$
|
12
|
|
|
$
|
15
|
|
|
|
|
|
The net periodic cost related to all of the Companys other
postretirement benefits plans include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits Plans
|
|
|
Three Months Ended September 30,
|
|
|
Nine Months Ended September 30,
|
|
|
|
|
|
|
(In millions)
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Service cost benefits earned
|
|
$
|
1
|
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
2
|
|
|
|
Interest cost on benefit obligation
|
|
|
1
|
|
|
|
2
|
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
2
|
|
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
6
|
|
|
|
|
|
STP
Defined Benefit Plans
NRG has a 44% undivided ownership interest in South Texas
Project, or STP. South Texas Project Nuclear Operating Company,
or STPNOC, which 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. The
total amount of employer contributions reimbursed to STPNOC for
the nine months ended September 30, 2008 was
$4 million. The Company recognized net periodic costs
related to its 44% interest in STP defined benefits plans of
$2 million and $1 million for the three months ended
September 30, 2008 and 2007, respectively. The Company
recognized net periodic costs related to its 44% interest in STP
defined benefits plan of $6 million and $5 million for
the nine months ended September 30, 2008 and 2007,
respectively.
25
|
|
Note 14
|
Commitments
and Contingencies
|
Commitments
Fuel
Commitments
NRG enters into long-term contractual arrangements to procure
fuel and transportation services for the Companys
generation assets. NRG entered into additional coal purchase
agreements during the nine months ended September 30, 2008
with total commitments of approximately $465 million,
spanning from 2008 through 2011. In addition, NRGs natural
gas purchase commitments have decreased by approximately
$264 million during the nine months ended
September 30, 2008 as the 2008 monthly commitments
were settled.
First and
Second Lien Structure
NRG has granted first and second liens to certain counterparties
on substantially all of the Companys assets in the United
States in order to secure primarily long-term obligations under
power and gas sale agreements and related contracts. NRG uses
the first or second lien structure to reduce the amount of cash
collateral and letters of credit that it would otherwise be
required to post from time to time to support its obligations
under 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 is limited by volumes hedged, not by the value of
underlying out-of-the money positions. The first lien program
does not require us 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 rolling 60 months with such permitted hedging volumes 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.
As part of the amendments to NRGs Senior Credit Facility
entered into on June 8, 2007, the Company obtained the
ability to move its second lien counterparty exposure to the
first lien on a pari passu basis with the Companys
existing first lien lenders. In exchange for moving to a pari
passu basis with the Companys first lien lenders, the
counterparties relinquished letters of credit issued by NRG
which they held as a part of their collateral package.
The Companys lien counterparties may have a claim on our
assets to the extent their net positions are out-of-the-money.
As of September 30, 2008 and October 23, 2008, the
first lien exposure of net out-of-the-money positions to
counterparties on hedges was $405 million and
$185 million, respectively. As of September 30, 2008
and October 23, 2008, the second lien net out-of-the-money
positions to counterparties on hedges were approximately
$16 million and $2 million, respectively.
RepoweringNRG
NRG has made non-refundable payments relating to
RepoweringNRG projects totaling approximately
$148 million primarily towards the procurement of wind
turbines. The Company believes that these payments are necessary
for the timely and successful execution of these projects. The
payments are in support of expected deliveries of wind turbines
and other equipment totaling approximately $248 million
through 2009. In addition, as discussed further in Note 1,
Basis of Presentation, NRG expects to contribute
approximately $87 million in equity to Sherbino in 2008 and
has posted a letter of credit in that amount. To date, NRG has
made capital contributions to Sherbino in the amount of
$17 million. Also, NRGs share of cash security posted
to The Connecticut Light and Power Company by GenConn Energy
LLC, or GenConn, a 50/50 joint venture vehicle of NRG and The
United Illuminating Company, for the project at Devon Station
is approximately $9 million.
26
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. 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.
California
Department of Water Resources
On December 19, 2006, the US Court of Appeals for the Ninth
Circuit reversed the Federal Energy Regulatory
Commissions, or FERCs, prior determinations
regarding the enforceability of certain wholesale power
contracts and remanded the case to FERC for further proceedings
consistent with the decision. One of these contracts was the
wholesale power contract between the California Department of
Water Resources, or CDWR, and subsidiaries of WCP. This case
originated with a February 2002 complaint filed at FERC by the
State of California alleging that many parties, including WCP
subsidiaries, overcharged the State. For WCP, the alleged
overcharges totaled approximately $940 million for 2001 and
2002. The complaint demanded that FERC abrogate the CDWR
contract and sought refunds associated with revenues collected
under the contract. In 2003, FERC rejected this complaint,
denied rehearing, and the case was appealed to the Ninth Circuit
where oral argument was held on December 8, 2004. On
December 19, 2006, the Court decided that in FERCs
review of the contracts at issue, FERC could not rely on the
Mobil-Sierra standard presumption of just and reasonable rates,
where such contracts were not reviewed by FERC with full
knowledge of the then existing market conditions. On May 3,
2007, WCP and the other defendants filed separate petitions for
certiorari seeking review by the US Supreme Court. On
June 26, 2008, the Supreme Court issued its decision. The
Court held (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. The
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. Although WCPs petition
for review was not heard by the Supreme Court, the Supreme
Courts decision with respect to the Morgan Stanley
petition applies equally to WCP.
On October 20, 2008, the Ninth Circuit ordered the parties,
including FERC, to submit short briefs on the question of
whether that Court should answer a question that the US Supreme
Court did not address in its June 26, 2008, decision. That
question is 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. WCPs response is due November 14, 2008.
At this time, while NRG cannot predict with certainty whether
WCP will be required to make refunds for rates collected under
the CDWR contract or estimate the range of any such possible
refunds, a reconsideration of the CDWR contract by FERC with a
resulting order mandating significant refunds could have a
material adverse impact on NRGs financial position,
statement of operations, and statement of cash flows. As part of
the 2006 acquisition of Dynegys 50% ownership interest in
WCP, WCP and NRG assumed responsibility for any risk of loss
arising from this case, unless any such loss was deemed to have
resulted from certain acts of gross negligence or willful
misconduct on the part of Dynegy, in which case any such loss
would be shared equally between WCP and Dynegy.
27
Station
Service Disputes
On October 2, 2000, Niagara Mohawk Power Corporation, or
NiMo, commenced an action against NRG in New York state court
seeking damages related to NRGs alleged failure to pay
retail tariff amounts for utility services at the Dunkirk plant
between June 1999 and September 2000. The parties agreed to
consolidate this action with two other actions against the
Huntley and Oswego plants. On October 8, 2002, by
stipulation and order, this action was stayed pending submission
to FERC of the disputes in the action. At FERC, NiMo asserted
the same claims and legal theories, and on November 19,
2004, FERC denied NiMos petition and ruled that the NRG
facilities could net their service obligations over each 30
calendar day period from the day NRG acquired the facilities. In
addition, FERC ruled that neither NiMo nor the New York Public
Service Commission could impose a retail delivery charge on the
NRG facilities because they are interconnected to transmission
and not to distribution. NiMo appealed to the US Court of
Appeals for the D.C. Circuit which, on June 23, 2006,
denied the appeal finding that New York Independent System
Operators, or NYISOs, station service program that
permits generators to self supply their station power needs by
netting consumption against production in a month is lawful. On
April 30, 2007, the US Supreme Court denied NiMos
request for review of the D.C. Circuit decision thus ending
further avenues to appeal FERCs ruling in this matter. NRG
believes it is adequately reserved.
On December 14, 1999, NRG acquired certain generating
facilities from CL&P. A dispute arose over station service
power and delivery services provided to the facilities. On
December 20, 2002, as a result of a petition filed at FERC
by Northeast Utilities Services Company on behalf of itself and
CL&P, FERC issued an order finding that, at times when NRG
is not able to self-supply its station power needs, there is a
sale of station power from a third-party and retail charges
apply. In August 2003, the parties agreed to submit the dispute
to binding arbitration. On September 11, 2007, the parties
argued the dispute before a three judge arbitration panel. On
February 19, 2008, the parties executed a settlement
agreement ending the arbitration, and on April 30, 2008,
that settlement agreement became effective thereby ending the
case.
Native
Village of Kivalina and City of Kivalina
Twenty-four electric generating companies and oil and gas
companies were named as defendants in this complaint, in which
damages of up to $400 million had been asserted. The
complaint was filed on behalf of a small Alaskan town and sought
damages associated with the need to relocate from the northern
coast of Alaska purportedly because of the effects of global
warming caused by the defendants
CO2
emissions. On June 11, 2008, NRG and the plaintiffs
executed a Stipulation of Dismissal with Prejudice and on
June 16, 2008, the US District Court for the Northern
District of California dismissed NRG with prejudice thereby
ending the case for NRG. The Company had argued to the
plaintiffs that their allegations were blocked by NRGs
2003 bankruptcy. NRG did not pay any money or exchange anything
of value with the plaintiffs in exchange for its dismissal.
Spring
Creek Coal Company
In August 2007, Spring Creek Coal Company filed a complaint
against NRG Texas LP, NRG South Texas LP, NRG Texas Power LLC,
NRG Texas LLC, and NRG Energy, Inc. in the US District Court for
the federal district of Wyoming. The complaint alleged multiple
breaches in 2007 of a 1978 coal supply agreement as amended by a
later 1987 agreement, which plaintiff alleges is a take or
pay contract. On April 10, 2008, the parties reached
a settlement in principal ending the litigation and on
May 5, 2008, the parties executed a settlement agreement.
On May 15, 2008, the case was dismissed with prejudice
thereby ending the matter. While neither party admitted
liability in the settlement, NRG paid Spring Creek approximately
$18 million for the amount of coal it did not take in 2007
and NRGs obligation to take coal under the coal supply
agreement in the future was reduced by an identical amount. In
addition, NRG is receiving a price reduction on all remaining
tons under the coal supply agreement valued at approximately
$3 million. NRG recorded expense of $15 million in
connection with the settlement.
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.
28
On April 3, 2006, the Company made a supplemental
distribution to creditors under the Companys
Chapter 11 bankruptcy plan, totaling $25 million in
cash and 5,082,000 shares of common stock. As of
October 23, 2008, the reserve held approximately
$10 million in cash and approximately 1,319,142 shares
of common stock. NRG believes the cash and stock together
represent sufficient funds to satisfy all remaining disputed
claims. During the fourth quarter of 2008, NRG expects to file
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.
|
|
Note 15
|
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, FERC
conditionally accepted, subject to refund, the
Reliability-Must-Run, or RMR, agreement filed on April 26,
2007 by Norwalk Power for its units 1 and 2, specifying a
June 19, 2007 effective date. Norwalks RMR rate and
its eligibility for the RMR agreement, which is based upon the
facilitys projected market revenues and costs, are subject
to further proceedings. Norwalk filed for the RMR agreement in
response to FERCs order eliminating the Peaking Unit Safe
Harbor bidding mechanism which took effect on June 19,
2007. Settlement proceedings are still ongoing.
On March 18, 2008, the US Court of Appeals for the D.C.
Circuit rejected the appeal filed by the Attorneys General of
the State of Connecticut and Commonwealth of Massachusetts
regarding the settlement of the New England capacity market
design. The settlement, filed with FERC on March 7, 2006,
by a broad group of New England market participants, provides
for interim capacity transition payments for all generators in
New England for the period starting December 1, 2006
through May 31, 2010, and a Forward Capacity Market, or
FCM, for the period thereafter. All substantive challenges to
the settlement, to the validity of the interim capacity
transition payments, and to the market design were rejected by
the D.C. Circuit, although one procedural argument relating to
future challenges by non-settling parties was sustained. Several
parties sought rehearing on this issue due to concerns regarding
the sanctity of contracts. On October 6, 2008, the D.C.
Circuit denied all requests for rehearing.
New York On March 7, 2008, FERC issued
an order accepting the NYISOs proposed market reforms to
the in-city Installed Capacity, or ICAP, market, with only minor
modifications. On October 4, 2007, the NYISO had filed its
proposal for revising the ICAP market for the New York City
zone. The 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. Although FERC had established a
refund effective date of May 12, 2007, its March 7 order
determined that the NYISOs proposal should be implemented
only prospectively and that no refunds should be required. No
party sought rehearing on the refund issue, thus resolving the
contingency. On September 29, 2008, FERC issued its order
on rehearing and the NYISOs compliance filings that
substantially reaffirmed the NYISOs proposed market
reforms.
On March 15, 2006, NRG received the results from NYISO
Market Monitoring Units review of NRGS Astoria
plants 2004 Generating Availability Data System, or GADS,
reporting. On July 25, 2008, the NYISO determined that it
would assess NRG a capacity deficiency charge relating to the
Astoria plant as a result of a restatement of its GADS data for
2004. NRG agreed to and paid the NYISOs assessment.
PJM On August 23, 2007, several
entities, including the New Jersey Board of Public Utilities,
the District of Columbia Office of the Peoples Counsel,
and the Maryland Office of Peoples Counsel, filed appeals
of the FERC orders accepting the settlement of the locational
capacity market for PJM Interconnection, LLC. The settlement,
filed at FERC on September 29, 2006, provides for a
capacity market mechanism known as the Reliability Pricing
Model, or RPM, which is designed to provide a long-term price
signal through competitive forward auctions. On
December 22, 2006, FERC issued an order accepting the
settlement, which was reaffirmed on rehearing by order dated
June 25, 2007. The RPM 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.
29
On January 15, 2008, the Maryland Public Service
Commission, or MDPSC, filed at FERC a complaint against PJM
claiming that PJM had failed to adequately mitigate certain
generation resources, due to exemptions for resources used to
relieve reactive limits on interfaces or that were constructed
during certain periods after 1999. In addition to seeking an
order eliminating the exemptions and a refund effective date as
of the date of the complaint, the MDPSC sought an investigation
of periods prior to the complaint that could have led to
disgorgement by certain entities, and possibly a resettlement of
the market. On May 16, 2008, FERC issued an order granting
in part, and dismissing in part, the complaint and establishing
a proceeding to examine the justness and reasonableness of
PJMs other market power mitigation mechanisms. FERC denied
the request for retroactive relief and resettlement of the
market.
On May 30, 2008, the MDPSC, together with other load
interests, filed at 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, FERC dismissed the
complaint. The parties representing load interests have sought
rehearing of the dismissal of the complaint. In a related
proceeding, FERC directed PJM to commence stakeholder processes
towards addressing issues with RPM and required PJM to make a
filing of proposed changes to RPM no later than
December 15, 2008.
|
|
Note 16
|
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 greenhouse gas, or
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 2008
through 2013 will be approximately $1.3 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 anticipated changes in schedules and controls
related to recent court rulings that vacate both the Clean Air
Interstate Rule, or CAIR, and the Clear Air Mercury Rule, or
CAMR, the full impact on the scope and timing of environmental
retrofits from any revised
and/or
replacement regulations cannot be determined at this time.
Northeast
Region
On December 20, 2005, 10 northeastern states entered into a
Memorandum of Understanding, or MOU, to create the Regional
Greenhouse Gas Initiative, or RGGI, to establish a
cap-and-trade
GHG program for electric generators. Electric generating units
in participating RGGI states will have to procure one allowance
for every US ton of
CO2
emitted with true up for
2009-2011
occurring in 2012. NRG units located in Connecticut, Delaware,
Maryland, Massachusetts and New York emitted approximately
13 million US tons of
CO2
in 2007. NRG believes that to the extent allowance costs will
not be fully reflected in wholesale electricity prices, the
direct financial impact on the Company is likely to be negative
as costs are incurred to secure the necessary RGGI allowances
and offsets at auction and in the market.
On May 29, 2008, the Delaware Department of Natural
Resources, or 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.
30
South
Central Region
On January 27, 2004, NRGs Louisiana Generating LLC
and the Companys Big Cajun II plant received a
request under Section 114 of the Clean Air Act, or CAA,
from USEPA seeking information primarily related to physical
changes made at the Big Cajun II plant, and subsequently
received a notice of violation, or NOV, on February 15,
2005, alleging that NRGs predecessors had undertaken
projects that triggered requirements under the Prevention of
Significant Deterioration, or PSD, program, including the
installation of emission controls. NRG submitted multiple
responses commencing February 27, 2004 and ending on
October 20, 2004. On May 9, 2006, these entities
received from the Department of Justice, or DOJ, a notice of
deficiency related to their responses, to which NRG responded on
May 22, 2006. A document review was conducted at NRGs
Louisiana Generating LLC offices by the DOJ during the week of
August 14, 2006. On December 8, 2006, the USEPA issued
a supplemental NOV updating the original February 15,
2005 NOV. Discussions with the USEPA are ongoing and the
Company cannot predict with certainty the outcome of this matter.
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, operation and maintenance agreements, service
agreements, settlement agreements, and other types of
contractual agreements with vendors and other third parties.
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.
This footnote should be read in conjunction with the complete
description under Note 25, Guarantees, to the
Companys financial statements in its Annual Report on
Form 10-K
for the year ended December 31, 2007.
For the nine months ended September 30, 2008, NRG had net
increases to its guarantee obligations under other commercial
arrangements of approximately $202 million.
31
|
|
Note 18
|
Condensed
Consolidating Financial Information
|
As of September 30, 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 of
7.375% 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
September 30, 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
|
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.
|
|
|
32
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 SECs
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.
33
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Three Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
2,597
|
|
|
|
$ 111
|
|
|
|
$
|
|
|
|
$
(18
|
)
|
|
|
$ 2,690
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
919
|
|
|
|
99
|
|
|
|
(3
|
)
|
|
|
(18
|
)
|
|
|
997
|
|
|
|
Depreciation and amortization
|
|
|
148
|
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
156
|
|
|
|
General and administrative
|
|
|
16
|
|
|
|
14
|
|
|
|
45
|
|
|
|
|
|
|
|
75
|
|
|
|
Development costs
|
|
|
2
|
|
|
|
2
|
|
|
|
9
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,085
|
|
|
|
122
|
|
|
|
52
|
|
|
|
(18
|
)
|
|
|
1,241
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,512
|
|
|
|
(11
|
)
|
|
|
(52
|
)
|
|
|
|
|
|
|
1,449
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings/(losses) of consolidated subsidiaries
|
|
|
52
|
|
|
|
|
|
|
|
897
|
|
|
|
(949
|
)
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
1
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
58
|
|
|
|
Other income/(expense), net
|
|
|
4
|
|
|
|
11
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
(7
|
)
|
|
|
Interest expense
|
|
|
(46
|
)
|
|
|
(61
|
)
|
|
|
(79
|
)
|
|
|
|
|
|
|
(186
|
)
|
|
|
|
|
Total other income/(expense)
|
|
|
11
|
|
|
|
7
|
|
|
|
796
|
|
|
|
(949
|
)
|
|
|
(135
|
)
|
|
|
|
|
Income/(Losses) From Continuing Operations Before Income
Taxes
|
|
|
1,523
|
|
|
|
(4
|
)
|
|
|
744
|
|
|
|
(949
|
)
|
|
|
1,314
|
|
|
|
Income tax expense/(benefit)
|
|
|
532
|
|
|
|
38
|
|
|
|
(40
|
)
|
|
|
|
|
|
|
530
|
|
|
|
|
|
Income/(Losses) From Continuing Operations
|
|
|
991
|
|
|
|
(42
|
)
|
|
|
784
|
|
|
|
(949
|
)
|
|
|
784
|
|
|
|
Income/(Losses) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss)
|
|
$
|
991
|
|
|
|
$(42
|
)
|
|
|
$
784
|
|
|
|
$
(949
|
)
|
|
|
$784
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
34
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Nine Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,020
|
|
|
|
$
306
|
|
|
|
$
|
|
|
|
$
(18
|
)
|
|
|
$ 5,308
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
2,600
|
|
|
|
231
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
2,812
|
|
|
|
Depreciation and amortization
|
|
|
454
|
|
|
|
21
|
|
|
|
3
|
|
|
|
|
|
|
|
478
|
|
|
|
General and administrative
|
|
|
47
|
|
|
|
10
|
|
|
|
176
|
|
|
|
|
|
|
|
233
|
|
|
|
Development costs
|
|
|
(3
|
)
|
|
|
5
|
|
|
|
27
|
|
|
|
|
|
|
|
29
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,098
|
|
|
|
267
|
|
|
|
206
|
|
|
|
(19
|
)
|
|
|
3,552
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,922
|
|
|
|
39
|
|
|
|
(206
|
)
|
|
|
1
|
|
|
|
1,756
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings/(losses) of consolidated subsidiaries
|
|
|
262
|
|
|
|
|
|
|
|
1,347
|
|
|
|
(1,609
|
)
|
|
|
|
|
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
|
|
(2
|
)
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
Other income/(expense), net
|
|
|
19
|
|
|
|
10
|
|
|
|
(14
|
)
|
|
|
(1
|
)
|
|
|
14
|
|
|
|
Interest expense
|
|
|
(148
|
)
|
|
|
(95
|
)
|
|
|
(238
|
)
|
|
|
|
|
|
|
(481
|
)
|
|
|
|
|
Total other income/(expense)
|
|
|
131
|
|
|
|
(48
|
)
|
|
|
1,095
|
|
|
|
(1,610
|
)
|
|
|
(432
|
)
|
|
|
|
|
Income/(Losses) From Continuing Operations Before Income
Taxes
|
|
|
2,053
|
|
|
|
(9
|
)
|
|
|
889
|
|
|
|
(1,609
|
)
|
|
|
1,324
|
|
|
|
Income tax expense/(benefit)
|
|
|
699
|
|
|
|
5
|
|
|
|
(173
|
)
|
|
|
|
|
|
|
531
|
|
|
|
|
|
Income/(Losses) From Continuing Operations
|
|
|
1,354
|
|
|
|
(14
|
)
|
|
|
1,062
|
|
|
|
(1,609
|
)
|
|
|
793
|
|
|
|
Income/(Losses) from discontinued operations, net of income taxes
|
|
|
|
|
|
|
269
|
|
|
|
(97
|
)
|
|
|
|
|
|
|
172
|
|
|
|
|
|
Net Income/(Loss)
|
|
$
|
1,354
|
|
|
|
$
255
|
|
|
|
$
965
|
|
|
|
$
(1,609
|
)
|
|
|
$ 965
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
35
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING BALANCE SHEETS
September 30,
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG Energy, Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2
|
|
|
$
|
182
|
|
|
$
|
1,299
|
|
|
$
|
|
|
|
$
|
1,483
|
|
|
|
Restricted cash
|
|
|
1
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
|
|
Accounts receivable, net
|
|
|
487
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
531
|
|
|
|
Inventory
|
|
|
444
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
456
|
|
|
|
Derivative instruments valuation
|
|
|
4,190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,190
|
|
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
544
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
544
|
|
|
|
Prepayments and other current assets
|
|
|
79
|
|
|
|
35
|
|
|
|
382
|
|
|
|
(293
|
)
|
|
|
203
|
|
|
|
|
|
Total current assets
|
|
|
5,747
|
|
|
|
304
|
|
|
|
1,681
|
|
|
|
(293
|
)
|
|
|
7,439
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
10,752
|
|
|
|
696
|
|
|
|
24
|
|
|
|
|
|
|
|
11,472
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
659
|
|
|
|
19
|
|
|
|
10,936
|
|
|
|
(11,614
|
)
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
26
|
|
|
|
402
|
|
|
|
|
|
|
|
|
|
|
|
428
|
|
|
|
Notes receivable and capital lease, less current portion
|
|
|
535
|
|
|
|
450
|
|
|
|
2,889
|
|
|
|
(3,424
|
)
|
|
|
450
|
|
|
|
Goodwill
|
|
|
1,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,786
|
|
|
|
Intangible assets, net
|
|
|
808
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
822
|
|
|
|
Nuclear decommissioning trust
|
|
|
333
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
333
|
|
|
|
Derivative instruments valuation
|
|
|
816
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
816
|
|
|
|
Other non-current assets
|
|
|
6
|
|
|
|
3
|
|
|
|
125
|
|
|
|
|
|
|
|
134
|
|
|
|
Intangible assets
held-for-sale
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
Total other assets
|
|
|
4,972
|
|
|
|
888
|
|
|
|
13,950
|
|
|
|
(15,038
|
)
|
|
|
4,772
|
|
|
|
|
|
Total Assets
|
|
$
|
21,471
|
|
|
$
|
1,888
|
|
|
$
|
15,655
|
|
|
$
|
(15,331
|
)
|
|
$
|
23,683
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
83
|
|
|
$
|
90
|
|
|
$
|
31
|
|
|
$
|
(82
|
)
|
|
$
|
122
|
|
|
|
Accounts payable
|
|
|
(293
|
)
|
|
|
648
|
|
|
|
12
|
|
|
|
|
|
|
|
367
|
|
|
|
Derivative instruments valuation
|
|
|
4,011
|
|
|
|
10
|
|
|
|
1
|
|
|
|
|
|
|
|
4,022
|
|
|
|
Deferred income taxes
|
|
|
|
|
|
|
19
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
16
|
|
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
154
|
|
|
|
Accrued expenses and other current liabilities
|
|
|
422
|
|
|
|
36
|
|
|
|
381
|
|
|
|
(210
|
)
|
|
|
629
|
|
|
|
|
|
Total current liabilities
|
|
|
4,377
|
|
|
|
803
|
|
|
|
422
|
|
|
|
(292
|
)
|
|
|
5,310
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
2,808
|
|
|
|
824
|
|
|
|
7,852
|
|
|
|
(3,425
|
)
|
|
|
8,059
|
|
|
|
Nuclear decommissioning reserve
|
|
|
320
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
320
|
|
|
|
Nuclear decommissioning trust liability
|
|
|
252
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
252
|
|
|
|
Deferred income taxes
|
|
|
659
|
|
|
|
(172
|
)
|
|
|
596
|
|
|
|
|
|
|
|
1,083
|
|
|
|
Derivative instruments valuation
|
|
|
1,089
|
|
|
|
17
|
|
|
|
52
|
|
|
|
|
|
|
|
1,158
|
|
|
|
Out-of-market
contracts
|
|
|
336
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
336
|
|
|
|
Other non-current liabilities
|
|
|
360
|
|
|
|
65
|
|
|
|
143
|
|
|
|
|
|
|
|
568
|
|
|
|
|
|
Total non-current liabilities
|
|
|
5,824
|
|
|
|
734
|
|
|
|
8,643
|
|
|
|
(3,425
|
)
|
|
|
11,776
|
|
|
|
|
|
Total liabilities
|
|
|
10,201
|
|
|
|
1,537
|
|
|
|
9,065
|
|
|
|
(3,717
|
)
|
|
|
17,086
|
|
|
|
|
|
Minority interest
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
247
|
|
|
|
Stockholders Equity
|
|
|
11,263
|
|
|
|
351
|
|
|
|
6,343
|
|
|
|
(11,614
|
)
|
|
|
6,343
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
21,471
|
|
|
$
|
1,888
|
|
|
$
|
15,655
|
|
|
$
|
(15,331
|
)
|
|
$
|
23,683
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
36
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the
Nine Months Ended September 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$1,354
|
|
|
|
$ 255
|
|
|
|
$ 965
|
|
|
|
$ (1,609
|
)
|
|
|
$ 965
|
|
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity in (earnings)/losses of unconsolidated
affiliates and consolidated subsidiaries
|
|
|
(260
|
)
|
|
|
(26
|
)
|
|
|
(1,347
|
)
|
|
|
1,609
|
|
|
|
(24
|
)
|
|
|
Depreciation and amortization
|
|
|
454
|
|
|
|
21
|
|
|
|
3
|
|
|
|
|
|
|
|
478
|
|
|
|
Amortization of nuclear fuel
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31
|
|
|
|
Amortization of financing costs and debt discount
|
|
|
|
|
|
|
5
|
|
|
|
17
|
|
|
|
|
|
|
|
22
|
|
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
(226
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(226
|
)
|
|
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
102
|
|
|
|
(21
|
)
|
|
|
346
|
|
|
|
|
|
|
|
427
|
|
|
|
Changes in nuclear decommissioning liability
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
Changes in derivatives
|
|
|
(101
|
)
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
(110
|
)
|
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(320
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(320
|
)
|
|
|
Loss on disposal and sales of assets
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
|
|
Gain on sale of emission allowances
|
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(52
|
)
|
|
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
|
|
|
|
21
|
|
|
|
Cash provided by/(used by) changes in other working capital
|
|
|
473
|
|
|
|
52
|
|
|
|
(444
|
)
|
|
|
|
|
|
|
81
|
|
|
|
|
|
Net Cash Provided (Used) by Operating Activities
|
|
|
1,476
|
|
|
|
4
|
|
|
|
(439
|
)
|
|
|
|
|
|
|
1,041
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
(175
|
)
|
|
|
|
|
|
|
885
|
|
|
|
(710
|
)
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(444
|
)
|
|
|
(200
|
)
|
|
|
(5
|
)
|
|
|
|
|
|
|
(649
|
)
|
|
|
Increase in restricted cash
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
35
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
20
|
|
|
|
Purchases of emission allowances
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
Proceeds from sale of emission allowances
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
|
|
Investment in nuclear decomissioning trust fund securities
|
|
|
(441
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(441
|
)
|
|
|
Proceeds from sales of nuclear decomissioning trust fund
securities
|
|
|
434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
434
|
|
|
|
Proceeds from sale of discontinued operations, net of cash
divested
|
|
|
|
|
|
|
(59
|
)
|
|
|
300
|
|
|
|
|
|
|
|
241
|
|
|
|
Proceeds from sale of assets
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
Equity investments in unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
(17
|
)
|
|
|
|
|
Net Cash Provided (Used) by Investing Activities
|
|
|
(543
|
)
|
|
|
(227
|
)
|
|
|
1,148
|
|
|
|
(710
|
)
|
|
|
(332
|
)
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds for intercompany loans
|
|
|
(882
|
)
|
|
|
208
|
|
|
|
(36
|
)
|
|
|
710
|
|
|
|
|
|
|
|
Payments for dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(41
|
)
|
|
|
|
|
|
|
(41
|
)
|
|
|
Payment of financing element of acquired derivatives
|
|
|
(49
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
Payments for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
(185
|
)
|
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
|
|
|
|
8
|
|
|
|
Proceeds from sale of minority interest in subsidiary
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
Payments for deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
Payments for short and long-term debt
|
|
|
|
|
|
|
(36
|
)
|
|
|
(166
|
)
|
|
|
|
|
|
|
(202
|
)
|
|
|
|
|
Net Cash Provided (Used) by Financing Activities
|
|
|
(931
|
)
|
|
|
242
|
|
|
|
(422
|
)
|
|
|
710
|
|
|
|
(401
|
)
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Cash Equivalent
|
|
|
2
|
|
|
|
62
|
|
|
|
287
|
|
|
|
|
|
|
|
351
|
|
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
|
|
|
|
120
|
|
|
|
1,012
|
|
|
|
|
|
|
|
1,132
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
|
$ 2
|
|
|
|
$ 182
|
|
|
|
$ 1,299
|
|
|
|
$
|
|
|
|
$ 1,483
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
37
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Three Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
1,676
|
|
|
|
$
96
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
1,772
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
868
|
|
|
|
73
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
939
|
|
|
|
Depreciation and amortization
|
|
|
153
|
|
|
|
4
|
|
|
|
3
|
|
|
|
|
|
|
|
160
|
|
|
|
General and administrative
|
|
|
34
|
|
|
|
5
|
|
|
|
39
|
|
|
|
|
|
|
|
78
|
|
|
|
Development costs
|
|
|
30
|
|
|
|
1
|
|
|
|
18
|
|
|
|
|
|
|
|
49
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,085
|
|
|
|
83
|
|
|
|
58
|
|
|
|
|
|
|
|
1,226
|
|
|
|
Gain/(Loss) on sale of assets
|
|
|
(1
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
590
|
|
|
|
13
|
|
|
|
(57
|
)
|
|
|
|
|
|
|
546
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
60
|
|
|
|
|
|
|
|
359
|
|
|
|
(419
|
)
|
|
|
|
|
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
|
|
1
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
Other income, net
|
|
|
3
|
|
|
|
3
|
|
|
|
13
|
|
|
|
(5
|
)
|
|
|
14
|
|
|
|
Interest expense
|
|
|
(60
|
)
|
|
|
(19
|
)
|
|
|
(95
|
)
|
|
|
5
|
|
|
|
(169
|
)
|
|
|
|
|
Total other income/(expense)
|
|
|
4
|
|
|
|
2
|
|
|
|
277
|
|
|
|
(419
|
)
|
|
|
(136
|
)
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
594
|
|
|
|
15
|
|
|
|
220
|
|
|
|
(419
|
)
|
|
|
410
|
|
|
|
Income tax expense/(benefit)
|
|
|
216
|
|
|
|
(23
|
)
|
|
|
(48
|
)
|
|
|
|
|
|
|
145
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
378
|
|
|
|
38
|
|
|
|
268
|
|
|
|
(419
|
)
|
|
|
265
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
|
|
Net Income
|
|
$
|
378
|
|
|
|
$
41
|
|
|
|
$
268
|
|
|
|
$
(419
|
)
|
|
|
$
268
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
38
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Nine Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
4,326
|
|
|
|
$ 281
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$ 4,607
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
2,346
|
|
|
|
213
|
|
|
|
1
|
|
|
|
|
|
|
|
2,560
|
|
|
|
Depreciation and amortization
|
|
|
460
|
|
|
|
17
|
|
|
|
4
|
|
|
|
|
|
|
|
481
|
|
|
|
General and administrative
|
|
|
80
|
|
|
|
14
|
|
|
|
140
|
|
|
|
|
|
|
|
234
|
|
|
|
Development costs
|
|
|
85
|
|
|
|
1
|
|
|
|
22
|
|
|
|
|
|
|
|
108
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
2,971
|
|
|
|
245
|
|
|
|
167
|
|
|
|
|
|
|
|
3,383
|
|
|
|
Gain/(loss) on sale of assets
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,371
|
|
|
|
36
|
|
|
|
(167
|
)
|
|
|
|
|
|
|
1,240
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
114
|
|
|
|
|
|
|
|
768
|
|
|
|
(882
|
)
|
|
|
|
|
|
|
Equity in (losses)/earnings of unconsolidated affiliates
|
|
|
(2
|
)
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
|
Other income, net
|
|
|
7
|
|
|
|
22
|
|
|
|
30
|
|
|
|
(15
|
)
|
|
|
44
|
|
|
|
Refinancing expense
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
(35
|
)
|
|
|
Interest expense
|
|
|
(198
|
)
|
|
|
(63
|
)
|
|
|
(274
|
)
|
|
|
15
|
|
|
|
(520
|
)
|
|
|
|
|
Total other income/(expense)
|
|
|
(79
|
)
|
|
|
1
|
|
|
|
489
|
|
|
|
(882
|
)
|
|
|
(471
|
)
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
1,292
|
|
|
|
37
|
|
|
|
322
|
|
|
|
(882
|
)
|
|
|
769
|
|
|
|
Income tax expense/(benefit)
|
|
|
472
|
|
|
|
(12
|
)
|
|
|
(160
|
)
|
|
|
|
|
|
|
300
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
820
|
|
|
|
49
|
|
|
|
482
|
|
|
|
(882
|
)
|
|
|
469
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
|
|
Net Income
|
|
$
|
820
|
|
|
|
$ 62
|
|
|
|
$ 482
|
|
|
$
|
$ (882
|
)
|
|
|
$ 482
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
39
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING BALANCE SHEETS
December 31,
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG Energy
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
|
ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
|
|
|
$
|
120
|
|
|
$
|
1,012
|
|
|
$
|
|
|
|
$
|
1,132
|
|
|
|
Restricted cash
|
|
|
1
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
29
|
|
|
|
Accounts receivable, 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
|
|
|
|
Notes receivable
|
|
|
360
|
|
|
|
126
|
|
|
|
3,779
|
|
|
|
(4,139
|
)
|
|
|
126
|
|
|
|
Capital lease, less current portion
|
|
|
|
|
|
|
365
|
|
|
|
|
|
|
|
|
|
|
|
365
|
|
|
|
Goodwill
|
|
|
1,786
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,786
|
|
|
|
Intangible assets, net
|
|
|
859
|
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
873
|
|
|
|
Intangible assets
held-for-sale
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
|
|
Nuclear decommissioning trust fund
|
|
|
384
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
384
|
|
|
|
Derivative instruments valuation
|
|
|
150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150
|
|
|
|
Other non-current assets
|
|
|
11
|
|
|
|
1
|
|
|
|
164
|
|
|
|
|
|
|
|
176
|
|
|
|
Non-current assets discontinued operations
|
|
|
|
|
|
|
93
|
|
|
|
|
|
|
|
|
|
|
|
93
|
|
|
|
|
|
Total other assets
|
|
|
4,202
|
|
|
|
996
|
|
|
|
13,730
|
|
|
|
(14,536
|
)
|
|
|
4,392
|
|
|
|
|
|
Total Assets
|
|
$
|
17,270
|
|
|
$
|
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
|
|
|
|
Non-current
out-of-market
contracts
|
|
|
628
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
628
|
|
|
|
Other non-current liabilities
|
|
|
377
|
|
|
|
10
|
|
|
|
25
|
|
|
|
|
|
|
|
412
|
|
|
|
Non-current liabilities discontinued operations
|
|
|
|
|
|
|
76
|
|
|
|
|
|
|
|
|
|
|
|
76
|
|
|
|
|
|
Total non-current liabilities
|
|
|
6,699
|
|
|
|
535
|
|
|
|
8,151
|
|
|
|
(4,139
|
)
|
|
|
11,246
|
|
|
|
|
|
Total liabilities
|
|
|
7,338
|
|
|
|
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. |
40
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF CASH FLOWS
For the
Nine Months Ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
(In millions)
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
821
|
|
|
$
|
61
|
|
|
$
|
482
|
|
|
$
|
(882
|
)
|
|
$
|
482
|
|
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity (earnings)/losses of unconsolidated
affiliates and consolidated subsidiaries
|
|
|
190
|
|
|
|
(25
|
)
|
|
|
(466
|
)
|
|
|
278
|
|
|
|
(23
|
)
|
|
|
Depreciation and amortization
|
|
|
459
|
|
|
|
20
|
|
|
|
4
|
|
|
|
|
|
|
|
483
|
|
|
|
Amortization of nuclear fuel
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42
|
|
|
|
Amortization of financing costs and debt discount
|
|
|
|
|
|
|
5
|
|
|
|
54
|
|
|
|
|
|
|
|
59
|
|
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
(116
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
(112
|
)
|
|
|
Changes in deferred income taxes
|
|
|
63
|
|
|
|
(40
|
)
|
|
|
209
|
|
|
|
|
|
|
|
232
|
|
|
|
Changes in nuclear decommissioning trust liability
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
Changes in derivatives
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(107
|
)
|
|
|
Gain on disposal and sale of assets
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(16
|
)
|
|
|
Gain on sale of emission allowances
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(31
|
)
|
|
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
|
|
Cash (used)/provided by changes in other working capital
|
|
|
(88
|
)
|
|
|
128
|
|
|
|
(156
|
)
|
|
|
|
|
|
|
(116
|
)
|
|
|
|
|
Net Cash (Used)/Provided by Operating Activities
|
|
|
1,281
|
|
|
|
153
|
|
|
|
146
|
|
|
|
(604
|
)
|
|
|
976
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
(81
|
)
|
|
|
(18
|
)
|
|
|
754
|
|
|
|
(655
|
)
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(210
|
)
|
|
|
(93
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
(309
|
)
|
|
|
Increase in restricted cash
|
|
|
|
|
|
|
(18
|
)
|
|
|
|
|
|
|
|
|
|
|
(18
|
)
|
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
Purchases of emission allowances
|
|
|
(152
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(152
|
)
|
|
|
Proceeds from the sale of emission allowances
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
Investment in nuclear decommissioning trust fund securities
|
|
|
(193
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(193
|
)
|
|
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
170
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
170
|
|
|
|
Proceeds from the sale of assets
|
|
|
29
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
57
|
|
|
|
Decrease in trust fund balances
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
Other
|
|
|
|
|
|
|
2
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
Net Cash (Used)/Provided by Investing Activities
|
|
|
(248
|
)
|
|
|
(101
|
)
|
|
|
772
|
|
|
|
(655
|
)
|
|
|
(232
|
)
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments/proceeds for intercompany loans
|
|
|
(754
|
)
|
|
|
|
|
|
|
99
|
|
|
|
655
|
|
|
|
|
|
|
|
Payments from intercompany dividends
|
|
|
(302
|
)
|
|
|
(302
|
)
|
|
|
|
|
|
|
604
|
|
|
|
|
|
|
|
Payment for dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(41
|
)
|
|
|
|
|
|
|
(41
|
)
|
|
|
Payments for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(268
|
)
|
|
|
|
|
|
|
(268
|
)
|
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
|
|
|
|
1,411
|
|
|
|
|
|
|
|
1,411
|
|
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
Payments for short and long-term debt
|
|
|
(1
|
)
|
|
|
(36
|
)
|
|
|
(1,435
|
)
|
|
|
|
|
|
|
(1,472
|
)
|
|
|
|
|
Net Cash (Used)/Provided by Financing Activities
|
|
|
(1,057
|
)
|
|
|
(338
|
)
|
|
|
(239
|
)
|
|
|
1,259
|
|
|
|
(375
|
)
|
|
|
|
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
Change in Cash from Discontinued Operations
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
|
|
|
|
|
|
(16
|
)
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
(24
|
)
|
|
|
(295
|
)
|
|
|
679
|
|
|
|
|
|
|
|
360
|
|
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
20
|
|
|
|
414
|
|
|
|
343
|
|
|
|
|
|
|
|
777
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
(4
|
)
|
|
$
|
119
|
|
|
$
|
1,022
|
|
|
$
|
|
|
|
$
|
1,137
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been
eliminated in consolidation. |
41
|
|
ITEM 2
|
MANAGEMENTS
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
|
Introduction
and Overview
NRG Energy, Inc., or NRG, or the Company, is a wholesale power
generation company with a significant presence in major
competitive power markets in the United States. NRG is primarily
engaged in the ownership, development, construction and
operation of power generation facilities, the transacting in and
trading of fuel and transportation services, and the trading of
energy, capacity and related products in the United States and
select international markets. As of September 30, 2008, NRG
had a total global portfolio of 189 active operating generation
units at 48 power generation plants, with an aggregate
generation capacity of approximately 24,020 MW and
approximately 472 MW under construction. Within the United
States, NRG has one of the largest and most diversified power
generation portfolios in terms of geography, fuel-type and
dispatch levels, with approximately 22,940 MW of generation
capacity in 177 active generating units at 43 plants. These
power generation facilities are primarily located in Texas
(approximately 10,815 MW), the Northeast (approximately
7,020 MW), South Central (approximately 2,860 MW), and
the West (approximately 2,130 MW) regions of the United
States, with approximately 115 MW of additional generation
capacity from the Companys thermal assets. NRGs
principal domestic power plants consist of a mix of natural
gas-, coal-, oil-fired and nuclear facilities, representing
approximately 46%, 33%, 16% and 5% of the Companys total
domestic generation capacity, respectively. In addition, 15% of
NRGs domestic generating facilities have dual or multiple
fuel capacity, which allows plants to dispatch with the lowest
cost fuel option, and consist primarily of baseload,
intermediate and peaking power generation facilities, the
ranking of which is referred to as the Merit Order, and also
include thermal energy production plants. The sale of capacity
and power from baseload generation facilities accounts for the
majority of the Companys revenues. 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.
The Companys strategy is reflected in five major
initiatives, described below. These initiatives are designed to
enable the Company to take advantage of opportunities and
surmount the challenges faced by the power industry.
1. |
FORNRG is a companywide effort designed to
increase the return on invested capital, or ROIC, through
operational performance improvements to the Companys asset
fleet, along with a range of initiatives at plants and at
corporate offices to reduce costs, or in some cases, monetize or
reduce excess working capital and other assets. The
FORNRG accomplishments disclosed in NRGs SEC
filings and press releases 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.
During 2007, the Company announced the acceleration and planned
conclusion of the FORNRG 1.0 program by bringing forward
the previously announced 2009 target of $250 million to
2008. Improvements in reliability throughout the baseload fleet,
coupled with higher gross margins, especially in the Texas
region, were the drivers of the
year-to-date
program performance. Through September 2008, the Company has
estimated the cumulative value of implemented FORNRG
improvements will achieve a value in excess of the established
a goal of $250 million by December 31, 2008. 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 will transition to
FORNRG 2.0 and target an incremental 100 basis point
improvement to the Companys return on invested capital by
2012. The initial targets for FORNRG 2.0 will be based
upon improvements in the Companys ROIC as measured by
increased cash flow. The economic results of FORNRG 2.0
will focus on: (1) revenue enhancement, (2) cost
savings, and (3) asset optimization including reducing
excess working capital and other assets. 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
2006-2008.
|
2. | 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.
|
42
3. |
econrg represents NRGs commitment to
environmentally responsible power generation. econrg seeks to
find ways for NRG to meet 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 our employees.
|
4. |
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.
|
5. |
NRG
Global Giving Respect for the
community 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.
|
NRGs 2007 Annual Report on
Form 10-K
includes a detailed discussion of various items impacting its
business, results of operations and financial condition. These
include:
|
|
|
|
|
Introduction and Overview section which provides a
description of NRGs business segments;
|
|
|
|
Strategy section;
|
|
|
|
Business Environment section, including how regulation,
weather, and other factors affect NRGs business; and
|
|
|
|
Critical Accounting Policies section.
|
Critical accounting policies are the accounting policies that
are most important to the portrayal of NRGs financial
condition and results of operations and require
managements most difficult, subjective or complex
judgment. NRGs critical accounting policies include
revenue recognition and derivative accounting, income taxes and
valuation allowance for deferred taxes, evaluation of assets for
impairment and other than temporary decline in value, goodwill
and other intangible assets, and contingencies.
This discussion and analysis explains the general financial
condition and the results of operations for NRG, including:
|
|
|
|
|
factors which affect the business;
|
|
|
|
earnings and costs in the periods presented;
|
|
|
|
changes in earnings and costs between periods;
|
|
|
|
sources of earnings;
|
|
|
|
impact of these factors on NRGs overall financial
condition;
|
|
|
|
expected future expenditures for capital projects; and
|
|
|
|
expected sources of cash for further operations and capital
expenditures.
|
43
As you read this discussion and analysis, refer to the
consolidated statements of income which present the results of
operations for the three and nine months ended
September 30, 2008 and 2007. NRG analyzes and explains the
differences between periods in the specific line items of the
consolidated statements of income.
NRG has organized the discussion and analysis as follows:
|
|
|
|
|
changes to the business environment during the period;
|
|
|
|
results of operations beginning with an overview of
NRGs consolidated results, followed by a more detailed
discussion of those results by major operating segment;
|
|
|
|
financial condition, addressing liquidity, the sources and
uses of cash, capital resources and commitments; and
|
|
|
|
known trends that will affect NRGs results of operation
and financial condition in the future.
|
Changes
in Accounting Standards
See Note 1 to the condensed consolidated financial
statements of this
Form 10-Q
as found in Item 1 for a discussion of recent accounting
developments.
Business
Environment Financial Credit Market Availability and
Domestic Recessionary Pressures
A sharp economic downturn in the US and overseas during the
latter part of 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 in general prompting fears of an 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 $3.0 billion in total liquidity, 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 Part 1,
Item 1 Liquidity and Capital Resources,
and Part 1, Item 3 Quantitative and
Qualitative Disclosures about Market Risk for further
discussion.
Unsolicited
Exelon Proposal
On October 19, 2008, NRG received an unsolicited proposal
from Exelon Corporation to acquire all of the outstanding shares
of NRG at a fixed exchange ratio of 0.485 Exelon shares for each
NRG common share. NRGs Board of Directors is reviewing
Exelons proposal with their advisors and will determine
the appropriate response in due course. As of the date of the
filing of this quarterly report, NRG stockholders have been
advised to take no action at this time pending the review by
NRGs Board of Directors.
Environmental
Matters
Carbon
Update
At the national level and at various regional and state levels,
policies are under development to regulate GHG emissions,
including
CO2,
thereby effectively putting a cost on such emissions in order to
create financial incentives to reduce them. The Northeast states
are furthest along where six of ten participating states held
the first
CO2
allowances auction on September 25, 2008. The effective
start date is January 1, 2009. California under legislation
enacted in 2007 known as AB32, the seven states and four
Canadian provinces in the Western Climate Initiative, and the
six states in the Midwest GHG Accord continue to develop market
based programs for their respective jurisdictions. It is almost
certain that all GHG regulatory schemes will encompass power
plants. The impact on the Companys financial performance
will depend on a number of factors, including the overall level
of GHG reductions required under any such regulation, the price
and availability of offsets, and the extent to which NRG would
be entitled to receive GHG emissions allowances without having
to purchase them in an auction or on the open market. Despite
current fiscal and economic concerns, Congressional leaders
continue to seek an approach to national climate change
legislation that will gain the support necessary to become law.
In October 2008, Representatives Boucher and Dingell introduced
a climate change discussion draft into Congress that, along with
basic cap and trade architecture, offers a menu of options for
dealing with a number of important details
44
such as allocations and factors that could affect allowance
price. In addition, the climate change discussion draft
continues the trend of all major climate legislation in Congress
to provide significant support for low carbon investments such
as those involved in the Companys RepoweringNRG and
econrg programs. Information regarding the Companys carbon
strategy is discussed in greater detail in Part I,
Item 1, Carbon Update in NRG Energy, Inc.s 2007
Annual Report on
Form 10-K
for the fiscal year ended December 31, 2007.
On April 2, 2007, the US Supreme Court issued a decision in
Massachusetts v. EPA that the USEPA has authority under
Title II of the Clean Air Act or CAA to regulate
CO2
emissions from new motor vehicles. The actual treatment of
CO2
under the CAA is contingent upon an official finding by the
USEPA on whether these emissions endanger public health and the
environment. While such a finding, based on the Supreme Court
decision, would be specific to mobile sources, the outcome would
also be applicable to the regulation of stationary sources
including electric generating units. On July 30, 2008, the
USEPA released an Advance Notice of Proposed Rulemaking, or
ANPR, inviting public comment on the benefits and ramifications
of regulating GHG emissions under the CAA with comments due to
EPA by November 28, 2008. Given this schedule it appears
unlikely that there will be any regulation of
CO2
under the CAA during the remainder of 2008. At this time, NRG
cannot predict the outcome of the ANPR process, any resulting
changes to federal regulations, nor the impact on Company
operations.
Federal
Environmental Initiatives
On May 18, 2005, the USEPA published the Clean Air Mercury
Rule, or CAMR, to permanently cap and reduce mercury emissions
from coal-fired power plants. CAMR imposed limits on mercury
emissions from new and existing coal-fired plants and created a
market-based
cap-and-trade
program to reduce nationwide emissions of mercury. The rule was
challenged by New Jersey and ten other states. On
February 8, 2008, the US Court of Appeals for the D.C.
Circuit vacated USEPAs rule delisting coal- and oil-fired
electric generating units from regulation under CAA
§ 112, or the Delisting Rule, and CAMR. Power plant
emissions are now subject to Section 112 of the CAA which
requires installation of maximum achievable control technology,
or MACT, to reduce emissions. The USEPA plans to develop MACT
standards and existing power plants will need to provide plans
to meet the new requirements. Certain states in which NRG
operates coal plants, such as Delaware, Massachusetts and New
York, adopted state implementation plans in lieu of the CAMR
federal implementation plan and these state rules remain
unchanged. Texas and Louisiana adopted the federal CAMR.
On May 12, 2005, the USEPA published the market based Clean
Air Interstate Rule, or CAIR. This rule applied to 28 eastern
states and the District of Columbia, or D.C., and capped both
SO2
and
NOx
emissions from power plants in two phases; 2010 and 2015 for
SO2
and 2009 and 2015 for
NOx.
CAIR applies to some of the Companys power plants in New
York, Massachusetts, Connecticut, Delaware, Louisiana, Illinois,
Pennsylvania, Maryland and Texas. On July 11, 2008, the
D.C. Circuit Court ruled that CAIR should be vacated in its
entirety. The USEPA petitioned for rehearing en banc on
September 24, 2008. The D.C. Circuit Court must grant or
deny the petition over the next few months after which it will
be reheard or the USEPA can appeal for a hearing before the
Supreme Court. The Court has not yet stayed the rule leaving
January 1, 2009 as the effective date for the CAIR annual
and seasonal
NOx
trading program. NRGs
SO2
and
NOx
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 rate of
spending for environmental retrofits at our facilities.
On September 30, 2008, the NRG Texas region held a bank of
emissions allowances with a net carrying value of
$748 million, consisting of $504 million for
SO2
and $244 million for
NOx.
These are classified as long-term intangible assets and are
carried at average cost. The D.C. Circuit Court ruling has
resulted in a decline in current
SO2
market prices. NRG has estimated its
SO2
allowance requirement needed for generation based on the new
ruling and evaluated any excess
SO2
allowances for potential impairment. Variability in generation
assumptions and any ensuing regulations or legislation will
alter our assumed rate of excess
SO2
allowances. NRG does not expect that CAIR and the D.C. Circuit
Court ruling will have a material impact on the carrying value
of our excess
SO2
allowances.
On March 12, 2008, 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. The USEPA plans to finalize ozone non-attainment
regions by March 2010 and states would likely submit plans to
come into attainment by 2013. The Company is unable to predict
with certainty the impact of the states future
recommendations on NRGs operations.
45
Regional
Environmental Initiatives
Northeast Region On December 20, 2005,
10 northeastern states entered into a Memorandum of
Understanding, or MOU, to create the Regional Greenhouse Gas
Initiative, or RGGI, to establish a
cap-and-trade
GHG program for electric generators. Electric generating units
in participating RGGI states will have to procure one allowance
for every US ton of
CO2
emitted with true up for
2009-2011
occurring in 2012. NRG units located in Connecticut, Delaware,
Maryland, Massachusetts and New York emitted approximately
13 million US tons of
CO2
in 2007. NRG believes that to the extent allowance costs
will not be fully reflected in wholesale electricity prices, the
direct financial impact on the Company is likely to be negative
as costs are incurred to secure the necessary RGGI allowances
and offsets at auction and in the market.
Regulatory
Matters
As an operator of power plants and a participant in the
wholesale markets, NRG is subject to regulation by various
federal and state government agencies. 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. In some of NRGs regions, interested parties have
advocated for 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 in order to reduce their market share. 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.
Northeast
Region
New England On July 1, 2008, ISO-NE
filed proposed revisions to its market rules tariff addressing
the compensation for units needed for reliability purposes after
June 1, 2010 (the scheduled date for the implementation of
the forward capacity market). These rule changes will impact
NRGs units that have operated pursuant to RMR agreements
and that seek to delist in the forward capacity auctions such as
Norwalk Powers units 1 and 2 which submitted a delist bid
in the first forward capacity auction. On October 28, 2008,
FERC determined that units, such as Norwalk Powers units,
that submitted a dynamic delist bid that was rejected by ISO-NE for
reliability reasons should be required to operate at their bid
amount, not a cost of service rate, notwithstanding mitigation rules
that restricted the ability of the units to submit a higher delist
bid. As a result, the Norwalk Power units will be compensated at
their delist bid of $5.99/kw-mo. for the first FCM capacity year.
On October 20, 2008, Northeast Utilities Service Company,
or NU, the parent company of Connecticut Light and Power, 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, a
significant reinforcement of the 345 kV transmission system. If
constructed, the NEEWS line will increase the import capacity
into Connecticut by approximately 1,100 MW.
New York On March 7, 2008, 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.
Texas
Region
ERCOT has adopted Texas Nodal Protocols that will
revise the wholesale market design to incorporate locational
marginal pricing (in place of the current ERCOT zonal market).
Major elements of the Texas Nodal Protocols include the
continued capability for bilateral contracting of energy and
ancillary services, a financially binding day-ahead market,
resource-specific energy and ancillary service bid curves, the
direct assignment of all congestion rents, nodal energy prices
for resources, aggregation of nodal to zonal energy prices for
loads, congestion revenue rights (including pre-assignment for
public power entities), and pricing safeguards. The Public
Utility Commission of Texas, or 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, ERCOT announced that it would delay the
implementation of the Texas Nodal Protocols, and has not
provided a new target implementation date.
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, ERCOT enacted revised
protocols, effective June 9, 2008, for addressing such
zonal congestion, providing 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, 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.
46
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 ERCOT. The PUCT issued its written
order on August 15, 2008.
West
Region
CAISO has indicated that its Market Redesign and Technology
Upgrade, or MRTU, program will not be implemented before
February 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 22, 2008, 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 imposing. The Company is
proceeding with preparation of a station power plan for
submission to the California Public Utility Commission, or CPUC,
and expects to realize savings in operation costs as a result of
this order.
47
Consolidated
Results of Operations
The following table provides selected financial information for
the Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
2008
|
|
|
2007
|
|
|
Change%
|
|
|
2008
|
|
|
2007
|
|
|
Change%
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
1,373
|
|
|
$
|
1,264
|
|
|
|
9
|
%
|
|
$
|
3,671
|
|
|
$
|
3,255
|
|
|
|
13
|
%
|
|
|
Capacity revenue
|
|
|
356
|
|
|
|
328
|
|
|
|
9
|
|
|
|
1,037
|
|
|
|
890
|
|
|
|
17
|
|
|
|
Risk management activities
|
|
|
822
|
|
|
|
35
|
|
|
|
N/A
|
|
|
|
105
|
|
|
|
44
|
|
|
|
139
|
|
|
|
Contract amortization
|
|
|
76
|
|
|
|
66
|
|
|
|
15
|
|
|
|
233
|
|
|
|
185
|
|
|
|
26
|
|
|
|
Thermal revenue
|
|
|
26
|
|
|
|
27
|
|
|
|
(4
|
)
|
|
|
85
|
|
|
|
97
|
|
|
|
(12
|
)
|
|
|
Other revenues
|
|
|
37
|
|
|
|
52
|
|
|
|
(29
|
)
|
|
|
177
|
|
|
|
136
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
2,690
|
|
|
|
1,772
|
|
|
|
52
|
|
|
|
5,308
|
|
|
|
4,607
|
|
|
|
15
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
997
|
|
|
|
939
|
|
|
|
6
|
|
|
|
2,812
|
|
|
|
2,560
|
|
|
|
10
|
|
|
|
Depreciation and amortization
|
|
|
156
|
|
|
|
160
|
|
|
|
(3
|
)
|
|
|
478
|
|
|
|
481
|
|
|
|
(1
|
)
|
|
|
General and administrative
|
|
|
75
|
|
|
|
78
|
|
|
|
(4
|
)
|
|
|
233
|
|
|
|
234
|
|
|
|
|
|
|
|
Development costs
|
|
|
13
|
|
|
|
49
|
|
|
|
(73
|
)
|
|
|
29
|
|
|
|
108
|
|
|
|
(73
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
1,241
|
|
|
|
1,226
|
|
|
|
1
|
|
|
|
3,552
|
|
|
|
3,383
|
|
|
|
5
|
|
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
1,449
|
|
|
|
546
|
|
|
|
165
|
|
|
|
1,756
|
|
|
|
1,240
|
|
|
|
42
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
58
|
|
|
|
19
|
|
|
|
205
|
|
|
|
35
|
|
|
|
40
|
|
|
|
(13
|
)
|
|
|
Other (loss)/income, net
|
|
|
(7
|
)
|
|
|
14
|
|
|
|
(150
|
)
|
|
|
14
|
|
|
|
44
|
|
|
|
(68
|
)
|
|
|
Refinancing expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
N/A
|
|
|
|
Interest expense
|
|
|
(186
|
)
|
|
|
(169
|
)
|
|
|
10
|
|
|
|
(481
|
)
|
|
|
(520
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expense
|
|
|
(135
|
)
|
|
|
(136
|
)
|
|
|
(1
|
)
|
|
|
(432
|
)
|
|
|
(471
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations before income tax
expense
|
|
|
1,314
|
|
|
|
410
|
|
|
|
220
|
|
|
|
1,324
|
|
|
|
769
|
|
|
|
72
|
|
|
|
Income tax expense
|
|
|
530
|
|
|
|
145
|
|
|
|
266
|
|
|
|
531
|
|
|
|
300
|
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
784
|
|
|
|
265
|
|
|
|
196
|
|
|
|
793
|
|
|
|
469
|
|
|
|
69
|
|
|
|
Income from discontinued operations, net of income tax expense
|
|
|
|
|
|
|
3
|
|
|
|
N/A
|
|
|
|
172
|
|
|
|
13
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
784
|
|
|
$
|
268
|
|
|
|
193
|
|
|
$
|
965
|
|
|
$
|
482
|
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMBtu)
|
|
|
9.11
|
|
|
|
6.24
|
|
|
|
46
|
%
|
|
|
9.67
|
|
|
|
7.02
|
|
|
|
38
|
%
|
|
|
|
|
N/A Not Applicable
Managements
discussion of the results of operations for the three months
ended September 30, 2008 and 2007:
Operating
Revenues
Operating revenues increased $918 million during the three
months ended September 30, 2008 compared to the same period
in 2007.
|
|
|
|
|
Energy revenues increased $109 million
during the three months ended September 30, 2008 compared
to the same period in 2007:
|
|
|
|
|
o
|
Texas increased $70 million, with
$101 million of this increase driven by higher energy
prices, offset by $31 million resulting from lower
generation volumes. Energy price increases were due to a more
favorable mix of merchant versus contract sales, as well as a
30% increase in merchant prices partially offset by a 14%
decrease in contract energy prices. Coal plant generation
increased by 1%, while gas plant generation decreased by 26%,
attributable to the effects of hurricane Ike in September 2008.
|
48
|
|
|
|
o
|
Northeast increased $5 million, with
$49 million driven by higher energy prices, offset by a
$44 million decrease attributable to a reduction in
generation. Higher energy prices were due to an average 19% rise
in merchant prices offset by lower contract revenue of
$11 million driven by higher costs required to service the
PJM contracts, as a result of the increase in market energy
prices. Generation decreased 12% due to a cooler summer in 2008
as compared to 2007.
|
|
|
o
|
South Central increased $19 million,
attributable to higher merchant energy revenues, reflecting a
40% rise in on-peak power prices combined with a 19% increase in
merchant energy MWh sold.
|
|
|
o
|
West increased $11 million due to the
dispatch of the El Segundo plant outside of its tolling
agreement in 2008. In 2007, no such dispatch occurred.
|
|
|
|
|
|
Capacity revenues increased $28 million
during the three months ended September 30, 2008 compared
to the same period in 2007:
|
|
|
|
|
o
|
Texas increased $39 million due to a
greater proportion of base-load contracts, which contain a
capacity component.
|
|
|
o
|
Northeast decreased $9 million, as lower
capacity prices in the NYISO and PJM markets were offset by
higher capacity prices in the NEPOOL markets.
|
|
|
|
|
|
Other revenues decreased $15 million
during the three months ended September 30, 2008 compared
to the same period in 2007, driven by reduced activity in
trading gas and coal of $31 million, offset by a
$12 million increase in ancillary revenue.
|
|
|
|
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
$787 million during the three months ended
September 30, 2008 compared to the same period in 2007. The
breakdown of changes by region is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2008
|
|
|
Three months ended September 30, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
(In millions)
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Total
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Total
|
|
|
|
|
Net gains/(losses) on settled positions, or financial
revenues
|
|
$
|
3
|
|
|
$
|
22
|
|
|
$
|
(4
|
)
|
|
$
|
21
|
|
|
$
|
15
|
|
|
$
|
13
|
|
|
$
|
1
|
|
|
$
|
29
|
|
|
|
|
|
Mark-to-market
results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
(5
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(7
|
)
|
|
|
(15
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(17
|
)
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
|
|
|
|
(6
|
)
|
|
|
(3
|
)
|
|
|
(9
|
)
|
|
|
(1
|
)
|
|
|
3
|
|
|
|
(5
|
)
|
|
|
(3
|
)
|
|
|
Net unrealized gains/(losses) on open positions related to
economic hedges
|
|
|
590
|
|
|
|
201
|
|
|
|
|
|
|
|
791
|
|
|
|
1
|
|
|
|
9
|
|
|
|
|
|
|
|
10
|
|
|
|
Net unrealized gains/(losses) on open positions related to
trading activity
|
|
|
(12
|
)
|
|
|
8
|
|
|
|
30
|
|
|
|
26
|
|
|
|
(4
|
)
|
|
|
5
|
|
|
|
15
|
|
|
|
16
|
|
|
|
|
|
Subtotal
mark-to-market
results
|
|
|
573
|
|
|
|
201
|
|
|
|
27
|
|
|
|
801
|
|
|
|
(19
|
)
|
|
|
15
|
|
|
|
10
|
|
|
|
6
|
|
|
|
Total gain/(loss)
|
|
$
|
576
|
|
|
$
|
223
|
|
|
$
|
23
|
|
|
$
|
822
|
|
|
$
|
(4
|
)
|
|
$
|
28
|
|
|
$
|
11
|
|
|
$
|
35
|
|
|
|
|
|
NRGs third quarter 2008 gain is comprised of
$801 million of
mark-to-market
gains and $21 million in settled gains, or financial
revenue. Of the $801 million of
mark-to-market
gains, $7 million represents the reversal of
mark-to-market
gains recognized on economic hedges and $9 million
represents the reversal of
mark-to-market
gains recognized on trading activity during 2007. Both of these
losses ultimately settled as financial revenues during 2008. The
$791 million gain from economic hedge positions included a
$439 million increase in value of forward sales of
electricity and fuel due to lower forward power and gas prices
and a $352 million gain 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 decreased at a slower pace.
49
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 prior to 2007, NRG hedged a portion
of the Companys 2007 and 2008 generation. During the third
quarter 2007 and 2008 the settled and forward prices of
electricity and natural gas have decreased resulting in the
recognition of realized gains and unrealized
mark-to-market
gains.
Cost
of Operations
Cost of operations increased $58 million during the three
months ended September 30, 2008 compared to the same period
in 2007.
|
|
|
|
|
Cost of energy increased $45 million
during the three months ended September 30, 2008 compared
to the same period in 2007 due to:
|
|
|
|
|
o
|
Texas increased $8 million due to higher
natural gas, coal, and ancillary service costs, offset by lower
nuclear fuel expense and amortized contract costs. Natural gas
cost increased $22 million, reflecting a 45% rise in per
MMBtu average natural gas prices, offset by a 26% decrease in
gas-fired generation. Coal costs increased $3 million due
to higher coal prices. Ancillary service costs rose
$11 million due to increased purchases to meet contract
obligations and a rise in ancillary service costs incurred by
ERCOT. Nuclear fuel expense decreased $15 million as
amortization of nuclear fuel inventory established under Texas
Genco purchase accounting ended in 2008. Amortized contract
costs decreased $11 million as amortization of water supply
contracts established under Texas Genco purchase accounting
ended in 2007.
|
|
|
o
|
Northeast decreased $1 million as a
$15 million reduction in natural gas costs and a
$2 million reduction in oil costs were offset by a
$16 million increase in coal costs. Natural gas cost
decreased due to 26% lower generation offset by higher average
prices. Coal costs increased due to higher prices and fuel
transportation surcharges offset by 4% lower coal generation.
|
|
|
o
|
South Central increased $25 million due
to a $14 million increase in purchased energy reflecting
higher gas costs, and a $12 million increase in natural gas
costs as certain gas plants ran extensively to support
transmission system stability during hurricane Gustav.
|
|
|
o
|
West increased $10 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
$13 million during the three months ended
September 30, 2008 compared to the same period in 2007, due
to increased operating and maintenance expenses, as well as
higher diesel and chemical costs in the Texas region.
|
Development
Costs
NRGs development costs arise from RepoweringNRG
projects and were $13 million for the three months ended
September 30, 2008, a decrease of $36 million when
compared to the same period in 2007:
|
|
|
|
|
Texas STP units 3 and 4 projects No
development expense was reflected in results of operations for
the third quarter 2008 period as NRG began to capitalize STP
units 3 and 4 development costs incurred after January 1,
2008 following the NRCs docketing of the Companys
Combined Operating License Application, or COLA, in late 2007.
The Company recorded $35 million in development expenses
during the same period in 2007.
|
|
|
|
Wind projects the Company incurred
$4 million in development costs related to wind projects in
Texas and California which is a $1 million decrease from
the same period in 2007.
|
|
|
|
Other projects the Company incurred
$9 million in development costs related to other domestic
RepoweringNRG projects which is consistent with the same
period in 2007.
|
Equity
in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates
increased by $39 million for the three months ended
September 30, 2008 compared to the same period in 2007.
This increase was due to a $41 million
mark-to-market
unrealized gain on a forward contract for natural gas swap
executed to hedge the future power generation of Sherbino.
50
Other
(Loss)/Income, Net
NRGs other (loss)/income decreased by $21 million for
the three months ended September 30, 2008 compared to the
same period in 2007. The Company recorded an additional
$19 million impairment charge in the third quarter 2008 to
restructure distressed investments in commercial paper, as
previously disclosed in 2007, reducing its carrying value to
$10 million.
Interest
Expense
NRGs interest expense increased by $17 million for
the three months ended September 30, 2008 compared to the
same period in 2007. This increase was due to the
$45 million payment made to CS for the benefit of CSF I in
August 2008 to early settle the embedded derivative in the
Companys CSF I notes and preferred interests. This
increase was offset by decreases due to interest savings from
the $300 million prepayment in December 2007 and an
additional payment of $143 million in March 2008 of the
Term B loan in connection with the mandatory offer under the
Senior Credit Facility accompanied by a reduction on the
variable interest rates on long-term debt. Interest capitalized
on RepoweringNRG projects under construction also
contributed to this decrease.
Income
Tax Expense
NRGs income tax expense increased by $385 million for
the three months ended September 30, 2008 compared to the
same period in 2007. The effective tax rate was 40.3% and 35.4%
for the three months ended September 30, 2008 and 2007,
respectively. The increase in income tax expense was primarily
due to an increase in income.
|
|
|
|
|
|
|
|
|
|
|
(In millions except percentages)
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
2008
|
|
|
2007
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,314
|
|
|
$
|
410
|
|
|
|
|
|
Tax at 35%
|
|
|
460
|
|
|
|
143
|
|
|
|
State taxes, net of federal benefit
|
|
|
63
|
|
|
|
21
|
|
|
|
Foreign operations
|
|
|
(2
|
)
|
|
|
(4
|
)
|
|
|
Foreign dividends
|
|
|
|
|
|
|
13
|
|
|
|
Non-deductible interest
|
|
|
18
|
|
|
|
2
|
|
|
|
Change in German tax rate
|
|
|
|
|
|
|
(30
|
)
|
|
|
Section 199 Manufacturing Deduction
|
|
|
(11
|
)
|
|
|
(3
|
)
|
|
|
Other permanent differences
|
|
|
2
|
|
|
|
3
|
|
|
|
|
|
Income tax expense
|
|
$
|
530
|
|
|
$
|
145
|
|
|
|
|
|
Effective income tax rate
|
|
|
40.3
|
%
|
|
|
35.4
|
%
|
|
|
|
|
The increase in income tax expense was due to:
|
|
|
|
|
Increase in income pre-tax income increased
by $904 million with a corresponding increase of
$358 million in income tax expense.
|
|
|
|
Permanent differences the Companys
effective tax rate differed from the US statutory rate of 35%
due to:
|
|
|
|
|
o
|
Taxable dividends from foreign subsidiaries
US taxability of foreign subsidiaries earnings
resulted in an additional tax benefit of approximately
$13 million during the third quarter 2008 as compared to
2007.
|
|
|
o
|
Non-deductible interest on CSF I CAGR Settlement
the Company executed the Note Purchase Amendment
Agreement and Preferred Interest Amendment Agreement which
allowed CSF I to early settle the CSF I CAGR. The result of this
settlement resulted in an additional income tax expense of
$16 million during the third quarter 2008 as compared to
the same period in 2007.
|
|
|
o
|
Change in German tax rate due to a reduction
in the German effective tax rate, income tax expense benefited
by $30 million in 2007 as compared to the same period in
2008.
|
|
|
o
|
Section 199 Manufacturing Deduction as a
result of the increase in pre-tax income during 2008, the
Company recorded an additional income tax benefit of
$8 million as compared to 2007.
|
51
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 the three
months ended September 30, 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 the three months ended
September 30, 2007, NRG recorded income from discontinued
operations, net of income tax expense, of $3 million. NRG
closed the sale of ITISA during the second quarter 2008.
Managements
discussion of the results of operations for the nine months
ended September 30, 2008 and 2007:
Operating
Revenues
Operating revenues increased $701 million during the nine
months ended September 30, 2008 compared to the same period
in 2007.
|
|
|
|
|
Energy revenues increased $416 million
during the nine months ended September 30, 2008 compared to
the same period in 2007:
|
|
|
|
|
o
|
Texas increased $291 million, was driven
by higher prices, as generating volumes were essentially
unchanged. The price variance was attributable to a more
favorable mix of merchant versus contract sales, as well as a
38% increase in merchant prices partially offset by a 14%
decrease in contract energy prices. Total generation was largely
unchanged at 36 million MWh. The mix of generation however
did change with a 3% higher generation from the nuclear plant
and a less than 1% rise in generation from coal plants. This mix
was offset by a 7% reduction in gas plant generation,
attributable to the effects of hurricane Ike in September 2008.
|
|
|
o
|
Northeast increased $28 million, with
$57 million of the increase driven by higher energy prices,
offset by $29 million due to reduced generation. The
increase due to energy prices reflects an average 12% 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. The decline due
to generation was driven by a net 3% reduction in the
regions generation, due to a cooler summer and warmer
winter in 2008 compared to 2007.
|
|
|
o
|
South Central increased $61 million,
attributable to $57 million higher merchant energy
revenues. The growth in merchant energy revenues reflects a 35%
rise in merchant MWh sold, as a 6% decrease in contract load MWh
allowed more sales to the merchant market at higher prices.
|
|
|
o
|
West increased $23 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 $147 million
during the nine months ended September 30, 2008 compared to
the same period in 2007:
|
|
|
|
|
o
|
Texas increased $93 million due to a
greater proportion of base-load contracts, which contain a
capacity component.
|
|
|
o
|
Northeast increased $26 million
reflecting higher capacity revenues in the PJM and NEPOOL
markets.
|
|
|
o
|
South Central increased $11 million due
to new peak loads set by the regions cooperative customers
which resulted in $6 million of additional capacity
payments and increased RPM capacity payments of $5 million
from the PJM market.
|
|
|
o
|
West increased $10 million due to a
tolling arrangement at Long Beach plant.
|
|
|
|
|
|
Contract amortization revenues increased
$48 million during the nine months ended September 30,
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.
|
52
|
|
|
|
|
Other revenues increased by $41 million
during the nine months ended September 30, 2008 compared to
the same period in 2007. The increases arose from greater
ancillary services revenue of $30 million and increased
activity in the trading of emission allowances and carbon
financial instruments of $21 million. These increases were
offset by $12 million in lower gas and coal trading
activities.
|
|
|
|
Risk management activities revenues from risk
management activities include economic hedges that did not
qualify for cash flow hedges, ineffectiveness on cash flow hedge
accounting and trading activities. Such revenues increased by
$61 million during the nine months ended September 30,
2008 compared to the same period in 2007. The breakdown of
changes by region is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
(In millions)
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Total
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Total
|
|
|
|
|
Net gains/(losses) on settled positions, or financial
revenues
|
|
$
|
(47
|
)
|
|
$
|
(2
|
)
|
|
$
|
(4
|
)
|
|
$
|
(53
|
)
|
|
$
|
31
|
|
|
$
|
49
|
|
|
$
|
5
|
|
|
$
|
85
|
|
|
|
|
|
Mark-to-market
results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
(21
|
)
|
|
|
(11
|
)
|
|
|
|
|
|
|
(32
|
)
|
|
|
(69
|
)
|
|
|
(40
|
)
|
|
|
|
|
|
|
(109
|
)
|
|
|
Reversal of previously recognized unrealized (gains)/losses on
settled positions related to trading activity
|
|
|
1
|
|
|
|
(7
|
)
|
|
|
(14
|
)
|
|
|
(20
|
)
|
|
|
|
|
|
|
(9
|
)
|
|
|
(14
|
)
|
|
|
(23
|
)
|
|
|
Net unrealized gains/(losses) on open positions related to
economic hedges
|
|
|
95
|
|
|
|
58
|
|
|
|
|
|
|
|
153
|
|
|
|
39
|
|
|
|
15
|
|
|
|
|
|
|
|
54
|
|
|
|
Net unrealized gains/(losses) on open positions related to
trading activity
|
|
|
25
|
|
|
|
1
|
|
|
|
31
|
|
|
|
57
|
|
|
|
1
|
|
|
|
8
|
|
|
|
28
|
|
|
|
37
|
|
|
|
|
|
Subtotal
mark-to-market
results
|
|
|
100
|
|
|
|
41
|
|
|
|
17
|
|
|
|
158
|
|
|
|
(29
|
)
|
|
|
(26
|
)
|
|
|
14
|
|
|
|
(41
|
)
|
|
|
Total gain/(loss)
|
|
$
|
53
|
|
|
$
|
39
|
|
|
$
|
13
|
|
|
$
|
105
|
|
|
$
|
2
|
|
|
$
|
23
|
|
|
$
|
19
|
|
|
$
|
44
|
|
|
|
|
|
NRGs 2008 gain is comprised of $158 million of
mark-to-market
gains and $53 million in settled losses, or financial
revenue. Of the $158 million of
mark-to-market
gains, $32 million represents the reversal of
mark-to-market
gains recognized on economic hedges and $20 million
represents the reversal of
mark-to-market
gains recognized on trading activity during 2007. Both of these
losses ultimately settled as financial revenues during 2008. The
$153 million gain from economic hedge positions included a
$180 million increase in value of forward sales of
electricity and fuel due to higher forward power and gas prices
and a $27 million loss primarily from hedge accounting
ineffectiveness related to gas trades in the Texas region which
was driven by increasing forward gas prices while forward power
prices rose at a slower pace.
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 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. In 2007, NRG recognized forward
mark-to-market
losses as forward prices of electricity increased relative to
its forward positions.
53
Cost
of Operations
Cost of operations increased $252 million during the nine
months ended September 30, 2008 compared to the same period
in 2007.
|
|
|
|
|
Cost of energy increased $260 million
during the nine months ended September 30, 2008 compared to
the same period in 2007 due to:
|
|
|
|
|
o
|
Texas increased $132 million due to
increases in natural gas costs, coal costs and ancillary
services cost, offset by reductions in nuclear fuel expenses and
amortization of contracts cost. The $136 million rise in
natural gas costs was due to an increase of average natural gas
prices, offset by a 7% decrease in gas-fired generation. The
$16 million increase in coal costs was a result of the
recognition of a settlement related to a coal contract dispute
and higher coal prices. The $19 million increase in
ancillary services and other costs was the result of higher
purchased ancillary services and increased ERCOT ISO fees.
Amortized contracts costs decreased by $31 million as the
amortization of water supply contracts established under Texas
Genco purchase accounting ended in 2007. Nuclear fuel expense
decreased by $11 million as amortization of nuclear fuel
inventory established under Texas Genco purchase accounting
ended in early 2008.
|
|
|
o
|
Northeast increased $51 million due to
$54 million higher coal costs and $20 million higher
natural gas costs, offset by $23 million reduced oil costs.
Coal costs increased due to 4% higher generation, as well as
higher coal prices and fuel transportation surcharges. Natural
gas costs increased due to higher natural gas prices, despite
14% lower generation. Oil costs decreased due to lower oil-fired
generation.
|
|
|
o
|
South Central increased $43 million due
to a $7 million rise in coals costs resulting from an
increase in fuel transportation surcharges, a $12 million
rise in natural gas costs as the regions peaker plants ran
extensively to support transmission system stability after
hurricane Gustav, and an $18 million increase in purchased
energy, reflecting higher natural gas costs for tolling
contracts.
|
|
|
o
|
West increased $23 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 decreased
$8 million during the nine months ended September 30,
2008 compared to the same period in 2007. This decrease was due
to:
|
|
|
|
|
o
|
Texas increased $20 million due to
higher operating and maintenance expenses, increased chemical
and diesel costs at the regions fossil plants, STP
equipment retirements and refueling outage, and the timing of
annual outages at the WA Parish and Limestone plants.
|
|
|
o
|
Northeast decreased $19 million due to a
$16 million decrease in operating and maintenance expenses
and a $7 million decrease in property taxes. The decrease
in operating and maintenance expenses was the result of less
outage work at the Arthur Kill, Huntley and Norwalk plants. The
reduction in property taxes was due to property tax credits
received in 2008.
|
Development
Costs
NRGs development costs that rose from RepoweringNRG
projects were $29 million for the nine months ended
September 30, 2008, which is a decrease of $79 million
when compared to the same period in 2007:
|
|
|
|
|
Texas STP units 3 and 4 projects the Company
recorded $7 million of income during the nine months ended
September 30, 2008, compared to $74 million in
development expenses during the same period in 2007. The 2008
activity reflects an April 2008 reimbursement under a
partnership agreement for development costs incurred in 2007. No
development expense is reflected in results of operations for
the nine months ended September 30, 2008 period as NRG
began to capitalize STP units 3 and 4 development costs incurred
after January 1, 2008 following the NRCs docketing of
the Companys Combined Operating License Application, or
COLA, in late 2007.
|
|
|
|
Wind projects the Company incurred
$13 million in development costs related to Texas wind
projects, which is a $1 million increase from the same
period in 2007.
|
54
|
|
|
|
|
Other projects the Company incurred
$23 million in development costs related to other domestic
RepoweringNRG projects which is a $1 million
increase from the same period in 2007.
|
Gain
on Sale of Assets
The Company reported no gains on sales of assets for the nine
months ended September 2008. For the nine months ended
September 30, 2007, NRGs gain on the sale of assets
was $16 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
decreased by $5 million for the nine months ended
September 30, 2008 compared to the same period in 2007.
This decrease was due to a $9 million
mark-to-market
unrealized loss on natural gas swap executed to hedge the future
power generation of Sherbino.
Other
(Loss)/Income, Net
NRGs other (loss)/income decreased by $30 million for
the nine months ended September 30, 2008 compared to the
same period in 2007. The Company recorded an additional $22 million
impairment charge in 2008 to restructure distressed investments
in commercial paper, as previously disclosed in 2007, reducing
its carrying value to $10 million. In addition, the 2008
results reflect reduced interest income of $32 million from
lower market interest rates on cash deposits.
Refinancing
Expense
Refinancing expense decreased by $35 million for the nine
months ended September 30, 2008 compared to the same period
in 2007. On June 8, 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 B
loan either exited the financing or reduced their holdings and
were replaced by other institutions.
Interest
Expense
NRGs interest expense decreased by $39 million for
the nine months ended September 30, 2008 compared to the
same period in 2007. This decrease was due to interest savings
from the $300 million prepayment in December 2007 and an
additional payment of $143 million in March 2008 of the
Term B loan in connection with the mandatory offer under the
Senior Credit Facility accompanied by a reduction on the
variable interest rates on long-term debt. Interest capitalized
on RepoweringNRG projects under construction also
contributed to this decrease. Offsetting these decreases was the
$45 million payment made to CS for the benefit of CSF I in
August 2008 to early settle the embedded derivative in the
Companys CSF I notes and preferred interests.
Income
Tax Expense
NRGs income tax expense increased by $231 million for
the nine months ended September 30, 2008 compared to the
same period in 2007. The effective tax rate was 40.1% and 39.0%
for the nine months ended September 30, 2008 and 2007,
respectively. The increase in income tax expense was primarily
due to an increase in income.
|
|
|
|
|
|
|
|
|
|
|
(In millions except percentages)
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
2008
|
|
|
2007
|
|
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,324
|
|
|
$
|
769
|
|
|
|
|
|
Tax at 35%
|
|
|
463
|
|
|
|
269
|
|
|
|
State taxes, net of federal benefit
|
|
|
62
|
|
|
|
37
|
|
|
|
Foreign operations
|
|
|
(10
|
)
|
|
|
(5
|
)
|
|
|
Valuation allowance
|
|
|
(1
|
)
|
|
|
1
|
|
|
|
Foreign dividends
|
|
|
5
|
|
|
|
21
|
|
|
|
Non-deductible interest
|
|
|
24
|
|
|
|
7
|
|
|
|
Change in German tax rate
|
|
|
|
|
|
|
(30
|
)
|
|
|
Section 199 Manufacturing Deduction
|
|
|
(17
|
)
|
|
|
(3
|
)
|
|
|
Other permanent differences
|
|
|
5
|
|
|
|
3
|
|
|
|
|
|
Income tax expense
|
|
$
|
531
|
|
|
$
|
300
|
|
|
|
|
|
Effective income tax rate
|
|
|
40.1
|
%
|
|
|
39.0
|
%
|
|
|
|
|
55
The increase in income tax expense was due to:
|
|
|
|
|
Increase in income pre-tax income increased
by $555 million, with a corresponding increase of
$220 million in income tax expense.
|
|
|
|
Permanent differences the Companys
effective tax rate differs from the US statutory rate of 35% due
to:
|
|
|
|
|
o
|
Lower tax rates in foreign jurisdictions
lower income tax rates at the Companys
foreign locations resulted in an income tax benefit in 2008 as
compared to the same period in 2007 of $5 million.
|
|
|
o
|
Taxable dividends from foreign subsidiaries
US taxability of foreign subsidiaries earnings
resulted in an additional tax benefit of approximately
$16 million in 2008 as compared to 2007.
|
|
|
o
|
Non-deductible interest on CSFI CAGR Settlement
the Company executed the Note Purchase Amendment
Agreement and Preferred Interest Amendment Agreement which
allowed CSF I to early settle the CSFI CAGR. The result of this
settlement 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 due to a reduction
in the German effective tax rate, income tax expense benefited
by $30 million in 2007 as compared to the same period in
2008.
|
|
|
o
|
Section 199 Manufacturing Deduction as a
result of the increase in pre-tax income during 2008, the
Company recorded an additional income tax benefit of
$14 million as compared to 2007.
|
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 the nine
months ended September 30, 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 the nine months
ended September 30, 2008 and the same period in 2007, NRG
recorded income from discontinued operations, net of income tax
expense, of $172 million and $13 million,
respectively. NRG closed the sale of ITISA during the second
quarter 2008.
56
Results
of Operations Regional Discussions
The following is a detailed discussion of the results of
operations of NRGs major wholesale power generation
business segments.
Texas
For a discussion of the business profile of the Companys
Texas operations, see
pages 22-25
of NRG Energy, Inc.s 2007 Annual Report on
Form 10-K.
Selected
income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
873
|
|
|
$
|
803
|
|
|
|
9
|
%
|
|
$
|
2,344
|
|
|
$
|
2,053
|
|
|
|
14
|
%
|
|
|
Capacity revenue
|
|
|
129
|
|
|
|
90
|
|
|
|
43
|
|
|
|
366
|
|
|
|
273
|
|
|
|
34
|
|
|
|
Risk management activities
|
|
|
576
|
|
|
|
(4
|
)
|
|
|
N/A
|
|
|
|
53
|
|
|
|
2
|
|
|
|
N/A
|
|
|
|
Contract amortization
|
|
|
69
|
|
|
|
59
|
|
|
|
17
|
|
|
|
215
|
|
|
|
167
|
|
|
|
29
|
|
|
|
Other revenues
|
|
|
14
|
|
|
|
8
|
|
|
|
75
|
|
|
|
83
|
|
|
|
31
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,661
|
|
|
|
956
|
|
|
|
74
|
|
|
|
3,061
|
|
|
|
2,526
|
|
|
|
21
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
366
|
|
|
|
358
|
|
|
|
2
|
|
|
|
1,037
|
|
|
|
905
|
|
|
|
15
|
|
|
|
Other operating expenses
|
|
|
154
|
|
|
|
175
|
|
|
|
(12
|
)
|
|
|
468
|
|
|
|
527
|
|
|
|
(11
|
)
|
|
|
Depreciation and amortization
|
|
|
108
|
|
|
|
113
|
|
|
|
(4
|
)
|
|
|
334
|
|
|
|
341
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
1,033
|
|
|
$
|
310
|
|
|
|
233
|
|
|
$
|
1,222
|
|
|
$
|
753
|
|
|
|
62
|
|
|
|
MWh sold (in thousands)
|
|
|
13,111
|
|
|
|
13,792
|
|
|
|
(5
|
)
|
|
|
36,817
|
|
|
|
37,037
|
|
|
|
(1
|
)
|
|
|
MWh generated (in thousands)
|
|
|
12,891
|
|
|
|
13,420
|
|
|
|
(4
|
)
|
|
|
36,147
|
|
|
|
36,157
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
|
102.82
|
|
|
|
62.44
|
|
|
|
65
|
|
|
|
112.80
|
|
|
|
63.60
|
|
|
|
77
|
|
|
|
Cooling Degree Days, or CDDs (a)
|
|
|
1,417
|
|
|
|
1,458
|
|
|
|
(3
|
)%
|
|
|
2,509
|
|
|
|
2,380
|
|
|
|
5
|
|
|
|
CDDs 30 year average
|
|
|
1,485
|
|
|
|
1,485
|
|
|
|
|
|
|
|
2,434
|
|
|
|
2,434
|
|
|
|
|
|
|
|
Heating Degree Days, or HDDs (a)
|
|
|
6
|
|
|
|
|
|
|
|
N/A
|
|
|
|
1,163
|
|
|
|
1,280
|
|
|
|
(9
|
)
|
|
|
HDDs 30 year average
|
|
|
5
|
|
|
|
5
|
|
|
|
|
|
|
|
1,221
|
|
|
|
1,208
|
|
|
|
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. |
Quarterly
Results
Operating
Income
Operating income increased by $723 million for the three
months ended September 30, 2008, compared to the same
period in 2007, primarily due to:
|
|
|
|
|
Risk management activities an increase of
$580 million was primarily due to $592 million in
greater unrealized derivative gains offset by $12 million
in lower realized gains on settled financial transactions. These
changes reflect a reduction in forward power and gas prices at
the end of the third quarter of 2008 compared to the end of the
second quarter 2008. Gas and power prices in the comparable
period of 2007 were relatively flat.
|
|
|
|
Energy revenues increased by $70 million
due to higher merchant energy revenue as a result of increased
power prices and sales volumes offset by lower contract energy
revenue.
|
57
Operating
Revenues
Total operating revenues increased by $705 million during
the three months ended September 30, 2008, compared to the
same period in 2007, due to:
|
|
|
|
|
Risk management activities gains of
$576 million were recognized for the three months ended
September 30, 2008 compared to a $4 million loss in
the same period in 2007. The $576 million includes
$573 million of unrealized mark-to-market gains and
$3 million in settled gains, or financial revenue, compared
to $19 million in unrealized derivative losses and
$15 million of settled financial gains in the same period
in 2007. The $573 million is the net effect of a
$590 million gain from economic hedge positions and a
$5 million loss on reversals of mark-to-market gains on
economic hedges, partially offset by $12 million in
unrealized mark-to-market losses on trading transactions. The
$590 million gain from economic hedges incorporates
$261 million in unrealized gains in the value of forward
sales of electricity and fuel driven by lower power and natural
gas prices. These hedges are considered effective economic
hedges that do not receive cash flow hedge accounting treatment.
The remaining $329 million in gains are from hedge
ineffectiveness which was driven by decreasing gas prices while
power prices decreased at a slower pace.
|
|
|
|
Energy revenues increased by $70 million
due to:
|
|
|
|
|
o
|
Energy prices increased by $101 million
due to higher energy prices, reflecting a more favorable mix of
merchant versus contract sales, as well as a 30% increase in
merchant prices offset by a 14% decrease in contract energy
prices. The increase in merchant prices was driven by higher
average natural gas prices in ERCOT as compared to 2007.
|
|
|
o
|
Generation decreased by $31 million due
to lower generation volumes. A 1% increase in coal plant
generation was offset by a 26% decrease in gas plant generation.
Hurricane Ike in September 2008 caused major damage to the
Houston area transmission grid which limited the Companys
ability to deliver power that normally would be generated to
serve demand in the region. The damage from hurricane Ike caused
a lost opportunity to generate and deliver power reducing gas
plant generation for the quarter.
|
|
|
|
|
|
Capacity revenue increased by
$39 million due to a greater proportion of base-load
contracts which contain a capacity component.
|
|
|
|
Contract amortization revenue increased by
$10 million due to the volume of contracted energy affected
by a greater spread between contract and market prices used in
the Texas Genco purchase accounting.
|
Cost of
Energy
Cost of energy increased by $8 million during the three
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Natural gas costs increased by
$22 million due to a 45% rise in average natural gas prices
offset by a 26% decrease in gas-fired generation.
|
|
|
|
Coal costs increased by $3 million due
to an increase in coal prices.
|
|
|
|
Ancillary Service Costs increased by
$11 million due to an increase in purchased ancillary
services costs incurred to meet contract obligations and a rise
in ancillary service costs charged by ERCOT.
|
These increases were partially offset by:
|
|
|
|
|
Nuclear fuel expense decreased by
$15 million as amortization of nuclear fuel inventory
established under Texas Genco purchase accounting ended in early
2008.
|
|
|
|
Amortized contract costs decreased by
$11 million as amortization of water supply contracts
established under Texas Genco purchase accounting ended in 2007.
|
58
Other
Operating Expenses
Other operating expenses decreased by $21 million during
the three months ended September 30, 2008, compared to the
same period in 2007, due to:
|
|
|
|
|
Development costs decreased by
$35 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. Development
costs for STP nuclear units 3 and 4 are being capitalized in
2008.
|
This decrease was offset by:
|
|
|
|
|
Operations & maintenance expense
increased by $13 million which included increased
maintenance activity at STP and increased diesel and chemical
costs at the regions fossil plants. The increase in
maintenance activity at STP was the result of equipment and
refueling outages.
|
Yearly
Results
Operating
Income
Operating income increased by $469 million for the nine
months ended September 30, 2008, compared to the same
period in 2007, primarily due to:
|
|
|
|
|
Energy revenues increased by $291 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 $93 million
due to a greater proportion of base-load contracts which contain
a capacity component.
|
|
|
|
Risk management activities an increase of
$51 million was primarily due to $128 million in
greater unrealized derivative gains offset by $79 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 nine months ended September 30,
2008. Gas and power prices in the comparable period 2007 were
relatively flat.
|
These increases were offset by:
|
|
|
|
|
Cost of energy increased by $132 million
reflecting the effects of increased natural gas and coal prices.
|
Operating
Revenues
Total operating revenues increased by $535 million during
the nine months ended September 30, 2008, compared to 2007,
due to:
|
|
|
|
|
Risk management activities gains of
$53 million were recognized for the nine months ended
September 30, 2008 compared to a $2 million gain in
the same period in 2007. The $53 million includes
$100 million of unrealized mark-to-market gains and
$47 million in settled losses, or financial revenue,
compared to $29 million in unrealized derivative losses and
$31 million of settled financial gains in the same period
in 2007. The $100 million is the net effect of a
$95 million gain from economic hedge positions and a
$20 million loss on reversals of mark-to-market gains on
economic hedges, partially offset by $25 million in
unrealized mark-to-market gains on trading transactions. The
$95 million gain from economic hedges incorporates
$123 million in unrealized gains in the value of forward
sales of electricity and fuel driven by higher power and natural
gas prices. These hedges are considered effective economic
hedges that do not receive cash flow hedge accounting treatment.
The remaining $28 million in losses are from hedge
ineffectiveness which was driven by increasing gas prices while
power prices rose at a slower pace.
|
|
|
|
Energy revenues increased by
$291 million due to:
|
|
|
|
|
o
|
Energy prices increased by $292 million
due to a more favorable mix of merchant versus contract sales
resulting in a 38% increase in merchant prices offset by a 14%
decrease in contract energy prices.
|
59
|
|
|
|
o
|
Generation remained largely unchanged at
36 million MWh. The mix of generation however did change
with a 3% rise in nuclear generation at STP and a less than 1%
rise in coal generation. This increase was offset by a 7%
decrease in overall gas plant generation for the nine months
ending September 2008. Hurricane Ike in September 2008 caused
major damage to the Houston area transmission grid which limited
the Companys ability to deliver power that normally would
be generated to serve demand in the region. The damage from
hurricane Ike caused a lost opportunity to generate and deliver
power reducing gas plant generation.
|
|
|
|
|
|
Capacity revenue increased by
$93 million due to a greater proportion of base-load
contracts which contain a capacity component.
|
|
|
|
Other revenues increased by $52 million
related to a $22 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
$8 million.
|
|
|
|
Contract amortization revenue increased by
$48 million 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.
|
Cost
of Energy
Cost of energy increased by $132 million during the nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Natural gas costs increased by
$136 million due to a 40% rise in average gas prices offset
by a 7% decrease in gas-fired generation.
|
|
|
|
Coal costs increased by $16 million due
to the settlement of a coal contract dispute and higher coal
prices.
|
|
|
|
Ancillary services increased by
$19 million due to a $7 million increase in purchased
ancillary services costs incurred to meet contract obligations
and a $12 million rise in ancillary service costs incurred
by ERCOT.
|
These increases were partially offset by:
|
|
|
|
|
Amortized contract costs decreased by
$31 million as amortization of water supply contracts
established under Texas Genco purchase accounting ended in 2007.
|
|
|
|
Nuclear fuel expense decreased by
$11 million as amortization of nuclear fuel inventory
established under Texas Genco purchase accounting ended in early
2008.
|
|
|
|
Purchased power decreased by $6 million
due to lower outage rates at the regions baseload plants.
|
Other
Operating Expenses
Other operating expenses decreased by $59 million during
the nine months ended September 30, 2008, compared to 2007,
due to:
|
|
|
|
|
Development costs decreased by
$81 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. Development
costs for STP nuclear units 3 and 4 are being capitalized in
2008.
|
This decrease was primarily offset by:
|
|
|
|
|
Operations & maintenance expense
increased by $20 million related to increased chemical and
diesel costs at the regions fossil plants, STP equipment
retirements and refueling outage, and the timing of annual
outages at the WA Parish and Limestone plants.
|
60
Northeast
Region
For a discussion of the business profile of the Northeast
region, see
pages 25-28
of NRG Energy, Inc.s 2007 Annual Report on
Form 10-K.
Selected
income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
September 30, |
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
324
|
|
|
$
|
319
|
|
|
|
2
|
%
|
|
$
|
873
|
|
|
$
|
845
|
|
|
|
3
|
%
|
|
|
Capacity revenue
|
|
|
117
|
|
|
|
126
|
|
|
|
(7
|
)
|
|
|
328
|
|
|
|
302
|
|
|
|
9
|
|
|
|
Risk management activities
|
|
|
223
|
|
|
|
28
|
|
|
|
N/A
|
|
|
|
39
|
|
|
|
23
|
|
|
|
70
|
|
|
|
Other revenues
|
|
|
13
|
|
|
|
29
|
|
|
|
(55
|
)
|
|
|
62
|
|
|
|
69
|
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
677
|
|
|
|
502
|
|
|
|
35
|
|
|
|
1,302
|
|
|
|
1,239
|
|
|
|
5
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
198
|
|
|
|
199
|
|
|
|
(1
|
)
|
|
|
557
|
|
|
|
506
|
|
|
|
10
|
|
|
|
Other operating expenses
|
|
|
89
|
|
|
|
92
|
|
|
|
(3
|
)
|
|
|
273
|
|
|
|
298
|
|
|
|
(8
|
)
|
|
|
Depreciation and amortization
|
|
|
26
|
|
|
|
25
|
|
|
|
4
|
|
|
|
77
|
|
|
|
74
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
364
|
|
|
$
|
186
|
|
|
|
96
|
|
|
$
|
395
|
|
|
$
|
361
|
|
|
|
9
|
|
|
|
MWh sold (in thousands)(b)
|
|
|
3,588
|
|
|
|
4,058
|
|
|
|
(12
|
)
|
|
|
10,424
|
|
|
|
10,754
|
|
|
|
(3
|
)
|
|
|
MWh generated (in thousands)
|
|
|
3,588
|
|
|
|
4,058
|
|
|
|
(12
|
)
|
|
|
10,424
|
|
|
|
10,754
|
|
|
|
(3
|
)
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
|
108.44
|
|
|
|
78.28
|
|
|
|
39
|
|
|
|
100.66
|
|
|
|
75.89
|
|
|
|
33
|
|
|
|
Cooling Degree Days, or CDDs(a)
|
|
|
446
|
|
|
|
511
|
|
|
|
(13
|
)
|
|
|
611
|
|
|
|
672
|
|
|
|
(9
|
)
|
|
|
CDDs 30 year average
|
|
|
430
|
|
|
|
430
|
|
|
|
|
|
|
|
534
|
|
|
|
534
|
|
|
|
|
|
|
|
Heating Degree Days, or HDDs(a)
|
|
|
135
|
|
|
|
122
|
|
|
|
11
|
%
|
|
|
3,866
|
|
|
|
4,116
|
|
|
|
(6
|
)%
|
|
|
HDDs 30 year average
|
|
|
159
|
|
|
|
159
|
|
|
|
|
|
|
|
4,126
|
|
|
|
4,126
|
|
|
|
|
|
|
|
|
|
|
|
|
(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) |
|
MWh sold are shown net of MWh purchased to satisfy certain
load contracts in the region. |
Quarterly
Results
Operating
Income
Operating income increased by $178 million for the three
months ended September 30, 2008, compared to the same
period in 2007 due to:
|
|
|
|
|
Operating revenues increased by
$175 million due to favorable impact of risk management
activities, offset by lower capacity and other revenues.
|
Operating
Revenues
Operating revenues increased by $175 million for the three
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Risk management activities gains of
$223 million were recorded for the three months ending
September 30, 2008, compared to gains of $28 million
during the same period in 2007. The $223 million gain
includes $201 million of unrealized mark-to-market gains
and $22 million in gains on settled transactions, or
financial revenue, compared to $15 million in unrealized
mark-to-market gains and $13 million in financial revenue
gains during the same period in 2007. The $201 million
unrealized gain is the net effect of a $201 million gain
from economic hedge positions, the reversal of $2 million
of mark-to-market gains on economic hedges, the reversal of
$6 million of mark-to-market gains on trading activity and
$8 million in unrealized mark-to-market gains on trading
activity. Gains are driven by decreases in power and gas prices.
|
61
|
|
|
|
|
Energy revenues increased by $5 million
due to:
|
|
|
|
|
o
|
Energy prices increased by $49 million
reflecting an average 19% rise in merchant energy prices of
$60 million. This increase was offset by lower net revenue
of $11 million driven by higher net costs as a result of
meeting obligations under load serving contracts in the PJM
market.
|
|
|
o
|
Generation decreased by $44 million due
to a net 12% decrease in generation in 2008 compared to
2007. The decrease in generation represents a 4% decline in coal
generation, a 53% decrease in oil-fired generation and 26% lower
gas-fired generation due to a cooler summer in 2008 compared to
2007.
|
|
|
|
|
|
Capacity revenues decreased by
$9 million due to:
|
|
|
|
|
o
|
NYISO capacity revenues decreased by
$9 million due to unfavorable 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 cash flow hedge revenue.
|
|
|
o
|
PJM capacity revenues decreased by
$4 million due to lower capacity prices.
|
|
|
o
|
NEPOOL capacity revenues increased by
$4 million due to higher capacity prices.
|
|
|
|
|
|
Other revenues decreased by $16 million
due to $26 million lower net physical gas sales offset by
$9 million from 2008 carbon financial instrument sales.
|
Cost of
Energy
Cost of energy decreased by $1 million for the three months
ended September 30, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Natural gas costs decreased by
$15 million due to 26% lower generation offset by higher
average prices per MMbtu.
|
|
|
|
Oil costs decreased by $2 million due to
53% lower oil-fired generation offset by higher oil prices.
|
These decreases were offset by:
|
|
|
|
|
Coal costs increased by $16 million due
to higher coal costs and fuel transportation surcharges. This
increase was offset by 4% lower coal generation.
|
Other
Operating Expenses
Other operating expenses decreased by $3 million for the
three months ended September 30 2008, compared to the same
period in 2007, due to a $3 million property tax credit
received in 2008 at the Arthur Kill plant.
62
Yearly
Results
Operating
Income
Operating income increased by $34 million for the nine
months ended September 30, 2008, compared to the same
period in 2007 due to:
|
|
|
|
|
Operating revenues increased by
$63 million due to higher energy revenue, capacity revenue
and risk management revenues.
|
|
|
|
Other operating expenses decreased by
$25 million consisting due to lower major maintenance
expenses, property taxes and utilities.
|
These favorable variances were offset by:
|
|
|
|
|
Cost of energy increased by $51 million
due to higher coal costs, increased coal transportation
surcharges and higher natural gas prices. These were offset by
lower oil costs from lower oil-fired generation due to a warmer
summer and colder winter in 2007 compared to 2008.
|
Operating
Revenues
Operating revenues increased by $63 million for the nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Energy revenues increased by $28 million
due to:
|
|
|
|
|
o
|
Energy prices increased by $102 million
reflecting an average 12% rise in merchant energy prices. This
was offset by lower contract revenue of $45 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 $29 million due
to a net 3% decrease in generation. The decrease in
generation represents a 52% decrease in oil-fired generation and
a 14% decrease in gas-fired generation. These results are due to
a warmer summer and colder winter in 2007. This decrease was
offset by a 4% increase in coal generation as a result of the
timing of outages at the Huntley and Indian River plants and
higher reliability at the Huntley plant.
|
|
|
|
|
|
Capacity revenues increased by
$26 million due to:
|
|
|
|
|
o
|
PJM capacity revenues increased by
$21 million reflecting recognition of nine months of
revenue from the RPM capacity market (effective on June 1,
2007) in 2008 compared to four months in 2007.
|
|
|
o
|
NEPOOL capacity revenues increased
$14 million consisting of $7 million from higher
capacity prices and $7 million from increased revenue
recognized on the Norwalk RMR contract (effective on
June 19, 2007).
|
|
|
o
|
NYISO capacity revenues decreased by
$9 million due to unfavorable 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 cash flow hedge revenue.
|
|
|
|
|
|
Risk management activities gains of
$39 million were recorded for the nine months ending
September 30, 2008, compared to gains of $23 million
during the same period in 2007. The $39 million gain
includes $41 million of unrealized mark-to-market gains and
$2 million of losses in settled transactions, or financial
revenue, compared to $26 million in unrealized
mark-to-market losses and $49 million in financial revenue
gains during the same period in 2007. The $41 million
unrealized gains is the net effect of a $58 million gain
from economic hedge positions, the reversal of $11 million
of mark-to-market gains on economic hedges, the reversal of
$7 million of mark-to-market gains on trading activity and
$1 million in unrealized mark-to-market gains on trading
activity. Gains are driven by increases in power and gas prices.
|
63
These gains were offset by:
|
|
|
|
|
Other revenues decreased by $7 million
due to $21 million lower net physical gas sales in 2008
offset by $15 million from 2008 sales of carbon financial
instruments.
|
Cost
of Energy
Cost of energy increased by $51 million for the nine months
ended September 30, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Coal costs increased by $54 million due
to 4% higher coal generation, higher coal costs and fuel
transportation surcharges.
|
|
|
|
Natural gas costs increased by
$20 million, despite 14% lower generation, due to higher
natural gas prices.
|
These increases were offset by:
|
|
|
|
|
Oil costs decreased by $23 million due
to lower oil-fired generation as a result of a warmer summer and
colder winter in 2007.
|
Other
Operating Expenses
Other operating expenses decreased by $25 million for nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Major maintenance expenses decreased by
$16 million due to less outage work at the Arthur Kill,
Huntley and Norwalk plants.
|
|
|
|
Property taxes decreased by $7 million
due to a $3 million property tax credit received in 2008 at
the Arthur Kill plant, $3 million in credits against the
property tax at the Western New York plants, and $1 million
of property tax credits received in 2008 at the New York City
plants.
|
|
|
|
Utilities decreased by $4 million due to
a Connecticut station service settlement.
|
64
South
Central Region
For a discussion of the business profile of the South Central
region, see
pages 28-30
of NRG Energy, Inc.s 2007 Annual Report on
Form 10-K.
Selected
income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
145
|
|
|
$
|
126
|
|
|
|
15
|
%
|
|
$
|
375
|
|
|
$
|
314
|
|
|
|
19
|
%
|
|
|
Capacity revenue
|
|
|
59
|
|
|
|
56
|
|
|
|
5
|
|
|
|
174
|
|
|
|
163
|
|
|
|
7
|
|
|
|
Risk management activities
|
|
|
23
|
|
|
|
11
|
|
|
|
109
|
|
|
|
13
|
|
|
|
19
|
|
|
|
(32
|
)
|
|
|
Contract amortization
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
|
|
18
|
|
|
|
18
|
|
|
|
|
|
|
|
Other revenues
|
|
|
(1
|
)
|
|
|
|
|
|
|
N/A
|
|
|
|
4
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
233
|
|
|
|
200
|
|
|
|
17
|
|
|
|
584
|
|
|
|
514
|
|
|
|
14
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
156
|
|
|
|
131
|
|
|
|
19
|
|
|
|
360
|
|
|
|
317
|
|
|
|
14
|
|
|
|
Other operating expenses
|
|
|
25
|
|
|
|
21
|
|
|
|
19
|
|
|
|
80
|
|
|
|
83
|
|
|
|
(4
|
)
|
|
|
Depreciation and amortization
|
|
|
16
|
|
|
|
17
|
|
|
|
(6
|
)
|
|
|
50
|
|
|
|
51
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
36
|
|
|
$
|
31
|
|
|
|
16
|
|
|
$
|
94
|
|
|
$
|
63
|
|
|
|
49
|
|
|
|
MWh sold (in thousands)
|
|
|
3,383
|
|
|
|
3,748
|
|
|
|
(10
|
)
|
|
|
9,448
|
|
|
|
9,579
|
|
|
|
(1
|
)
|
|
|
MWh generated (in thousands)
|
|
|
2,828
|
|
|
|
3,192
|
|
|
|
(11
|
)
|
|
|
8,469
|
|
|
|
8,416
|
|
|
|
1
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
|
84.88
|
|
|
|
60.42
|
|
|
|
40
|
|
|
|
79.14
|
|
|
|
60.80
|
|
|
|
30
|
|
|
|
Cooling Degree Days, or CDDs(a)
|
|
|
1,027
|
|
|
|
1,249
|
|
|
|
(18
|
)
|
|
|
1,577
|
|
|
|
1,853
|
|
|
|
(15
|
)
|
|
|
CDDs 30 year average
|
|
|
997
|
|
|
|
997
|
|
|
|
|
|
|
|
1,487
|
|
|
|
1,487
|
|
|
|
|
|
|
|
Heating Degree Days, or HDDs(a)
|
|
|
16
|
|
|
|
10
|
|
|
|
60
|
%
|
|
|
2,239
|
|
|
|
2,080
|
|
|
|
8
|
|
|
|
HDDs 30 year average
|
|
|
33
|
|
|
|
33
|
|
|
|
|
|
|
|
2,246
|
|
|
|
2,226
|
|
|
|
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. |
Quarterly
Results
Operating
Income
Operating income increased by $5 million for the three
months ended September 30, 2008, compared to the same
period in 2007, primarily due to:
|
|
|
|
|
Operating revenues increased by
$33 million due to increases in energy revenue, capacity
revenue and risk management activities. Mild weather in the
summer months reduced demand from the regions cooperative
customers, thereby allowing sales to the merchant market at
higher prices. This increase was offset by the impacts of
hurricane Gustav which caused major power outages in the region
that limited demand from the cooperative customers during a
period when the region would typically be purchasing power
across the daily peaks. Hurricane Gustav also inflicted major
damage to the transmission grid which limited the Companys
ability to deliver power and restricted the output of the Big
Cajun II coal plant.
|
|
|
|
Cost of energy increased by $25 million
due to higher purchased energy and natural gas costs offset by
lower coal generation costs.
|
65
Operating
Revenues
Operating revenues increased by $33 million for the three
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Energy revenues increased by $19 million
due to $23 million in higher merchant energy revenues,
offset by a $3 million reduction in contract energy
revenues. The growth in merchant energy revenues reflects a 40%
rise in on-peak power prices combined with a 19% increase in
merchant MWh sold. Hurricane Gustav resulted in major power
outages throughout Louisiana and reduced load demand from the
regions cooperative customers. Megawatt hour sales to
cooperative customers fell by 6% in the third quarter of 2008 as
compared to 2007.
|
|
|
|
Risk Management Activities gains of
$23 million were recognized during the third quarter 2008
compared to gains of $11 million recognized during the same
period in 2007. The $23 million gain includes
$27 million in unrealized gains offset by realized losses
of $4 million compared to $10 million in unrealized
gains and $1 million in realized gains for the same period
in 2007. The $27 million unrealized gain is the net effect
of a $30 million unrealized mark-to-market gain from
trading activity and the reversal of $3 million of
mark-to-market gains on trading activity. Unrealized gains are
primarily driven by decreases in power and gas prices.
|
|
|
|
Capacity revenues increased by
$3 million due to increased capacity revenue from the PJM
market.
|
Cost
of Energy
Cost of energy increased by $25 million for the three
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Purchased energy increased by
$14 million reflecting higher gas costs associated with the
regions tolling agreements and market purchases.
|
|
|
|
Natural gas costs increased by
$12 million as a result of the Bayou Cove and Big Cajun I
Peaker plants running extensively to support transmission system
stability after hurricane Gustav.
|
These increases were offset by:
|
|
|
|
|
Coal costs decreased by $1 million due
to $6 million decline related to a 15% reduction in coal
generation as a result of hurricane Gustav offset by a
$5 million rise in coal unit costs as a result of increases
in fuel transportation surcharges.
|
Other
Operating Expenses
Other operating expenses increased by $4 million for the
three months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
G&A Expense $2 million higher
corporate allocations in 2008 compared to the same period in
2007.
|
|
|
|
Operating and maintenance expense increase of
$1 million due to higher labor expenses and higher major
maintenance expenses.
|
66
Yearly
Results
Operating
Income
Operating income increased by $31 million for the nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Operating revenues increased by
$70 million due to the increase in energy revenue and
capacity revenue offset by an unfavorable impact of risk
management activities.
|
|
|
|
Cost of energy increased by $43 million
due to higher purchased energy, natural gas coal transportation
costs, and transmission costs.
|
Operating
Revenues
Operating revenues increased by $70 million for the nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Energy revenues increased by $61 million
due to $57 million in higher merchant energy revenues and
$4 million of improved contract energy revenues. The growth
in merchant energy revenues reflects a 1% rise in total MWh
generated combined with a 6% decrease in contract load MWh
thereby allowing for more sales to the merchant market at higher
prices. The increase in revenue from contract load is driven by
higher fuel cost pass-through adjustments for the regions
cooperative customers, while mild weather and the impacts of
hurricane Gustav lowered load requirements. Megawatt hour sales
to contract customers decreased 6% in 2008 as compared to 2007.
Merchant energy MWh sold increased by 35%.
|
|
|
|
Capacity revenues increased by
$11 million due to new peak loads set by the regions
cooperative customers which resulted in $6 million of
additional capacity payments and increased RPM capacity payments
of $5 million from the PJM market.
|
These increases were offset by:
|
|
|
|
|
Risk Management Activities gains of
$13 million were recognized during the first nine months of
2008 compared to $19 million in gains recognized during the
same period in 2007. Unrealized gains in 2008 of
$17 million offset by realized losses of $4 million
compared to $14 million of unrealized gains and
$5 million of realized gains in 2007. The $17 million
unrealized gain is the net effect of a $31 million
unrealized mark-to-market gain from trading activities in the
region offset by the reversal of $14 million of
mark-to-market gains on trading activity. Unrealized gains are
primarily driven by decreases in power and gas prices.
|
Cost of
Energy
Cost of energy increased by $43 million for the nine months
ended September 30, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Purchased energy increased by
$18 million reflecting a 28% 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 a decrease in purchased MWh as increased
plant availability reduced power purchases required to support
contract load.
|
|
|
|
Natural gas costs increased $12 million.
The regions Bayou Cove and Big Cajun I Peaker plants ran
extensively to support transmission system stability after
hurricane Gustav in September 2008.
|
|
|
|
Coal costs increased by $7 million due
to a $2 per ton increase in fuel transportation surcharges.
These increases were offset by a 1% drop in coal generation and
a $3 million decrease in allocated rail car lease fees
among the regions. This allocation of the railcar lease better
reflects the actual usage of the Companys railcar fleet.
|
|
|
|
Transmission costs increased by
$6 million due to additional point-to-point transmission
costs driven by an increase in merchant energy sales.
|
67
Other
Operating Expenses
Other operating expenses decreased by $3 million for the
nine months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
G&A Expense Franchise tax decreased by
$7 million due to a retroactive charge recorded in the
first quarter 2007. The Louisiana state franchise tax is
assessed on the Companys total debt and equity that
significantly increased following the Acquisition of Texas Genco
LLC. This decrease was offset by $5 million in higher
corporate allocations in 2008 compared to the same period in
2007.
|
|
|
|
Operating and maintenance expense Major
maintenance decreased by $5 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.
|
68
West
Region
For a discussion of the business profile of the West region, see
pages 30-32
of NRG Energy, Inc.s 2007 Annual Report on
Form 10-K.
Selected
income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30,
|
|
|
Nine months ended September 30,
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
12
|
|
|
$
|
1
|
|
|
|
N/A
|
|
|
$
|
25
|
|
|
$
|
2
|
|
|
|
N/A
|
|
|
|
Capacity revenue
|
|
|
28
|
|
|
|
32
|
|
|
|
(13
|
)%
|
|
|
97
|
|
|
|
87
|
|
|
|
11
|
%
|
|
|
Risk management activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
1
|
|
|
|
400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
40
|
|
|
|
33
|
|
|
|
21
|
|
|
|
127
|
|
|
|
90
|
|
|
|
41
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
11
|
|
|
|
1
|
|
|
|
N/A
|
|
|
|
25
|
|
|
|
2
|
|
|
|
N/A
|
|
|
|
Other operating expenses
|
|
|
14
|
|
|
|
19
|
|
|
|
(26
|
)
|
|
|
52
|
|
|
|
58
|
|
|
|
(10
|
)
|
|
|
Depreciation and amortization
|
|
|
2
|
|
|
|
1
|
|
|
|
100
|
|
|
|
6
|
|
|
|
2
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
13
|
|
|
$
|
12
|
|
|
|
8
|
|
|
$
|
44
|
|
|
$
|
28
|
|
|
|
57
|
|
|
|
MWh sold (in thousands)
|
|
|
124
|
|
|
|
4
|
|
|
|
N/A
|
|
|
|
213
|
|
|
|
5
|
|
|
|
N/A
|
|
|
|
MWh generated (in thousands)
|
|
|
124
|
|
|
|
4
|
|
|
|
N/A
|
|
|
|
213
|
|
|
|
5
|
|
|
|
N/A
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
|
96.72
|
|
|
|
68.87
|
|
|
|
40
|
|
|
|
91.52
|
|
|
|
65.93
|
|
|
|
39
|
|
|
|
Cooling Degree Days, or CDDs(a)
|
|
|
687
|
|
|
|
634
|
|
|
|
8
|
|
|
|
893
|
|
|
|
770
|
|
|
|
16
|
|
|
|
CDDs 30 year average
|
|
|
506
|
|
|
|
506
|
|
|
|
|
|
|
|
663
|
|
|
|
663
|
|
|
|
|
|
|
|
Heating Degree Days, or HDDs(a)
|
|
|
61
|
|
|
|
91
|
|
|
|
(33
|
)%
|
|
|
2,157
|
|
|
|
1,917
|
|
|
|
13
|
|
|
|
HDDs 30 year average
|
|
|
108
|
|
|
|
108
|
|
|
|
|
|
|
|
2,098
|
|
|
|
2,081
|
|
|
|
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. |
Quarterly
Results
Operating
Income
Operating income increased by $1 million for the three
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Energy revenues increased by $11 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 Expenses decreased by
$5 million due to a reduction in RepoweringNRG
permitting expenses for the El Segundo and Carlsbad Energy
Centers for 2008 as compared to 2007.
|
These increases were partially offset by:
|
|
|
|
|
Cost of energy increased by $10 million
due to the 2008 dispatch of the El Segundo plant.
|
|
|
|
Capacity revenues decreased by
$4 million primarily due to expiration of a two year
tolling agreement at the El Segundo facility partially offset by
the tolling agreement at the Long Beach plant:
|
|
|
|
|
o
|
El Segundo The expiration of the two year
tolling agreement at the end of April resulted in a decrease of
$5 million in capacity revenues for the three months ended
September 30, 2008.
|
|
|
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 $1 million in incremental
capacity revenues for the three months ended September 30,
2008.
|
69
Yearly
Results
Operating
Income
Operating income increased by $16 million for the nine
months ended September 30, 2008, compared to the same
period in 2007, due to:
|
|
|
|
|
Capacity revenues increased by
$10 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 nine months ended September 30,
2008.
|
|
|
o
|
El Segundo The expiration of the two year
tolling agreement at the end of April resulted in a decrease of
$5 million in capacity revenues for the nine months ended
September 30, 2008
|
|
|
|
|
|
Energy revenues increased by $23 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 revenues increased by $4 million
due to increased trading activity of emission allowances in 2008.
|
|
|
|
Other operating expense decreased by
$6 million due to a reduction RepoweringNRG
permitting expenses of $4 million for the El Segundo and
Carlsbad Energy Centers in 2008 as compared to 2007. In addition
an environmental liability of $2 million was recognized in
2007 related to the El Segundo plant.
|
These increases were partially offset by:
|
|
|
|
|
Cost of energy increased by $23 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
$4 million, reflecting the depreciation associated with the
successful completion of the RepoweringNRG project at the
Long Beach plant.
|
70
Liquidity
and Capital Resources
Liquidity
Position
As of September 30, 2008 and December 31, 2007,
NRGs liquidity was approximately $3.0 billion and
$2.7 billion, respectively, and comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
As of
|
|
September 30, 2008
|
|
|
December 31, 2007
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
1,483
|
|
|
$
|
1,132
|
|
|
|
Restricted cash
|
|
|
32
|
|
|
|
29
|
|
|
|
|
|
Total cash
|
|
|
1,515
|
|
|
|
1,161
|
|
|
|
|
|
Synthetic letter of credit availability
|
|
|
534
|
|
|
|
557
|
|
|
|
Revolver credit facility availability
|
|
|
1,000
|
|
|
|
997
|
|
|
|
|
|
Total liquidity
|
|
$
|
3,049
|
|
|
$
|
2,715
|
|
|
|
|
|
For the nine months ended September 30, 2008, total
liquidity increased by $334 million due to higher cash
balances of $354 million. Changes in cash balances are
further discussed hereinafter under Cash Flow Discussion.
Cash and cash equivalents at September 30, 2008 are
predominantly held in money market funds invested in treasury
securities or treasury repurchase agreements.
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%.
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
First
and Second Lien Structure
NRG has granted first and second liens to certain counterparties
on substantially all of the Companys assets in the United
States in order to secure primarily long-term obligations under
power and gas sale agreements and related contracts. NRG uses
the first or second lien structure to reduce the amount of cash
collateral and letters of credit that it would otherwise be
required to post from time to time to support its obligations
under 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 is limited by volumes hedged, not by the value of
underlying out-of-the money positions. The first lien program
does not require us 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 rolling 60 months with such permitted hedging volumes 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.
As part of the amendments to NRGs Senior Credit Facility
entered into on June 8, 2007, the Company obtained the
ability to move its second lien counterparty exposure to the
first lien on a pari passu basis with the Companys
existing first lien lenders. In exchange for moving to a pari
passu basis with the Companys first lien lenders, the
counterparties agreed to relinquish letters of credit issued by
NRG which they held as a part of their collateral package.
The Companys lien counterparties may have a claim on our
assets to the extent their net positions are
out-of-the-money.
As of September 30, 2008 and October 23, 2008, the
first lien exposure of net out-of-the-money positions to
counterparties on hedges was $405 million and
$185 million, respectively. As of September 30, 2008
and October 23, 2008, the second lien net out-of-the-money
positions to counterparties on hedges was approximately
$16 million and $2 million, respectively.
71
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 October 23, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales
secured by First and
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second Lien Structure
(a)
|
2008(b)
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
|
|
|
|
|
|
|
In MW
|
5,751
|
|
44,529
|
|
40,515
|
|
33,341
|
|
19,499
|
|
7,650
|
|
|
As a percentage of total forecasted baseload capacity (c)
|
56%
|
|
73%
|
|
68%
|
|
56%
|
|
33%
|
|
14%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Equivalent Net Sales include natural gas swaps converted
using a weighted average heat rate by region. |
|
(b) |
|
2008 MW value consists of November through December
positions only. |
|
(c) |
|
Forecasted baseload capacity under the first and second lien
structure represents 80% of the total Companys baseload
assets. |
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 the notes and preferred interest maturities of
CSF I from October 2008 to June 2010. In addition, the
settlement date of an embedded derivative, or CSFI CAGR, which
is based on NRGs share price appreciation beyond a 20%
compound annual growth rate since the original date of purchase
by CSF I, 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 CSFI 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.
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 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 condensed consolidated balance sheet As
discussed in Note 3, Discontinued Operations, 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
September 30, 2008, commercial operations had total cash
collateral outstanding of $390 million, and
$464 million outstanding in letters of credit to third
parties primarily to support its hedging activities.
Future liquidity requirements may change based on the
Companys hedging activities and structures, fuel
purchases, and future market conditions, including forward
prices for energy and fuel and market volatility. In addition,
liquidity requirements are dependent on NRGs credit
ratings and general perception of its creditworthiness.
72
Debt
Service Obligations
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 B loan. The percentage of
excess cash flow offered to these lenders is dependent upon the
Companys consolidated leverage ratio (as defined in the
Senior Credit Facility) at the end of the preceding year. Of the
amount offered, the first lien lenders must accept 50% while the
remaining 50% may either be accepted or rejected at the
lenders option. The mandatory annual offer required for
2008 was $446 million, against which the Company made a
$300 million prepayment 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 can be used for investments, capital expenditures and
other items as defined by the Senior Credit Facility.
Capital
Expenditures and RepoweringNRG Equity Investments in
Affiliates
For the nine months ended September 30, 2008, the
Companys capital expenditures, including accruals, were
approximately $709 million, of which $466 million was
related to RepoweringNRG projects. The following table
summarizes the Companys capital expenditures for the nine
months ended September 30, 2008 and the estimated capital
expenditure and repowering investments forecast for the
remainder of 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Maintenance
|
|
|
Environmental
|
|
|
RepoweringNRG
|
|
|
Total
|
|
|
|
|
Northeast
|
|
$
|
15
|
|
|
$
|
93
|
|
|
$
|
19
|
|
|
$
|
127
|
|
|
|
Texas
|
|
|
94
|
|
|
|
17
|
|
|
|
82
|
|
|
|
193
|
|
|
|
South Central
|
|
|
7
|
|
|
|
5
|
|
|
|
|
|
|
|
12
|
|
|
|
West
|
|
|
2
|
|
|
|
|
|
|
|
28
|
|
|
|
30
|
|
|
|
NINA
|
|
|
|
|
|
|
|
|
|
|
55
|
|
|
|
55
|
|
|
|
Wind
|
|
|
|
|
|
|
|
|
|
|
282
|
|
|
|
282
|
|
|
|
Other
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
|
|
Capital expenditures through September 30, 2008
|
|
|
128
|
|
|
|
115
|
|
|
|
466
|
|
|
|
709
|
|
|
|
Capital expenditures through the remainder of 2008
|
|
|
80
|
|
|
|
87
|
|
|
|
97
|
|
|
|
264
|
|
|
|
|
|
Total estimated capital expenditures for 2008
|
|
$
|
208
|
|
|
$
|
202
|
|
|
$
|
563
|
|
|
$
|
973
|
|
|
|
|
|
Total estimated repowering equity investments for 2008
|
|
|
N/A
|
|
|
|
N/A
|
|
|
$
|
87
|
|
|
$
|
87
|
|
|
|
|
|
RepoweringNRG capital expenditures and
investments RepoweringNRG project capital
expenditures consisted of approximately $170 million for
wind turbines and construction related costs for the Elbow Creek
wind farm project which is currently under construction and
$112 million in turbine purchases for other wind projects
currently under development. In addition, the Companys
RepoweringNRG capital expenditures included
$82 million related to the construction of Cedar Bayou Unit
4 in Texas, $55 million related to the development of STP
Units 3 and 4 in Texas, $28 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
the remainder of 2008 are expected to consist of approximately
$57 million related to the construction and equipment
procurement for the Elbow Creek wind farm project and other wind
projects under development. In addition, the Company expects to
incur additional 2008 capital expenditures of approximately
$13 million towards the construction of Cedar Bayou Unit 4
and $19 million towards the development of STP Units 3 and
4.
Related to RepoweringNRG, the Company expects to
contribute equity of approximately $87 million to its
Sherbino wind farm project in 2008 and has posted a letter of
credit in that amount. For the nine months ended
September 30, 2008, the Company invested $17 million
in Sherbino.
Major maintenance and environmental capital
expenditures The Companys baghouse project
at its Huntley and Dunkirk plants resulted in environmental
capital expenditures of $70 million for the nine months
ended September 30, 2008. Other capital expenditures
included $31 million for STP fuel and $63 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.
73
Loans to affiliates During the first nine
months of 2008, the Company loaned $15 million in funds to
GenConn Energy LLC, or GenConn, a
50/50
joint venture vehicle of NRG and The United Illuminating Company
as a part of the Devon plant project. On October 16, 2008,
the Company loaned a further $15 million in funds to
GenConn 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 GenConns construction costs
are expected to be funded through equity of NRG and The United
Illuminating Company and non-recourse project level financing.
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2008
through 2013 to meet NRGs environmental commitments will
be approximately $1.3 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.
The following table summarizes the major environmental capital
expenditures for the referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
|
2008
|
|
$
|
24
|
|
|
$
|
172
|
|
|
$
|
6
|
|
|
$
|
202
|
|
|
|
2009
|
|
|
|
|
|
|
256
|
|
|
|
|
|
|
|
256
|
|
|
|
2010
|
|
|
7
|
|
|
|
187
|
|
|
|
52
|
|
|
|
246
|
|
|
|
2011
|
|
|
17
|
|
|
|
154
|
|
|
|
102
|
|
|
|
273
|
|
|
|
2012
|
|
|
27
|
|
|
|
67
|
|
|
|
100
|
|
|
|
194
|
|
|
|
2013
|
|
|
32
|
|
|
|
|
|
|
|
67
|
|
|
|
99
|
|
|
|
|
|
Total
|
|
$
|
107
|
|
|
$
|
836
|
|
|
$
|
327
|
|
|
$
|
1,270
|
|
|
|
|
|
2008
Capital Allocation Plan
In December 2007, the Company initiated its 2008 Capital
Allocation Program, 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 Program 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
September 30, 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 Program.
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. As part of the 2009 plan, the Company will invest
over $511 million in maintenance and environmental capital expenditures in the existing assets in 2009 and
$118 million in projects under RepoweringNRG
that are currently under construction or for which there exist
current obligations. Finally, in addition to a scheduled debt
amortization payment, in the first quarter 2009 the Company
will offer its first lien lenders 50% of its 2008 excess cash
flow (as defined in the Senior Credit Facility).
Benefit
Plans Obligations
Based on the Companys December 31, 2007 measurement
of its benefit obligation for its three defined benefit pension
plans, the Company is expected to contribute $13 million to
these plans from October 1, 2008 through March 31,
2009. Based on weak market performance of plan assets, the plans would require an additional
contribution of approximately $60 million from the Company in 2009.
74
Cash Flow
Discussion
The following table reflects the changes in cash flows for the
comparative periods. All cash flow categories include the cash
flows from both continuing operations and discontinued
operations:
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Nine months ended September 30,
|
|
2008
|
|
|
2007
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
1,041
|
|
|
$
|
976
|
|
|
|
Net cash used by investing activities
|
|
$
|
(332
|
)
|
|
$
|
(232
|
)
|
|
|
Net cash used by financing activities
|
|
$
|
(401
|
)
|
|
$
|
(375
|
)
|
|
|
|
|
Net
Cash Provided By Operating Activities
For the nine months ended September 30, 2008, net cash
provided by operating activities increased by $65 million
compared to the same period in 2007. The difference was due to:
|
|
|
|
|
Increase in generation and energy prices An
increase in power generation and higher energy prices
contributed to $278 million more in cash from operations
after adjusting net income for the effect of non-cash items for
the first nine months of 2008 compared to 2007.
|
|
|
|
Collateral deposits During the first nine
months of 2008, an increase in net collateral deposits of
$320 million to support the Companys hedging and
trading activities reduced cash from operations by
$213 million compared to the same period in 2007.
|
Net
Cash Used By Investing Activities
For the nine months ended September 30, 2008, net cash used
in investing activities was approximately $100 million more
than the same period in 2007. This was due to:
|
|
|
|
|
Capital expenditures NRGs capital
expenditures increased by $340 million due to
RepoweringNRG projects, primarily related to
$282 million for wind turbines related to Elbow Creek and
other wind projects currently under development.
|
|
|
|
Sale of discontinued operations Net proceeds
from the sale of ITISA were $241 million in 2008.
|
|
|
|
Asset sales The Company received
$14 million in proceeds primarily from the sale of rail
cars in the first nine months of 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 an increase in cash
of $51 million for the first nine months of 2008 compared
to 2007.
|
|
|
|
Equity Contribution The Company contributed
approximately $17 million to its equity investment in
Sherbino.
|
Net
Cash Used By Financing Activities
For the nine months ended September 30, 2008, net cash used
by financing activities increased by approximately
$26 million compared to 2007, due to:
|
|
|
|
|
Term B loan debt payment In 2008, the Company
paid down $166 million of its Term B loan, including the
payment of excess cash flow, as discussed above under Debt
Service Obligations. The Company paid down $25 million
of its Term B loan during the first nine months of 2007 for a
net cash decrease of $141 million for the nine months ended
of 2008 compared to the same period in 2007.
|
|
|
|
Share repurchase During the first nine months
of 2008, the Company repurchased approximately $185 million
shares of NRG common stock, compared to $268 million for
2007 for a net $83 million increase to cash for the nine
months 2008 compared to the same period in 2007.
|
75
|
|
|
|
|
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 the nine months of 2008, the
Company paid approximately $49 million related to the
settlement of gas swaps related to the acquisition of Texas
Genco in 2006.
|
|
|
|
Issuance of debt During the first nine months
of 2008, the Company received $20 million in proceeds from
the borrowings made by its subsidiaries.
|
|
|
|
Exercise of stock options The Company
received proceeds of $8 million from the exercise of stock
options for the nine months ended 2008.
|
NOLs,
Deferred Tax Assets and FIN 48 Implications
As of September 30, 2008, the Company had generated a total
domestic continuing pre-tax book income of $1,249 million
and foreign continuing pre-tax book income of $75 million.
In addition, NRG has cumulative foreign NOL carryforwards of
$253 million, of which $54 million will expire
starting in 2011 through 2017 and $199 million that do not
have an expiration date.
In addition to these amounts, the Company has $709 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 2008. Beginning in
2009, income tax payments will be approximately 30% of pre-tax
book income.
However, as the position remains uncertain, of the
$709 million of tax effected unrecognized tax benefits, the
Company has recorded a non-current tax liability of
$138 million and may accrue the remaining balance as an
increase to non-current liabilities until final resolution with
the related taxing authority. The $138 million non-current
tax liability for unrecognized tax benefits is due to taxable
earnings for the period for 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.
New and
On-going Company Initiatives
Nuclear
Innovation North America
In March 2008, NRG formed Nuclear Innovation North America LLC,
or 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 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.
In April 2008, NINA entered into a $20 million revolving
loan arrangement, as borrower, to provide working capital to
NINA. This facility matures on April 21, 2011, and permits
NINA to make cash draws or issue letters of credit. Borrowings
accrue interest at either LIBOR or a base rate, plus a spread.
As of September 30, 2008, NINA has $9.5 million
outstanding under this facility.
Toshiba Corporation, or Toshiba, will serve as the prime
contractor on all of NINAs projects, and has agreed to
partner with NRG on the NINA venture. Toshiba 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. Toshiba will invest $300 million
in NINA in six annual installments of $50 million, the last
three of which are subject to certain conditions, in exchange
for a 12% equity ownership in NINA. 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. Toshiba is also
extending pre-negotiated Engineering, Procurement and
Construction, or 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.
76
NINA intends to use the NRC certified ABWR design, with only a
limited number of changes to enhance safety and construction
schedules. On September 24, 2008, NINA filed a revision to
the COLA. Given the changes to the application, NRG anticipates
STP units 3 and 4 will come online in 2015 and 2016,
respectively.
RepoweringNRG
Update
Cos Cob
Generating Station
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 output to 100 MW. All five units were
retrofitted to use water injection technology, resulting in a
50% net station reduction in
NOx
and a 97% reduction in
SO2
emissions by using low-sulfur distillate fuel.
Sherbino
I Wind Farm
On October 22, 2008, NRG and its 50/50 joint venture
partner, BP Wind Energy North America Inc., or BP, announced the
completion of its Sherbino I Wind Farm project in Pecos County,
Texas. The wind farm was developed by NRGs subsidiary
Padoma Wind Power LLC, or Padoma. Padoma managed the
construction and development, which began in late 2007, and 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.
GenConn
Energy LLC
On March 3, 2008, GenConn Energy LLC, or GenConn, a 50/50
joint venture vehicle of NRG and The United Illuminating
Company, submitted a binding bid to the Connecticut Department
of Public Utility Control, or DPUC, for new peaking generation
facilities in Connecticut subject to a regulated long-term
contract. The DPUC subsequently made two awards to GenConn. The
first, on June 25, 2008, was for the construction and
operation of approximately 200 MW of peaking generation at
NRGs Devon plant in Milford, Connecticut with a commercial
operation date of June 1, 2010 and a
30-year
term. The second, on October 6, 2008, was for the
construction and operation of approximately 200 MW of
peaking generation at NRGs Middletown facility in
Middletown, Connecticut with a commercial operation date of
June 1, 2011 and a
30-year
term. GenConn subsidiaries have executed contracts for
differences with Connecticut Light & Power for each of
these projects that have been approved by the
DPUC.
El
Segundo Energy Center LLC
On March 7, 2008, NRG, through its wholly-owned subsidiary,
El Segundo Energy Center LLC, or ESEC, executed a
10-year
tolling agreement, or PPA, with Southern California Edison, or
SCE. Pre-construction activities started shortly thereafter on a
550 MW rapid response combined cycle facility in El
Segundo, California. Since that time, NRG has made
non-refundable payments of approximately $17 million to the
equipment provider to meet the project construction schedule.
On July 29, 2008, the Los Angeles County Superior Court
issued a ruling in Natural Resource Defense Council,
Inc. v. South Coast Air Management District (Case
No. BS 110792), or NRDC I, that eliminated
the availability of certain air credits from the Priority
Reserve program of the South Coast Air Management District, or
SCAQMD. On August 18, 2008, the Natural Resource Defense
Council, or NRDC, filed a Complaint for Declaratory and
Injunctive Relief in the US District Court for the Central
District of California (Natural Resource Defense Council,
Inc. v. South Coast Air Management District (Case
No. CV08-05403), or
NRCD II, claiming the emission reduction
credits created by retiring power generation units and those
created by SCAQMD Rule 1309.1 do not meet federal Clean Air
Act requirements.
If successful, these actions may affect ESECs ability to
use air emission credits generated by retiring generating units
and the distribution of credits from offset accounts. Although
the California Public Utilities Commission, or CPUC, approved
the PPA on September 18, 2008, the project is unlikely to
reach commercial operation by June 1, 2011 as a result of
the NRDC I and II related permitting delays.
77
Plants
under Construction
The Company has two projects under construction, the Cedar Bayou
Generating Station and the Elbow Creek Wind Farm.
In August 2007, NRG, through its wholly owned subsidiary, NRG
Cedar Bayou Development Company LLC, entered into a definitive
agreement with EnergyCo Cedar Bayou 4, LLC to jointly develop,
construct, operate and own, on a 50/50 undivided interest basis,
a 550 MW combined cycle natural gas turbine generating
plant at NRGs Cedar Bayou Generating Station in Chambers
County, Texas. This project is expected to reach commercial
operations in mid-2009.
On March 27, 2008, NRG, through Padoma, began construction
of the Elbow Creek project, a wholly-owned 122 MW wind farm
in Howard County near Big Spring, Texas. This project is
scheduled to reach commercial operations by the end of 2008.
Huntley
IGCC
In December 2006, in a competitive bid process with New York
Power Authority, or NYPA, NRG won a conditional award of a power
purchase agreement in support of the construction of a
600 MW IGCC plant at its existing Huntley facility. The
project was cancelled on July 22, 2008.
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.
Retained
or Contingent Interests
NRG does not have any material retained or contingent interests
in assets transferred to an unconsolidated entity.
Derivative
Instrument Obligations
On August 11, 2005, NRG issued 3.625% Preferred Stock that
included a conversion feature which is considered a derivative
per FAS 133, as amended. 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
FAS 133. As of September 30, 2008, based on the
Companys stock price, the redemption value of this
embedded derivative was approximately $2 million.
On October 13, 2006, NRG, through its unrestricted
wholly-owned subsidiaries, NRG Common Stock Fund I, or
CSF I, and NRG Common Stock Fund II, or CSF II, issued
notes and preferred interests for the repurchase of NRGs
common stock. Included in each agreement was features 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
September 30, 2008, based on the Companys stock
price, the redemption value on the CSF II embedded derivative
was approximately $22 million.
Obligations
Arising Out of a Variable Interest in an Unconsolidated
Entity
Variable interest in equity investments As of
September 30, 2008, NRG had not entered into any financing
structure that was designed to be off-balance sheet that would
create incremental liquidity, financing or market risk or credit
risk to the Company. However, NRG has several investments with
an ownership interest percentage of 50% or less in energy and
energy-related entities, that are accounted for under the equity
method of accounting. NRGs pro-rata share of non-recourse
debt held by unconsolidated affiliates was approximately
$193 million as of September 30, 2008. This
indebtedness may restrict the ability of these affiliates to
issue dividends or distributions to NRG.
78
In addition, as previously discussed, NRG and BP entered into a
50/50 joint venture in February 2008 to build and own Sherbino.
NRG expects to contribute $87 million in equity to the
joint venture and has posted a letter of credit in this amount.
NRGs maximum exposure to loss is limited to its expected
equity investments.
Synthetic Letter of Credit Facility and Revolver
Facility Under NRGs amended Senior Credit
Facility which the Company entered into in June 2007, the
Company has a $1.3 billion Synthetic Letter of Credit
Facility which is secured by a $1.3 billion cash deposit at
Deutsche Bank AG, New York Branch, the Issuing Bank. This
deposit was funded using proceeds from the Senior Credit
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. Currently NRG has the capability to issue
under its Revolving Credit Facility unfunded Letters of Credit
up to $900 million for ongoing working capital requirements
and for general corporate purposes, including acquisitions that
are permitted under the Senior Credit Facility. In addition, NRG
is permitted to issue additional letters of credit of up
$100 million under the Senior Credit Facility through other
financial institutions.
As of September 30, 2008, the Company had issued
$766 million in letters of credit under the Synthetic
Letter of Credit Facility. The Company had no letters of credit
issued under the Revolving Credit Facility as of
September 30, 2008. A portion of these letters of credit
supports non-commercial letter of credit obligations.
Contractual
Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other
commercial commitments that represent prospective cash
requirements in addition to the Companys capital
expenditure programs, as disclosed in the Companys
Form 10-K.
Also see Note 14, Commitments and Contingencies, to
the condensed consolidated financial statements of this
Form 10-Q
for a discussion of new commitments and contingencies that also
include contractual obligations and commercial commitments that
occurred during the third quarter 2008.
Critical
Accounting Estimates
NRGs discussion and analysis of the financial condition
and results of operations are based upon the consolidated
financial statements, which have been prepared in accordance
with accounting principles generally accepted in the United
States of America. The preparation of these financial statements
and related disclosures in compliance with generally accepted
accounting principles, or US 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 also may have a significant
effect, not only on the operation of the business, but on the
results reported through the application of accounting measures
used in preparing the financial statements and related
disclosures, even if the nature of the accounting policies have
not changed.
On an ongoing basis, 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.
79
|
|
ITEM 3
|
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 and oil. A number of factors influence the
level and volatility of prices for energy commodities and
related derivative products. These factors include:
|
|
|
|
|
Seasonal, daily and hourly changes in demand;
|
|
|
|
Extreme peak demands due to weather conditions;
|
|
|
|
Available supply resources;
|
|
|
|
Transportation availability and reliability within and between
regions; and
|
|
|
|
Changes in the nature and extent of federal and state
regulations.
|
As part of NRGs overall portfolio, NRG manages the
commodity price risk of the Companys merchant generation
operations by entering into various derivative or non-derivative
instruments to hedge the variability in future cash flows from
forecasted sales of electricity and purchases of fuel. These
instruments include forward purchase and sale contracts, futures
and option contracts traded on the New York Mercantile Exchange,
and swaps and options traded in the
over-the-counter
financial markets. The portion of forecasted transactions hedged
may vary based upon managements assessment of market,
weather, operation and other factors.
While some of the contracts the Company uses to manage risk
represent commodities or instruments for which prices are
available from external sources, other commodities and certain
contracts are not actively traded and are valued using other
pricing sources and modeling techniques to determine expected
future market prices, contract quantities, or both. NRG uses the
Companys best estimates to determine the fair value of
commodity and derivative contracts held and sold. These
estimates consider various factors, including closing exchange
and
over-the-counter
price quotations, time value, volatility factors and credit
exposure. However, it is likely that future market prices could
vary from those used in recording
mark-to-market
derivative instrument valuation, and such variations could be
material.
NRG measures the market risk of the Companys portfolio to
commodity prices using Value at Risk, or VAR. VAR is a
statistical model that attempts to predict risk of loss based on
market price and volatility. Currently, the company estimates
VAR using a Monte Carlo simulation based methodology. NRGs
total portfolio includes
mark-to-market
and non-mark-to-market energy assets and liabilities.
NRG uses a diversified VAR model to calculate an estimate of the
potential loss in the fair value of the Companys energy
assets and liabilities, which includes generation assets, load
obligations, and bilateral physical and financial transactions.
The key assumptions for the Companys diversified model
include: (i) a lognormal 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.
80
As of September 30, 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 $51 million.
The following table summarizes average, maximum and minimum VAR
for NRG:
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
VAR (a)
|
|
2008
|
|
|
2007
|
|
|
|
|
Three months ended September 30:
|
|
$
|
51
|
|
|
$
|
32
|
|
|
|
Average
|
|
|
48
|
|
|
|
31
|
|
|
|
Maximum
|
|
|
62
|
|
|
|
37
|
|
|
|
Minimum
|
|
|
35
|
|
|
|
24
|
|
|
|
|
|
Nine months ended September 30:
|
|
$
|
51
|
|
|
$
|
32
|
|
|
|
Average
|
|
|
50
|
|
|
|
26
|
|
|
|
Maximum
|
|
|
65
|
|
|
|
37
|
|
|
|
Minimum
|
|
|
35
|
|
|
|
15
|
|
|
|
|
|
|
|
|
(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 relative immaturity 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
September 30, 2008, for the entire term of these
instruments entered into for both asset management and trading
was approximately $16 million.
Interest
Rate Risk
NRG is exposed to fluctuations in interest rates through the
Companys issuance of fixed rate and variable rate debt.
Exposures to interest rate fluctuations may be mitigated by
entering into derivative instruments known as interest rate
swaps, caps, collars and put or call options. These contracts
reduce exposure to interest rate volatility and result in
primarily fixed rate debt obligations when taking into account
the combination of the variable rate debt and the interest rate
derivative instrument. NRGs risk management policies allow
the Company to reduce interest rate exposure from variable rate
debt obligations.
As of September 30, 2008, the Company had various interest
rate swap agreements with notional amounts totaling
approximately $2.6 billion. If the swaps had been
discontinued on September 30, 2008, the Company would have
owed the counterparties approximately $74 million. Based on
a diverse group of counterparties, NRG believes its exposure to
credit risk due to nonperformance by counterparties to its hedge
contracts to be insignificant. In addition, due to the fact that
the interest rate environment at that time was lower than the
interest rates in NRGs interest rate swaps, NRG could then
engage in new interest rate swaps at improved rates in the event
of default by its counterparties.
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 September 30, 2008, a
100 basis point change in interest rates would result in a
$13 million change in interest expense on a rolling twelve
month basis.
As of September 30, 2008, the Companys long-term debt
fair value was $7.2 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 $420 million.
81
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 would cause a change in margin collateral outstanding
of approximately $69 million as of September 30, 2008.
This analysis uses simplified assumptions and is calculated
based on portfolio composition and margin-related contract
provisions as of September 30, 2008.
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.
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.
The following table highlights the counterparty credit exposure (net
of collateral) to NRG, or Net Exposure, by industry sector and by
credit quality. Counterparty credit exposure is NRGs net
in-the-money position for a counterparty after giving effect to any
netting that is permitted under the enabling agreements and includes
all cash flow, mark to market and normal purchase and sale and
non-derivative transactions. As of
September 30, 2008, aggregate counterparty credit exposure to
substantially all counterparties was $1.2 billion and NRG held
collateral (cash and letters of credit) against those positions of
$236 million resulting in aggregate Net Exposure of
$1.0 billion.
|
|
|
|
|
|
|
|
|
Net Exposure (a)
|
|
|
|
Category
|
|
(% of Total)
|
|
|
|
|
Coal producers
|
|
|
42
|
%
|
|
|
Financial institutions
|
|
|
32
|
%
|
|
|
Utilities, energy, merchants and marketers
|
|
|
17
|
%
|
|
|
ISOs
|
|
|
9
|
%
|
|
|
|
|
Total as of September 30, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Exposure (a)
|
|
|
|
Category
|
|
(% of Total)
|
|
|
|
|
Investment grade
|
|
|
52
|
%
|
|
|
Non-Investment grade
|
|
|
27
|
%
|
|
|
Non-rated
|
|
|
21
|
%
|
|
|
|
|
Total as of September 30, 2008
|
|
|
100
|
%
|
|
|
|
|
|
|
|
(a) |
|
Excludes California tolling, uranium, coal
transportation/railcar leases, New England Reliability Must Run,
and Texas Westmoreland coal contracts. |
82
NRGs Net Exposure to those counterparties individually
representing more than 10% of its total Net Exposure was $252 million
in the aggregate. No counterparty represents more than 15% of total
Net Exposure. Approximately three-quarters of NRGs Net Exposure
rolls off by the end of 2010. Changes in hedge positions and market
prices will affect Net 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.
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 instruments are
recognized in earnings. These trading activities are a
complement to NRGs energy marketing portfolio.
The tables below disclose the activities that include all
derivative 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 as of September 30, 2008, based on whether fair
values are determined by quoted market prices or more subjective
means; and indicate the maturities of contracts:
|
|
|
|
|
|
|
Derivative Activity Losses
|
|
(In millions)
|
|
|
|
|
Fair value of contracts as of December 31, 2007
|
|
$
|
(492
|
)
|
|
|
Contracts realized or otherwise settled during the period
|
|
|
163
|
|
|
|
Changes in fair value
|
|
|
155
|
|
|
|
|
|
Fair value of contracts as of September 30, 2008
|
|
$
|
(174
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of September 30, 2008
|
|
|
Maturity
|
|
|
|
|
|
|
|
|
Maturity
|
|
|
|
|
|
|
(In millions)
|
|
Less than
|
|
|
Maturity
|
|
|
Maturity
|
|
|
in excess
|
|
|
Total Fair
|
|
|
|
Sources of Fair Value Gains/(Losses)
|
|
1 Year
|
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
5 Years
|
|
|
Value
|
|
|
|
|
Prices actively quoted
|
|
$
|
(8
|
)
|
|
$
|
7
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
(1
|
)
|
|
|
Prices provided by other external sources
|
|
|
162
|
|
|
|
(323
|
)
|
|
|
(19
|
)
|
|
|
(12
|
)
|
|
|
(192
|
)
|
|
|
Prices provided by models and other valuation methods
|
|
|
13
|
|
|
|
5
|
|
|
|
1
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
Total
|
|
$
|
167
|
|
|
$
|
(311
|
)
|
|
$
|
(18
|
)
|
|
$
|
(12
|
)
|
|
$
|
(174
|
)
|
|
|
|
|
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 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 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 11% 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 risk of default. If the exposure under a
specific master agreement is a liability, the Company is using
NRGs probability of default. 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 September 30, 2008 the credit reserve resulted in a
$6 million decrease in fair value which is composed of a
$5 million gain in OCI and an $11 million loss in
derivative revenue. The fair values in each category reflect the
level of forward prices and volatility factors as of
September 30, 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.
83
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 the
Item 3 Commodity Price Risk section
above, NRG measures the sensitivity of the Companys
portfolio to potential changes in market prices using 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. However, the Companys
trade-by-trade
derivative accounting results in a
gross-up of
the Companys derivative assets and liabilities. Thus, the
net derivative assets and liability position is a better
indicator of our hedging activity. As of September 30,
2008, NRGs net derivative liability was $174 million,
an increase to total fair value of $318 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
deals that settled during the period.
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 September 30,
2008, there were no foreign currency options or forward
contracts outstanding. Due to 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 as of
September 30, 2008.
|
|
ITEM 4
|
CONTROLS
AND PROCEDURES
|
Evaluation
of Disclosure Controls and Procedures
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 its disclosure
controls and procedures, as such term is defined in
Rules 13a-15(e)
and
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 report on
Form 10-Q.
Changes
in Internal Control over Financial Reporting
There have been no changes in the Companys internal
control over financial reporting (as such term is defined in
Rules 13a-15(f)
and
15d-15(f)
under the Exchange Act) during the current period covered by
this report on
Form 10-Q
that have materially affected, or are reasonably likely to
materially affect the Companys internal control over
financial reporting.
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. However, 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.
84
PART II
OTHER INFORMATION
|
|
ITEM 1
|
LEGAL
PROCEEDINGS
|
For a discussion of material legal proceedings in which NRG was
involved through September 30, 2008, see Note 14,
Commitments and Contingencies, to the condensed
consolidated financial statements of this
Form 10-Q.
Information regarding risk factors appears in Part I,
Item 1A, Risk Factors in NRG Energy, Inc.s 2007
Annual Report on
Form 10-K
for the fiscal year ended December 31, 2007.
|
|
ITEM 2
|
UNREGISTERED
SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
|
|
|
Item 2(c)
|
Purchase
of Equity securities by NRG
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number of shares
|
|
|
Dollar value of
|
|
|
|
|
|
|
|
|
|
|
|
purchased as part of
|
|
|
shares that may be
|
|
|
|
|
|
Total number of
|
|
|
Average price
|
|
|
publicly announced
|
|
|
purchased under the
|
|
|
|
For the period ended October 27, 2008
|
|
shares purchased
|
|
|
paid per share
|
|
|
plans or programs
|
|
|
plans or programs
|
|
|
|
|
First Quarter 2008 Total
|
|
|
1,281,600
|
|
|
$
|
42.73
|
|
|
|
1,281,600
|
|
|
$
|
160,008,401
|
|
|
|
|
|
Second Quarter 2008 Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
160,008,401
|
|
|
|
|
|
July 1 July 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 1 August 31
|
|
|
3,410,283
|
|
|
|
38.06
|
|
|
|
3,410,283
|
|
|
|
30,226,541
|
|
|
|
September 1 September 31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Quarter 2008 Total
|
|
|
3,410,283
|
|
|
|
38.06
|
|
|
|
3,410,283
|
|
|
|
30,226,541
|
|
|
|
|
|
October 1 October 27, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-to-date
|
|
|
4,691,883
|
|
|
$
|
39.33
|
|
|
|
4,691,883
|
|
|
$
|
30,266,541
|
|
|
|
|
|
On February 28, 2008, NRG announced a $300 million
stock buyback as part of the Companys 2008 Capital
Allocation Program. As discussed in Note 8, Changes in
Capital Structure, the Company initiated its 2008 program in
December 2007.
|
|
ITEM 3
|
DEFAULTS
UPON SENIOR SECURITIES
|
None.
|
|
ITEM 4
|
SUBMISSION
OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
None.
|
|
ITEM 5
|
OTHER
INFORMATION
|
None.
85
|
|
|
|
|
Exhibits
|
|
|
|
3
|
.1
|
|
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.
|
|
10
|
.1
|
|
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.
|
|
10
|
.2
|
|
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.
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
31
|
.3
|
|
Certification of Chief Accounting Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
32
|
|
|
Certification of Chief Executive Officer, Chief Financial
Officer and Chief Accounting Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002,
18 U.S.C. Section 1350, filed herewith.
|
86
SIGNATURES
Pursuant to the requirements 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)
/s/ JAMES J. INGOLDSBY
James J. Ingoldsby
Chief Accounting Officer
(Principal Accounting Officer)
Date: October 30, 2008
87
EXHIBIT INDEX
|
|
|
|
|
Exhibits
|
|
|
|
3
|
.1
|
|
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.
|
|
10
|
.1
|
|
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.
|
|
10
|
.2
|
|
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.
|
|
31
|
.1
|
|
Certification of Chief Executive Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
31
|
.2
|
|
Certification of Chief Financial Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
31
|
.3
|
|
Certification of Chief Accounting Officer pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, filed
herewith.
|
|
32
|
|
|
Certification of Chief Executive Officer, Chief Financial
Officer and Chief Accounting Officer pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002,
18 U.S.C. Section 1350, filed herewith.
|
88