e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended: June 30, 2010
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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 |
(State or other jurisdiction
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(I.R.S. Employer |
of incorporation or organization)
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Identification No.) |
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211 Carnegie Center, Princeton, New Jersey
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08540 |
(Address of principal executive offices)
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(Zip Code) |
(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 shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
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.
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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 Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.
Yes þ No o
As of July 29, 2010, there were 253,184,870 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 of NRG Energy, Inc., or NRG or the Company, includes
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended,
or 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 Factors Related to NRG Energy, Inc. in Part I, Item 1A, of the Companys
Annual Report on Form 10-K, for the year ended December 31, 2009, 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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Volatile power supply costs and demand for power; |
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Hazards customary to the power production industry and power generation operations such
as fuel and electricity price volatility, unusual weather conditions, catastrophic
weather-related or other damage to facilities, unscheduled generation outages, maintenance
or repairs, unanticipated changes to fuel supply costs or availability due to higher demand,
shortages, transportation problems or other developments, environmental incidents, or
electric transmission or gas pipeline system constraints and the possibility that NRG may
not have adequate insurance to cover losses as a result of such hazards; |
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The effectiveness of NRGs risk management policies and procedures, and the ability of
NRGs counterparties to satisfy their financial commitments; |
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Counterparties collateral demands and other factors affecting NRGs liquidity position
and financial condition; |
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NRGs ability to operate its businesses efficiently, manage capital expenditures and
costs tightly, and generate earnings and cash flows from its asset-based businesses in
relation to its debt and other obligations; |
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NRGs ability to enter into contracts to sell power and procure fuel on acceptable terms
and prices; |
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The liquidity and competitiveness of wholesale markets for energy commodities; |
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Government regulation, including compliance with regulatory requirements and changes in
market rules, rates, tariffs and environmental laws and increased regulation of carbon
dioxide and other greenhouse gas emissions; |
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Price mitigation strategies and other market structures employed by ISOs or RTOs that
result in a failure to adequately compensate NRGs generation units for all of its costs;
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NRGs ability to borrow additional funds and access capital markets, as well as NRGs
substantial indebtedness and the possibility that NRG may incur additional indebtedness
going forward; |
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Operating and financial restrictions placed on NRG and its subsidiaries that are
contained in the indentures governing NRGs outstanding notes, in NRGs Senior Credit
Facility, and in debt and other agreements of certain of NRG subsidiaries and project
affiliates generally; |
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NRGs ability to implement its RepoweringNRG strategy of developing and building new
power generation facilities, including new nuclear, wind and solar 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 natural resources while taking advantage of
business opportunities; |
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NRGs ability to implement its FORNRG strategy of increasing the return on invested
capital through operational performance improvements and a range of initiatives at plants
and corporate offices to reduce costs or generate revenues; |
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NRGs ability to achieve its strategy of regularly returning capital to shareholders; |
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Reliant Energys ability to maintain market share; |
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NRGs ability to successfully evaluate investments in new business and growth
initiatives; and |
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NRGs ability to successfully integrate and manage acquired businesses. |
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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Baseload capacity
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Electric power generation capacity normally expected to serve loads on an
around-the-clock basis throughout the calendar year |
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BTU
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British Thermal Unit |
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CAA
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Clean Air Act |
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CAIR
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Clean Air Interstate Rule |
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CAISO
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California Independent System Operator |
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CATR
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Clean Air Transport Rule |
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Capital Allocation Plan
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Share repurchase program |
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Capital Allocation Program
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NRGs plan of allocating capital between debt reduction, reinvestment in the
business, and share repurchases through the Capital Allocation
Plan |
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C&I
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Commercial, industrial and governmental/institutional |
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CFTC
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U.S. Commodity Futures Trading Commission |
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CO2
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Carbon dioxide |
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CPS
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CPS Energy |
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CSF Debt
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CSF I and CSF II issued notes and preferred interest, individually referred to
as CSF I Debt and CSF II Debt |
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CSRA
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Credit Sleeve Reimbursement Agreement with Merrill Lynch in connection with
acquisition of Reliant Energy, as hereinafter defined |
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CSRA Amendment
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Amendment of the existing CSRA with Merrill Lynch which became effective October
5, 2009 |
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DNREC
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Delaware Department of Natural Resources and Environmental Control |
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ERCOT
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Electric Reliability Council of Texas, the Independent System Operator and the
regional reliability coordinator of the various electricity systems
within Texas |
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Exchange Act
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The Securities Exchange Act of 1934, as amended |
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Expected Baseload Generation
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The net baseload generation limited by economic factors (relationship between
cost of generation and market price) and reliability factors (scheduled and
unplanned outages) |
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FASB
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Financial Accounting Standards Board the designated organization for
establishing standards for financial accounting and
reporting |
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FERC
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Federal Energy Regulatory Commission |
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Funded Letter of Credit Facility
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NRGs $1.3 billion term loan-backed fully funded senior secured letter of credit
facility, of which $500 million matures on February 1, 2013, and $800 million
matures on August 31, 2015, and is a component of NRGs
Senior Credit Facility |
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GHG
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Greenhouse Gases |
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GWh
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Gigawatt hour |
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IGCC
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Integrated Gasification Combined Cycle |
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ISO
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Independent System Operator, also referred to as Regional Transmission
Organizations, or RTO |
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ISO-NE
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ISO New England Inc. |
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kV
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Kilovolts |
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kW
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Kilowatts |
4
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kWh
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Kilowatt-hours |
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LIBOR
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London Inter-Bank Offer Rate |
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LTIP
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Long-Term Incentive Plan |
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MACT
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Maximum Achievable Control Technology |
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Mass
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Residential and small business |
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Merit Order
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A term used for the ranking of power stations in order of ascending marginal cost |
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MIBRAG
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Mitteldeutsche Braunkohlengesellschaft mbH |
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MMBtu
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Million British Thermal Units |
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MW
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Megawatts |
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MWh
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Saleable megawatt hours net of internal/parasitic load megawatt-hours |
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NAAQS
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National Ambient Air Quality Standards |
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NINA
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Nuclear Innovation North America LLC |
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NOx
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Nitrogen oxide |
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NPNS
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Normal Purchase Normal Sale |
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NRC
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U.S. Nuclear Regulatory Commission |
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NYISO
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New York Independent System Operator |
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OCI
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Other comprehensive income |
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Phase II 316(b) Rule
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A section of the Clean Water Act regulating cooling water intake structures |
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PJM
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PJM Interconnection, LLC |
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PJM market
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The wholesale and retail electric market operated by PJM primarily in all or
parts of Delaware, the District of Columbia, Illinois, Maryland, New Jersey,
Ohio, Pennsylvania, Virginia and West Virginia |
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PPA
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Power Purchase Agreement |
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PUCT
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Public Utility Commission of Texas |
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Reliant Energy
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NRGs retail business in Texas purchased on May 1, 2009, from Reliant Energy,
Inc. which is now known as RRI Energy, Inc., or RRI |
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Repowering
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Technologies utilized to replace, rebuild, or redevelop major portions of an
existing electrical generating facility, not only to achieve a substantial
emissions reduction, but also to increase facility capacity, and improve system
efficiency |
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RepoweringNRG
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NRGs program designed to develop, finance, construct and operate new, highly
efficient, environmentally responsible capacity |
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RERH
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RERH Holding, LLC and its subsidiaries |
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Revolving Credit Facility
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NRGs $875 million senior secured revolving credit facility, which matures on
August 31, 2015, and is a component of NRGs Senior Credit
Facility |
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RGGI
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Regional Greenhouse Gas Initiative |
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RMR
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Reliability Must-Run |
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ROIC
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Return on invested capital |
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RRI
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RRI Energy, Inc. (formerly Reliant Energy, Inc.) |
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Sarbanes-Oxley
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Sarbanes-Oxley Act of 2002, as amended |
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SEC
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United States Securities and Exchange Commission |
5
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Securities Act
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The Securities Act of 1933, as amended |
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Senior Credit Facility
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NRGs senior secured facility, which is comprised of a Term Loan Facility, an
$875 million Revolving Credit Facility and a $1.3 billion Funded Letter of
Credit Facility |
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Senior Notes
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The Companys $5.4 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, $1.1 billion of 7.375% senior notes due 2017, and $700 million of 8.5%
senior notes due 2019 |
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SO2
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Sulfur dioxide |
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STP
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South Texas Project nuclear generating facility located near Bay City, Texas
in which NRG owns a 44% Interest |
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STPNOC
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South Texas Project Nuclear Operating Company |
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TANE
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Toshiba America Nuclear Energy Corporation |
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TANE Facility
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NINAs
$500 million credit facility with TANE which matures on
February 24, 2012 |
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TEPCO
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The Tokyo Electric Power Company of Japan, Inc. |
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Term Loan Facility
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A senior first priority secured term loan, of which approximately $975 million
matures on February 1, 2013 and $1.0 billion matures on August 31, 2015, and is
a component of NRGs Senior Credit Facility |
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TNEA
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TEPCO Nuclear Energy America LLC |
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Tonnes
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Metric tonnes, which are units of mass or weight in the metric system each equal
to 2,205lbs and are the global measurement for GHG |
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TWh
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Terawatt hour |
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U.S.
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United States of America |
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U.S. DOE
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United States Department of Energy |
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U.S. EPA
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United States Environmental Protection Agency |
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U.S. GAAP
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Accounting principles generally accepted in the United States |
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VaR
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Value at Risk |
6
ACCOUNTING PRONOUNCEMENTS
The FASB has established the FASB Accounting Standards Codification, or ASC, as the source of
authoritative U.S. GAAP. The FASB issues updates to the ASC through Accounting Standards Updates,
or ASUs. The following ASC topics and ASUs are referenced in this report:
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ASC 280
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ASC-280, Segment Reporting |
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ASC 450
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ASC-450, Contingencies |
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ASC 740
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ASC-740, Income Taxes |
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ASC 805
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ASC-805, Business Combinations |
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ASC 810
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ASC-810, Consolidation |
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ASC 815
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ASC-815, Derivatives and Hedging |
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ASC 820
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ASC-820, Fair Value Measurements and Disclosures |
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ASC 980
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ASC-980, Regulated Operations |
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ASU 2009-15
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ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of
Convertible Debt Issuance or Other Financing |
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ASU 2009-17
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ASU No. 2009-17, Consolidations: Improvements to Financial Reporting by
Enterprises Involved with Variable Interest Entities |
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ASU 2010-02
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ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases
in Ownership of a Subsidiarya Scope Clarification |
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ASU 2010-06
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ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures
about Fair Value Measurements |
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ASU 2010-09
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ASU No. 2010-09, Subsequent Events (Topic 815): Amendments to Certain Recognition
and Disclosure Requirements |
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ASU 2010-10
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ASU No. 2010-10, Consolidation (Topic 810): Amendments for Certain Investment Funds |
7
PART I FINANCIAL INFORMATION
ITEM 1 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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Three months ended June 30, |
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Six months ended June 30, |
(In millions, except for per share amounts) |
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2010 |
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2009 |
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2010 |
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2009 |
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Operating Revenues |
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Total operating revenues |
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$ |
2,133 |
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$ |
2,237 |
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$ |
4,348 |
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$ |
3,895 |
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Operating Costs and Expenses |
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Cost of operations |
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1,329 |
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1,242 |
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2,968 |
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2,008 |
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Depreciation and amortization |
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208 |
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213 |
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410 |
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382 |
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Selling, general and administrative |
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139 |
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131 |
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269 |
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214 |
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Acquisition-related transaction and integration costs |
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23 |
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35 |
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Development costs |
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13 |
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9 |
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22 |
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22 |
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Total operating costs and expenses |
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1,689 |
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1,618 |
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3,669 |
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2,661 |
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Gain on sale of assets |
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23 |
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Operating Income |
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444 |
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619 |
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702 |
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1,234 |
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Other Income/(Expense) |
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Equity in earnings of unconsolidated affiliates |
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11 |
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5 |
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25 |
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27 |
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Gain on sale of equity method investment |
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128 |
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128 |
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Other income/(expense), net |
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19 |
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(11 |
) |
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23 |
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(14 |
) |
Interest expense |
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(147 |
) |
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(159 |
) |
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(300 |
) |
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(297 |
) |
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Total other expense |
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(117 |
) |
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(37 |
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(252 |
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(156 |
) |
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Income Before Income Taxes |
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327 |
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582 |
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450 |
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1,078 |
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Income tax expense |
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|
117 |
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|
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150 |
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|
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182 |
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|
|
448 |
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Net Income |
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|
210 |
|
|
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432 |
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|
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268 |
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630 |
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Less: Net loss attributable to noncontrolling interest |
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(1 |
) |
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(1 |
) |
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(1 |
) |
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(1 |
) |
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Net income attributable to NRG Energy, Inc. |
|
|
211 |
|
|
|
433 |
|
|
|
269 |
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|
631 |
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Dividends for preferred shares |
|
|
3 |
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7 |
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5 |
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21 |
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Income Available for NRG Energy, Inc. Common Stockholders |
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$ |
208 |
|
|
$ |
426 |
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$ |
264 |
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$ |
610 |
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Earnings per share attributable to NRG Energy, Inc. Common
Stockholders |
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Weighted average number of common shares outstanding basic |
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255 |
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253 |
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254 |
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245 |
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Net Income per Weighted Average Common Share basic |
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$ |
0.82 |
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$ |
1.68 |
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$ |
1.04 |
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$ |
2.49 |
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Weighted average number of common shares outstanding diluted |
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256 |
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275 |
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256 |
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275 |
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Net Income per Weighted Average Common Share diluted |
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$ |
0.81 |
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$ |
1.56 |
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$ |
1.03 |
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$ |
2.27 |
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See notes to condensed consolidated financial statements.
8
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
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June 30, 2010 |
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December 31, 2009 |
(In millions, except shares) |
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(unaudited) |
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ASSETS |
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Current Assets |
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Cash and cash equivalents |
|
$ |
2,168 |
|
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$ |
2,304 |
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Funds deposited by counterparties |
|
|
310 |
|
|
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177 |
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Restricted cash |
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13 |
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2 |
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Accounts receivable trade, less allowance for doubtful accounts of $21 and $29, respectively |
|
|
909 |
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|
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876 |
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Inventory |
|
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535 |
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|
541 |
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Derivative instruments valuation |
|
|
1,800 |
|
|
|
1,636 |
|
Cash collateral paid in support of energy risk management activities |
|
|
391 |
|
|
|
361 |
|
Prepayments and other current assets |
|
|
243 |
|
|
|
311 |
|
|
Total current assets |
|
|
6,369 |
|
|
|
6,208 |
|
|
Property, plant and equipment, net of accumulated depreciation of $3,414 and $3,052, respectively |
|
|
11,793 |
|
|
|
11,564 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
Equity investments in affiliates |
|
|
394 |
|
|
|
409 |
|
Note receivable affiliate and capital leases, less current portion |
|
|
434 |
|
|
|
504 |
|
Goodwill |
|
|
1,716 |
|
|
|
1,718 |
|
Intangible assets, net of accumulated amortization of $862 and $648, respectively |
|
|
1,626 |
|
|
|
1,777 |
|
Nuclear decommissioning trust fund |
|
|
360 |
|
|
|
367 |
|
Derivative instruments valuation |
|
|
910 |
|
|
|
683 |
|
Restricted cash supporting funded letter of credit facility |
|
|
1,300 |
|
|
|
|
|
Other non-current assets |
|
|
201 |
|
|
|
148 |
|
|
Total other assets |
|
|
6,941 |
|
|
|
5,606 |
|
|
Total Assets |
|
$ |
25,103 |
|
|
$ |
23,378 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases |
|
$ |
179 |
|
|
$ |
571 |
|
Accounts payable |
|
|
690 |
|
|
|
697 |
|
Derivative instruments valuation |
|
|
1,484 |
|
|
|
1,473 |
|
Deferred income taxes |
|
|
244 |
|
|
|
197 |
|
Cash collateral received in support of energy risk management activities |
|
|
310 |
|
|
|
177 |
|
Accrued expenses and other current liabilities |
|
|
623 |
|
|
|
647 |
|
|
Total current liabilities |
|
|
3,530 |
|
|
|
3,762 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
7,991 |
|
|
|
7,847 |
|
Funded letter of credit |
|
|
1,300 |
|
|
|
|
|
Nuclear decommissioning reserve |
|
|
309 |
|
|
|
300 |
|
Nuclear decommissioning trust liability |
|
|
234 |
|
|
|
255 |
|
Deferred income taxes |
|
|
1,768 |
|
|
|
1,783 |
|
Derivative instruments valuation |
|
|
433 |
|
|
|
387 |
|
Out-of-market contracts |
|
|
258 |
|
|
|
294 |
|
Other non-current liabilities |
|
|
1,002 |
|
|
|
806 |
|
|
Total non-current liabilities |
|
|
13,295 |
|
|
|
11,672 |
|
|
Total Liabilities |
|
|
16,825 |
|
|
|
15,434 |
|
|
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs) |
|
|
248 |
|
|
|
247 |
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock (at liquidation value, net of issuance costs) |
|
|
|
|
|
|
149 |
|
Common stock |
|
|
3 |
|
|
|
3 |
|
Additional paid-in capital |
|
|
5,311 |
|
|
|
4,948 |
|
Retained earnings |
|
|
3,596 |
|
|
|
3,332 |
|
Less treasury stock, at cost 50,625,606 and 41,866,451 shares, respectively |
|
|
(1,373 |
) |
|
|
(1,163 |
) |
Accumulated other comprehensive income |
|
|
476 |
|
|
|
416 |
|
Noncontrolling interest |
|
|
17 |
|
|
|
12 |
|
|
Total Stockholders Equity |
|
|
8,030 |
|
|
|
7,697 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
25,103 |
|
|
$ |
23,378 |
|
|
See notes to condensed consolidated financial statements.
9
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
Six months ended June 30, |
|
2010 |
|
2009 |
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
268 |
|
|
$ |
630 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Distributions and equity in earnings of unconsolidated affiliates |
|
|
(9 |
) |
|
|
(27 |
) |
Depreciation and amortization |
|
|
410 |
|
|
|
382 |
|
Provision for bad debts |
|
|
22 |
|
|
|
9 |
|
Amortization of nuclear fuel |
|
|
19 |
|
|
|
19 |
|
Amortization of financing costs and debt discount/premiums |
|
|
15 |
|
|
|
21 |
|
Amortization of intangibles and out-of-market contracts |
|
|
1 |
|
|
|
15 |
|
Changes in deferred income taxes and liability for unrecognized tax benefits |
|
|
179 |
|
|
|
445 |
|
Changes in nuclear decommissioning trust liability |
|
|
9 |
|
|
|
15 |
|
Changes in derivatives |
|
|
(55 |
) |
|
|
(368 |
) |
Changes in collateral deposits supporting energy risk management activities |
|
|
(30 |
) |
|
|
245 |
|
Gain on sale of assets, net |
|
|
(11 |
) |
|
|
(1 |
) |
Gain on sale of equity method investment |
|
|
|
|
|
|
(128 |
) |
Loss/(gain) on sale of emission allowances |
|
|
3 |
|
|
|
(9 |
) |
Gain recognized on settlement of pre-existing relationship |
|
|
|
|
|
|
(31 |
) |
Amortization of unearned equity compensation |
|
|
15 |
|
|
|
13 |
|
Changes in option premiums collected, net of acquisition |
|
|
34 |
|
|
|
(270 |
) |
Cash used by changes in other working capital, net of acquisition |
|
|
(265 |
) |
|
|
(238 |
) |
|
Net Cash Provided by Operating Activities |
|
|
605 |
|
|
|
722 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired |
|
|
(141 |
) |
|
|
(345 |
) |
Capital expenditures |
|
|
(330 |
) |
|
|
(374 |
) |
Increase in restricted cash, net |
|
|
(11 |
) |
|
|
(3 |
) |
Decrease/(increase) in notes receivable |
|
|
15 |
|
|
|
(11 |
) |
Purchases of emission allowances |
|
|
(45 |
) |
|
|
(52 |
) |
Proceeds from sale of emission allowances |
|
|
11 |
|
|
|
15 |
|
Investments in nuclear decommissioning trust fund securities |
|
|
(76 |
) |
|
|
(172 |
) |
Proceeds from sales of nuclear decommissioning trust fund securities |
|
|
67 |
|
|
|
157 |
|
Proceeds from renewable energy grants |
|
|
102 |
|
|
|
|
|
Proceeds from sale of assets, net |
|
|
30 |
|
|
|
6 |
|
Proceeds from sale of equity method investment |
|
|
|
|
|
|
284 |
|
Other |
|
|
(7 |
) |
|
|
(5 |
) |
|
Net Cash Used by Investing Activities |
|
|
(385 |
) |
|
|
(500 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
(5 |
) |
|
|
(21 |
) |
Payment for treasury stock |
|
|
(50 |
) |
|
|
|
|
Net receipt from/(payments for) acquired derivatives that include financing elements |
|
|
27 |
|
|
|
(22 |
) |
Installment proceeds from sale of noncontrolling interest in subsidiary |
|
|
50 |
|
|
|
50 |
|
Proceeds from issuance of long-term debt |
|
|
141 |
|
|
|
820 |
|
Proceeds from issuance of term loan for funded letter of credit facility |
|
|
1,300 |
|
|
|
|
|
Increase in restricted cash supporting funded letter of credit facility |
|
|
(1,300 |
) |
|
|
|
|
Proceeds from issuance of common stock |
|
|
2 |
|
|
|
|
|
Payment of deferred debt issuance costs |
|
|
(53 |
) |
|
|
(29 |
) |
Payments for short and long-term debt |
|
|
(459 |
) |
|
|
(233 |
) |
|
Net Cash (Used)/Provided by Financing Activities |
|
|
(347 |
) |
|
|
565 |
|
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
(9 |
) |
|
|
1 |
|
|
Net (Decrease)/Increase in Cash and Cash Equivalents |
|
|
(136 |
) |
|
|
788 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
2,304 |
|
|
|
1,494 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
2,168 |
|
|
$ |
2,282 |
|
|
See notes to condensed consolidated financial statements.
10
NRG ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company
with a significant presence in major competitive power markets in the United States, as well as a
major retail electricity provider in the ERCOT (Texas) market. NRG is engaged in the ownership,
development, construction and operation of power generation facilities, both conventional and
renewable, the transacting in and trading of fuel and transportation services, the trading of
energy, capacity and related products in the United States and select international markets, and
supply of electricity and energy services to retail electricity customers in the Texas market. The
Company also seeks to invest in and deploy new energy technologies.
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
following notes should be read in conjunction with the accounting policies and other disclosures as
set forth in the notes to the Companys financial statements in its Annual Report on Form 10-K for
the year ended December 31, 2009. Interim results are not necessarily indicative of results for a
full year.
In the opinion of management, the accompanying unaudited interim condensed consolidated
financial statements contain all material adjustments consisting of normal and recurring accruals
necessary to present fairly the Companys consolidated financial position as of June 30, 2010, the
results of operations for the three and six months ended June 30, 2010, and 2009, and cash flows
for the six months ended June 30, 2010 and 2009. 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.
Note 2 Summary of Significant Accounting Policies
Other Cash Flow Information
NRGs investing activities do not include non-cash capital expenditures of $113 million which
were accrued at June 30, 2010.
Recent Accounting Developments
ASU No. 2009-17 On January 1, 2010, the Company adopted the provisions of ASU No. 2009-17,
Consolidations: Improvements to Financial Reporting by Enterprises Involved with Variable Interest
Entities, or ASU 2009-17. This guidance amends ASC 810 by altering how a company determines when
an entity that is insufficiently capitalized or not controlled through its voting interests should
be consolidated. The previous ASC 810 guidance required a quantitative analysis of the economic
risk/rewards of a Variable Interest Entity, or a VIE, to determine the primary beneficiary. ASU
2009-17 specifies that a qualitative analysis be performed, requiring the primary beneficiary to
have both the power to direct the activities of a VIE that most significantly impact the entities
economic performance, as well as either the obligation to absorb losses or the right to receive
benefits that could potentially be significant to the VIE. The Companys adoption of ASU 2009-17
on January 1, 2010, did not have an impact on its results of operations, financial position or cash
flows.
ASU No. 2010-10 In February 2010, the FASB issued ASU No. 2010-10, Consolidation (Topic
810): Amendments for Certain Investment Funds, or ASU 2010-10. The amendments to ASC 810 clarify
that related parties should be considered when evaluating the criteria for determining whether a
decision makers or service providers fee represents a variable interest. In addition, the
amendments clarify that a quantitative calculation should not be the sole basis for evaluating
whether a decision makers or service providers fee represents a variable interest. The Company
adopted the provisions of ASU 2010-10 effective January 1, 2010, with no impact on its results of
operations, financial position or cash flows.
11
Other effects of ASU 2009-17/ASU 2010-10 adoption NRG determined that one of its equity
method investments was a VIE as of January 1, 2010, upon adoption of this new guidance. NRG owns a
50% interest in Sherbino I Wind Farm LLC, or Sherbino, a 150MW wind farm operated as a joint
venture with BP Wind Energy North America Inc., or BP Wind. The Company has determined that
Sherbino is a VIE, but the Company is not the primary beneficiary, under the amended guidance in
ASU 2009-17 and ASU 2010-10. Therefore, NRG will continue to account for its investment in
Sherbino under the equity method. NRGs maximum exposure to loss is limited to its equity
investment, which is $94 million as of June 30, 2010.
Borrowings of an equity method investment In December 2008, Sherbino entered into a 15-year
term loan facility which is non-recourse to NRG. As of June 30, 2010, the outstanding principal
balance of the term loan facility was $131 million, and is secured by substantially all of
Sherbinos assets and membership interests.
ASU No. 2010-09 In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic
855): Amendments to Certain Recognition and Disclosure Requirements, or ASU 2010-09. Under the
amendments of ASU 2010-09, an entity that is an SEC filer is not required to disclose the date
through which subsequent events have been evaluated. As this guidance provides only disclosure
requirements, the adoption of ASU 2010-09 effective January 1, 2010, did not impact the Companys
results of operations, financial position or cash flows.
Other The following accounting standards were adopted on January 1, 2010, with no impact on
the Companys results of operations, financial position or cash flows:
|
|
|
ASU No. 2009-15, Accounting for Own-Share Lending Arrangements in Contemplation of
Convertible Debt Issuance or Other Financing, or ASU 2009-15. |
|
|
|
ASU No. 2010-02, Consolidation (Topic 810): Accounting and Reporting for Decreases in
Ownership of a Subsidiarya Scope Clarification, or ASU 2010-02. |
|
|
|
ASU No. 2010-06, Fair Value Measurement and Disclosures: Improving Disclosures about Fair
Value Measurements, or ASU 2010-06. |
Note 3 Comprehensive Income/(Loss)
The following table summarizes the components of the Companys comprehensive income/(loss),
net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Net income attributable to NRG Energy, Inc. |
|
$ |
211 |
|
|
$ |
433 |
|
|
$ |
269 |
|
|
$ |
631 |
|
|
Changes in derivative activity |
|
|
(154 |
) |
|
|
(109 |
) |
|
|
103 |
|
|
|
64 |
|
Foreign currency translation adjustment |
|
|
(36 |
) |
|
|
36 |
|
|
|
(42 |
) |
|
|
18 |
|
Reclassification adjustment for translation gain
realized upon sale of foreign investments |
|
|
|
|
|
|
(22 |
) |
|
|
|
|
|
|
(22 |
) |
Unrealized (loss)/gain on available-for-sale securities |
|
|
(1 |
) |
|
|
1 |
|
|
|
(1 |
) |
|
|
2 |
|
|
Other comprehensive (loss)/income |
|
|
(191 |
) |
|
|
(94 |
) |
|
|
60 |
|
|
|
62 |
|
|
Comprehensive income attributable to NRG Energy, Inc. |
|
$ |
20 |
|
|
$ |
339 |
|
|
$ |
329 |
|
|
$ |
693 |
|
|
The following table summarizes the changes in the Companys accumulated other comprehensive
income, net of tax:
|
|
|
|
|
(In millions) |
|
|
|
|
|
Accumulated other comprehensive income as of December 31, 2009 |
|
$ |
416 |
|
Changes in derivative activity |
|
|
103 |
|
Foreign currency translation adjustment |
|
|
(42 |
) |
Unrealized loss on available-for-sale securities |
|
|
(1 |
) |
|
Accumulated other comprehensive income as of June 30, 2010 |
|
$ |
476 |
|
|
12
Note 4 Business Acquisitions and Dispositions
Acquisition of Reliant Energy
On May 1, 2009, NRG, through its wholly-owned subsidiary, NRG Retail LLC, acquired Reliant
Energy from RRI Energy, Inc., or RRI, which consisted of the entire Texas electric retail business
operations of RRI, including the exclusive use of the trade name Reliant and related branding
rights. The acquisition of Reliant Energy was accounted for under the acquisition method of
accounting in accordance with ASC 805. Accordingly, NRG conducted an assessment of net assets
acquired and recognized identifiable assets acquired and liabilities assumed at their acquisition
date fair values. The accounting for this business combination was completed on March 31, 2010.
NRG paid RRI total cash consideration of approximately $370 million. NRG also recognized a
$31 million non-cash gain at the acquisition date, on the settlement of a pre-existing
relationship, representing the in-the-money value to NRG of an agreement that permits Reliant
Energy to call on certain NRG gas plants when necessary for Reliant Energy to meet its load
obligations. This non-cash gain was considered a component of consideration in accordance with ASC
805, and together with cash consideration, brings total consideration to approximately $401
million.
The following table summarizes the values assigned to the net assets acquired, including cash
acquired of $6 million, as of the acquisition date:
|
|
|
|
|
|
|
(In millions) |
Assets |
|
|
|
|
Current and non-current assets |
|
$ |
635 |
|
Property, plant and equipment |
|
|
72 |
|
Intangible assets subject to amortization: |
|
|
|
|
In-market customer contracts |
|
|
790 |
|
Customer relationships |
|
|
405 |
|
Trade names |
|
|
178 |
|
In-market energy supply contracts |
|
|
54 |
|
Other |
|
|
6 |
|
Derivative assets |
|
|
1,942 |
|
Deferred tax asset, net |
|
|
14 |
|
Goodwill |
|
|
|
|
|
Total assets acquired |
|
$ |
4,096 |
|
|
Liabilities |
|
|
|
|
Current and non-current liabilities |
|
$ |
556 |
|
Derivative liabilities |
|
|
2,996 |
|
Out-of-market energy supply and customer contracts |
|
|
143 |
|
|
Total liabilities assumed |
|
$ |
3,695 |
|
|
Net assets acquired |
|
$ |
401 |
|
|
13
Measurement period adjustments
The following measurement period adjustments to the provisional amounts, attributable to
refinement of the underlying appraisal assumptions, were recognized during 2009 subsequent to the
acquisition date and through the first quarter of 2010, the end of the measurement period:
|
|
|
|
|
|
|
Increase/(Decrease) |
|
|
(In millions) |
Assets |
|
|
|
|
Intangible assets subject to amortization: |
|
|
|
|
In-market customer contracts |
|
$ |
57 |
|
Customer relationships |
|
|
(76 |
) |
In-market energy supply contracts |
|
|
17 |
|
Deferred tax asset, net |
|
|
3 |
|
|
Total assets acquired |
|
|
1 |
|
|
Liabilities |
|
|
|
|
Current and non-current liabilities |
|
|
6 |
|
Out-of-market energy supply and customer contracts |
|
|
(5 |
) |
|
Total liabilities assumed |
|
|
1 |
|
|
Net assets acquired |
|
$ |
|
|
|
Other Acquisitions
Northwind Phoenix On June 22, 2010, NRG, through its wholly-owned subsidiary, NRG Thermal
LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix, for a total purchase
price of $100 million, plus a payment for acquired working capital true-ups. Northwind Phoenix
owns and operates a district cooling system that provides chilled water to commercial buildings in
the Phoenix central business district. In addition, Northwind Phoenix maintains and operates
Combined Heat and Power, or CHP, plants that provide chilled water, steam and electricity in
metropolitan Tucson and to portions of Arizona State University campuses in Tempe and Mesa. The
acquisition was financed by the issuance of $100 million in notes by NRG Thermal. See Note 8,
Long-Term Debt, for information related to the notes issued.
South Trent On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent
wind farm, or South Trent, a 101 MW wind farm near Sweetwater, Texas, for a total purchase price of
$111 million. South Trent commenced operations in January 2009 and consists of 44 turbines
producing up to 2.3 MW of power each. The project has a 20-year PPA, which commenced January 2009,
for all generation from the site. In connection with the acquisition, NRG paid $32 million in cash
and South Trent entered into a financing arrangement that includes a $79 million term loan. See
Note 8, Long-Term Debt, for information related to this financing arrangement.
Dispositions
Padoma On January 11, 2010, NRG sold its terrestrial wind development company, Padoma Wind
Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG retained its existing ownership
interest in its three Texas wind farms: Sherbino, Elbow Creek and Langford. In addition, NRG will
maintain a strategic partnership with Enel to evaluate potential opportunities in renewable energy,
including the opportunity to participate in wind projects currently in development. NRG recognized
a gain on the sale of Padoma of $23 million, which was recorded as a component of operating income
in the statement of operations.
MIBRAG On June 10, 2009, NRG sold its 50% ownership interest in Mibrag B.V. whose principal
holding was MIBRAG. For its share, NRG received EUR 203 million ($284 million at an exchange rate
of 1.40 U.S.$/EUR), net of transaction costs. During the three and six months ended June 30, 2009,
NRG recognized an after-tax gain of $128 million. Prior to completion of the sale, NRG continued
to record its share of MIBRAGs operations to Equity in earnings of unconsolidated affiliates. In
connection with the transaction, NRG entered into a foreign currency forward contract to hedge the
impact of exchange rate fluctuations on the sale proceeds. For the three and six months ended June
30, 2009, NRG recorded an exchange loss of $15 million and $24 million, respectively, on the
contract within Other income/(expense), net.
14
Note 5 Fair Value of Financial Instruments
The estimated carrying values and fair values of NRGs recorded financial instruments are as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying Amount |
|
Fair Value |
|
|
|
|
|
|
December 31, |
|
|
|
|
|
December 31, |
|
|
June 30, 2010 |
|
2009 |
|
June 30, 2010 |
|
2009 |
|
|
|
|
|
|
(In millions) |
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2,168 |
|
|
$ |
2,304 |
|
|
$ |
2,168 |
|
|
$ |
2,304 |
|
Funds deposited by counterparties |
|
|
310 |
|
|
|
177 |
|
|
|
310 |
|
|
|
177 |
|
Restricted cash |
|
|
13 |
|
|
|
2 |
|
|
|
13 |
|
|
|
2 |
|
Cash collateral paid in support of energy risk management
activities |
|
|
391 |
|
|
|
361 |
|
|
|
391 |
|
|
|
361 |
|
Investment in available-for-sale securities (classified
within other non-current assets): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities |
|
|
10 |
|
|
|
9 |
|
|
|
10 |
|
|
|
9 |
|
Marketable equity securities |
|
|
3 |
|
|
|
5 |
|
|
|
3 |
|
|
|
5 |
|
Trust fund investments |
|
|
362 |
|
|
|
369 |
|
|
|
362 |
|
|
|
369 |
|
Notes receivable |
|
|
221 |
|
|
|
231 |
|
|
|
232 |
|
|
|
238 |
|
Derivative assets |
|
|
2,710 |
|
|
|
2,319 |
|
|
|
2,710 |
|
|
|
2,319 |
|
Restricted cash supporting funded letter of credit facility |
|
|
1,300 |
|
|
|
|
|
|
|
1,300 |
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt, including current portion |
|
|
8,069 |
|
|
|
8,295 |
|
|
|
7,991 |
|
|
|
8,211 |
|
Funded letter of credit |
|
|
1,300 |
|
|
|
|
|
|
|
1,250 |
|
|
|
|
|
Cash collateral received in support of energy risk
management activities |
|
|
310 |
|
|
|
177 |
|
|
|
310 |
|
|
|
177 |
|
Derivative liabilities |
|
$ |
1,917 |
|
|
$ |
1,860 |
|
|
$ |
1,917 |
|
|
$ |
1,860 |
|
|
15
Recurring Fair Value Measurements
The following table presents assets and liabilities measured and recorded at fair value on the
Companys condensed consolidated balance sheet on a recurring basis and their level within the fair
value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Fair Value |
As of June 30, 2010 |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Cash and cash equivalents |
|
$ |
2,168 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,168 |
|
Funds deposited by counterparties |
|
|
310 |
|
|
|
|
|
|
|
|
|
|
|
310 |
|
Restricted cash |
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
Cash collateral paid in support of energy risk management activities |
|
|
391 |
|
|
|
|
|
|
|
|
|
|
|
391 |
|
Investment in available-for-sale securities (classified within other non-current assets): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
|
10 |
|
Marketable equity securities |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Trust fund investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
U.S. government and federal agency obligations |
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Federal agency mortgage-backed securities |
|
|
|
|
|
|
61 |
|
|
|
|
|
|
|
61 |
|
Commercial mortgage-backed securities |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
10 |
|
Corporate debt securities |
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
50 |
|
Marketable equity securities |
|
|
172 |
|
|
|
|
|
|
|
32 |
|
|
|
204 |
|
Foreign government fixed income securities |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Derivative assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
629 |
|
|
|
2,005 |
|
|
|
65 |
|
|
|
2,699 |
|
Interest rate contracts |
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
Restricted cash supporting funded letter of credit facility |
|
|
1,300 |
|
|
|
|
|
|
|
|
|
|
|
1,300 |
|
|
Total assets |
|
$ |
5,022 |
|
|
$ |
2,127 |
|
|
$ |
118 |
|
|
$ |
7,267 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash collateral received in support of energy risk management activities |
|
$ |
310 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
310 |
|
Derivative liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts |
|
|
681 |
|
|
|
967 |
|
|
|
152 |
|
|
|
1,800 |
|
Interest rate contracts |
|
|
|
|
|
|
117 |
|
|
|
|
|
|
|
117 |
|
|
Total liabilities |
|
$ |
991 |
|
|
$ |
1,084 |
|
|
$ |
152 |
|
|
$ |
2,227 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Fair Value |
As of December 31, 2009 |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Cash and cash equivalents |
|
$ |
2,304 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,304 |
|
Funds deposited by counterparties |
|
|
177 |
|
|
|
|
|
|
|
|
|
|
|
177 |
|
Restricted cash |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Cash collateral paid in support of energy risk management activities |
|
|
361 |
|
|
|
|
|
|
|
|
|
|
|
361 |
|
Investment in available-for-sale securities (classified within other non-current assets): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities |
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
9 |
|
Marketable equity securities |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
Trust fund investments |
|
|
214 |
|
|
|
118 |
|
|
|
37 |
|
|
|
369 |
|
Derivative assets |
|
|
489 |
|
|
|
1,767 |
|
|
|
63 |
|
|
|
2,319 |
|
|
Total assets |
|
$ |
3,552 |
|
|
$ |
1,885 |
|
|
$ |
109 |
|
|
$ |
5,546 |
|
|
Cash collateral received in support of energy risk management activities |
|
$ |
177 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
177 |
|
Derivative liabilities |
|
|
501 |
|
|
|
1,283 |
|
|
|
76 |
|
|
|
1,860 |
|
|
Total liabilities |
|
$ |
678 |
|
|
$ |
1,283 |
|
|
$ |
76 |
|
|
$ |
2,037 |
|
|
16
There have been no transfers during the three months and six months ended June 30, 2010,
between Levels 1 and 2. The following table reconciles the beginning and ending balances for
financial instruments that are recognized at fair value in the consolidated financial statements
using significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
Six months ended June 30, 2010 |
|
|
Debt |
|
Trust Fund |
|
|
|
|
|
|
|
|
|
Debt |
|
Trust Fund |
|
|
|
|
(In millions) |
|
Securities |
|
Investments |
|
Derivatives(a) |
|
Total |
|
Securities |
|
Investments |
|
Derivatives(a) |
|
Total |
|
Beginning Balance |
|
$ |
9 |
|
|
$ |
37 |
|
|
$ |
(25 |
) |
|
$ |
21 |
|
|
$ |
9 |
|
|
$ |
37 |
|
|
$ |
(13 |
) |
|
$ |
33 |
|
Total gains/(losses) (realized and unrealized) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
|
|
|
|
|
|
|
|
(63 |
) |
|
|
(63 |
) |
|
|
|
|
|
|
|
|
|
|
(31 |
) |
|
|
(31 |
) |
Included in OCI |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Included in nuclear decommissioning obligations |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Purchases |
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
9 |
|
Transfer into Level 3 (b) |
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
(47 |
) |
|
|
(47 |
) |
Transfer out of Level 3 (b) |
|
|
|
|
|
|
|
|
|
|
(11 |
) |
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
6 |
|
|
Ending balance as of June 30, 2010 |
|
$ |
10 |
|
|
$ |
32 |
|
|
$ |
(76 |
) |
|
$ |
(34 |
) |
|
$ |
10 |
|
|
$ |
32 |
|
|
$ |
(76 |
) |
|
$ |
(34 |
) |
|
The amount of the total gains for the period
included in earnings attributable to the change in
unrealized gains relating to assets still held as
of June 30, 2010 |
|
$ |
|
|
|
$ |
|
|
|
$ |
(61 |
) |
|
$ |
(61 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(36 |
) |
|
$ |
(36 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
Six months ended June 30, 2009 |
|
|
Debt |
|
Trust Fund |
|
|
|
|
|
|
|
|
|
Debt |
|
Trust Fund |
|
|
|
|
(In millions) |
|
Securities |
|
Investments |
|
Derivatives(a) |
|
Total |
|
Securities |
|
Investments |
|
Derivatives(a) |
|
Total |
|
Beginning Balance |
|
$ |
7 |
|
|
$ |
27 |
|
|
$ |
126 |
|
|
$ |
160 |
|
|
$ |
7 |
|
|
$ |
31 |
|
|
$ |
49 |
|
|
$ |
87 |
|
Total gains/(losses) (realized and unrealized) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
|
|
|
|
|
|
|
|
(49 |
) |
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
(30 |
) |
|
|
(30 |
) |
Included in nuclear decommissioning obligations |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Purchases/(sales), net |
|
|
|
|
|
|
1 |
|
|
|
(8 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
1 |
|
|
|
(4 |
) |
|
|
(3 |
) |
Transfer in/(out) of Level 3 (b) |
|
|
|
|
|
|
|
|
|
|
(19 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
35 |
|
|
Ending balance as of June 30, 2009 |
|
$ |
7 |
|
|
$ |
34 |
|
|
$ |
50 |
|
|
$ |
91 |
|
|
$ |
7 |
|
|
$ |
34 |
|
|
$ |
50 |
|
|
$ |
91 |
|
|
The amount of the total gains for the period
included in earnings attributable to the change in
unrealized gains relating to assets still held as
of June 30, 2009 |
|
$ |
|
|
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
28 |
|
|
$ |
28 |
|
|
|
|
|
(a) |
|
Consists of derivative assets and liabilities, net. |
|
(b) |
|
Transfers in/(out) of Level 3 are related to the availability of external broker quotes. All
transfers out are to Level 2. |
Realized and unrealized gains and losses included in earnings that are related to the
energy derivatives are recorded in operating revenues and cost of operations.
In determining the fair value of NRGs Level 2 and 3 derivative contracts, NRG applies a
credit reserve to reflect credit risk which is calculated based on credit default swaps. As of
June 30, 2010, the credit reserve resulted in an $11 million decrease in fair value which is
composed of a $6 million loss in OCI and a $5 million loss in operating revenue and cost of
operations.
Concentration of Credit Risk
In addition to the credit risk discussion as disclosed 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, 2009, the following item is a discussion of the concentration of credit
risk for the Companys financial instruments. 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. NRG is exposed to counterparty credit risk through various activities including
wholesale sales, fuel purchases and retail supply and retail customer credit risk through its
retail load activities.
Counterparty Credit Risk
The Company monitors and manages counterparty 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, prepayment
arrangements, or volumetric limits; (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 credit risk with a diversified portfolio of counterparties. 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.
17
As of June 30, 2010, total counterparty credit exposure to substantially all counterparties
was $1.5 billion and NRG held cash collateral against those positions of $310 million and letters
of credit of $11 million, resulting in a net exposure of $1.2 billion. Total counterparty credit
exposure is discounted at the risk free rate.
The following table highlights the counterparty credit quality and the net counterparty credit
exposure by industry sector. Net counterparty credit exposure is defined as the aggregate net
asset position for NRG with counterparties where netting is permitted under the enabling agreement
and includes all cash flow, mark-to-market and Normal Purchase Normal Sale, or NPNS, and
non-derivative transactions. The exposure is shown net of collateral held, and includes amounts
net of receivables or payables.
|
|
|
|
|
|
|
Net Exposure(a) |
Category |
|
(% of Total) |
|
Financial institutions |
|
|
59 |
% |
Utilities, energy, merchants, marketers and other |
|
|
31 |
|
Coal suppliers |
|
|
4 |
|
ISOs |
|
|
6 |
|
|
Total as of June 30, 2010 |
|
|
100 |
% |
|
|
|
|
|
|
|
|
Net Exposure(a) |
Category |
|
(% of Total) |
|
Investment grade |
|
|
88 |
% |
Non-Investment grade |
|
|
2 |
|
Non-rated |
|
|
10 |
|
|
Total as of June 30, 2010 |
|
|
100 |
% |
|
|
|
|
(a) |
|
Counterparty credit exposure excludes California tolling, Northeast load obligations,
certain cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned
exposures were excluded for various reasons including regulatory support or liens held against
the contracts which serve to reduce the risk of loss. NRG also excludes uranium and coal
transportation contracts from counterparty credit exposure because of the illiquidity of the
reference markets. Credit exposure also excludes any exposure NRG has to counterparties of
non-recourse subsidiaries. |
NRG has counterparty credit risk exposure to certain counterparties representing more
than 10% of total net exposure and the aggregate of such counterparties was $409 million.
Approximately 89% of NRGs positions relating to credit risk roll-off by the end of 2012. Changes
in hedge positions and market prices will affect credit exposure and counterparty concentration.
Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not
anticipate a material impact on the Companys financial results or results of operations from
nonperformance by any of NRGs counterparties.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Companys competitive electricity supply
business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when
a customer fails to pay for services rendered. The losses could be incurred from nonpayment of
customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk
through the use of established credit policies that include monitoring of the portfolio, and the
use of credit mitigation measures such as deposits or prepayment arrangements.
As of June 30, 2010, the Companys retail customer credit exposure to C&I customers was
diversified across many customers and various industries, with a significant portion of the
exposure with government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which may
result in a write-off of bad debt. During 2010, the Company continued to experience improved
customer payment behavior, but current economic conditions may affect the Companys customers
ability to pay bills in a timely manner, which could increase customer delinquencies and may lead
to an increase in bad debt expense.
This footnote should be read in conjunction with the complete description under Note 5, Fair
Value of Financial Instruments, to the Companys financial statements in its Annual Report on Form
10-K for the year ended December 31, 2009.
18
Note 6 Nuclear Decommissioning Trust Fund
NRGs nuclear decommissioning trust fund assets, which are for its portion of the
decommissioning of the South Texas Project, or STP, are comprised of securities classified as
available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts
for the nuclear decommissioning trust fund in accordance with ASC-980 Regulated Operations, or
ASC 980. Since the Company is in compliance with the Public Utility Commission of Texas, or PUCT
rules and regulations regarding decommissioning trusts and the cost of decommissioning is the
responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses
(including other than-temporary-impairments) related to the Nuclear Decommissioning Trust Fund are
recorded to the Nuclear Decommissioning Trust Liability to the ratepayers and are not included in
net income or accumulated other comprehensive income, consistent with regulatory treatment.
The following table summarizes the aggregate fair values and unrealized gains and losses
(including other-than-temporary impairments) for the securities held in the trust funds as of June
30, 2010, and December 31, 2009, as well as information about the contractual maturities of those
securities. The cost of securities sold is determined on the specific identification method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of June 30, 2010 |
|
As of December 31, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
average |
|
|
|
|
|
|
|
|
|
|
|
|
|
average |
|
|
Fair |
|
Unrealized |
|
Unrealized |
|
maturities |
|
Fair |
|
Unrealized |
|
Unrealized |
|
maturities |
(In millions, except otherwise noted) |
|
Value |
|
gains |
|
losses |
|
(in years) |
|
Value |
|
gains |
|
losses |
|
(in years) |
|
Cash and cash equivalents |
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
|
|
|
|
|
|
U.S. government and federal agency
obligations |
|
|
25 |
|
|
|
2 |
|
|
|
|
|
|
|
11 |
|
|
|
23 |
|
|
|
1 |
|
|
|
|
|
|
|
8 |
|
Federal agency mortgage-backed
securities |
|
|
61 |
|
|
|
3 |
|
|
|
|
|
|
|
22 |
|
|
|
60 |
|
|
|
2 |
|
|
|
|
|
|
|
23 |
|
Commercial mortgage-backed securities |
|
|
10 |
|
|
|
|
|
|
|
1 |
|
|
|
30 |
|
|
|
10 |
|
|
|
|
|
|
|
1 |
|
|
|
29 |
|
Corporate debt securities |
|
|
50 |
|
|
|
3 |
|
|
|
|
|
|
|
10 |
|
|
|
48 |
|
|
|
3 |
|
|
|
1 |
|
|
|
10 |
|
Marketable equity securities |
|
|
204 |
|
|
|
73 |
|
|
|
3 |
|
|
|
|
|
|
|
220 |
|
|
|
89 |
|
|
|
2 |
|
|
|
|
|
Foreign government fixed income
securities |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
Total |
|
$ |
360 |
|
|
$ |
81 |
|
|
$ |
4 |
|
|
|
|
|
|
$ |
367 |
|
|
$ |
95 |
|
|
$ |
4 |
|
|
|
|
|
|
The following tables summarize proceeds from sales of available-for-sale securities and the
related realized gains and losses from these sales.
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
Realized gains |
|
$ |
2 |
|
|
$ |
2 |
|
Realized losses |
|
|
2 |
|
|
|
5 |
|
Proceeds from sale of securities |
|
|
67 |
|
|
|
157 |
|
|
19
Note 7 Accounting for Derivative Instruments and Hedging Activities
ASC 815 requires NRG to recognize all derivative instruments on the balance sheet as either
assets or liabilities and to measure them at fair value each reporting period unless they qualify
for a NPNS exception. If certain conditions are met, NRG may be able to designate certain
derivatives as cash flow hedges and defer the effective portion of the change in fair value of the
derivatives to accumulated OCI, until the hedged transactions occur and are recognized in earnings.
The ineffective portion of a cash flow hedge is immediately recognized in earnings.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes
in fair value of both the derivative and the hedged transaction are recorded in current earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge
accounting treatment, the changes in the fair value will be immediately recognized in earnings.
Under the guidelines established per ASC 815, certain derivative instruments may qualify for the
NPNS exception and are therefore exempt from fair value accounting treatment. ASC 815 applies to
NRGs energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
As the Company engages principally in the trading and marketing of its generation assets and
retail business, some of NRGs commercial activities qualify for hedge accounting under the
requirements of ASC 815. In order for the generation assets to qualify, the physical generation
and sale of electricity should be highly probable at inception of the trade and throughout the
period it is held, as is the case with the Companys baseload plants. For this reason, many trades
in support of NRGs baseload units normally qualify for NPNS or cash flow hedge accounting
treatment, and trades in support of NRGs peaking units asset optimization will generally not
qualify for hedge accounting treatment, with any changes in fair value likely to be reflected on a
mark-to-market basis in the statement of operations. Most of the retail load contracts either
qualify for the NPNS exception or fail to meet the criteria for a derivative and the majority of
the supply contracts are recorded under mark-to-market accounting. All of NRGs hedging and
trading activities are subject to limits within the Companys Risk Management Policy.
Energy-Related Commodities
To manage the commodity price risk associated with the Companys competitive supply activities
and the price risk associated with wholesale and retail power sales from the Companys electric
generation facilities, NRG may enter into a variety of derivative and non-derivative hedging
instruments, utilizing the following:
|
|
|
Forward contracts, which commit NRG to sell or purchase energy commodities or purchase
fuels in the future. |
|
|
|
Futures contracts, which are exchange-traded standardized commitments to purchase or sell
a commodity or financial instrument. |
|
|
|
Swap agreements, which require payments to or from counter-parties based upon the
differential between two prices for a predetermined contractual, or notional, quantity. |
|
|
|
Option contracts, which convey the right or obligation to purchase or sell a commodity. |
|
|
|
Weather and hurricane derivative products used to mitigate a portion of Reliant Energys
lost revenue due to weather. |
The objectives for entering into derivative contracts designated as hedges include:
|
|
|
Fixing the price for a portion of anticipated future electricity sales through the use of
various derivative instruments including gas collars and swaps at a level that provides an
acceptable return on the Companys electric generation operations. |
|
|
|
Fixing the price of a portion of anticipated fuel purchases for the operation of NRGs
power plants. |
As of June 30, 2010, NRG had cash flow hedge energy-related derivative financial instruments
extending through December 2013.
NRGs trading activities are subject to limits within 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.
20
Interest Rate Swaps
NRG is exposed to changes in interest rates through the Companys issuance of variable and
fixed rate debt. In order to manage the Companys interest rate risk, NRG enters into interest
rate swap agreements. As of June 30, 2010, NRG had interest rate derivative instruments extending
through June 2028, the majority of which had been designated as either cash flow or fair value
hedges.
Volumetric Underlying Derivative Transactions
The following table summarizes the net notional volume buy/(sell) of NRGs open derivative
transactions broken out by commodity, excluding those derivatives that qualified for the NPNS
exception as of June 30, 2010, and December 31, 2009. Option contracts are reflected using delta
volume. Delta volume equals the notional volume of an option adjusted for the probability that the
option will be in-the-money at its expiration date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Volume |
|
|
|
|
June 30, 2010 |
|
December 31, 2009 |
Commodity |
|
Units |
|
(In millions) |
|
Emissions |
|
Short Ton |
|
|
(7 |
) |
|
|
(2 |
) |
Coal |
|
Short Ton |
|
|
42 |
|
|
|
55 |
|
Natural Gas |
|
MMBtu |
|
|
(299 |
) |
|
|
(484 |
) |
Oil |
|
Barrel |
|
|
|
|
|
|
1 |
|
Power |
|
MWh |
|
|
11 |
|
|
|
5 |
|
Capacity |
|
MW/Day |
|
|
(3 |
) |
|
|
(2 |
) |
Interest |
|
Dollars |
|
$ |
3,203 |
|
|
$ |
3,291 |
|
|
Fair Value of Derivative Instruments
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade
basis and does not offset amounts at the counterparty master agreement level. Also, collateral
received or paid on the Companys derivative assets or liabilities are recorded on a separate line
item on the balance sheet. The Company has chosen not to offset positions as permitted in ASC 815.
As of June 30, 2010, the Company recorded $391 million of cash collateral paid and $310 million of
cash collateral received on its balance sheet.
The following table summarizes the fair value within the derivative instrument valuation on
the balance sheet as of June 30, 2010, and December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
Derivative Assets |
|
Derivative Liabilities |
|
|
June 30, |
|
December 31, |
|
June 30, |
|
December 31, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Derivatives Designated as Cash Flow or Fair Value Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts current |
|
$ |
|
|
|
$ |
|
|
|
$ |
48 |
|
|
$ |
2 |
|
Interest rate contracts long-term |
|
|
11 |
|
|
|
8 |
|
|
|
69 |
|
|
|
106 |
|
Commodity contracts current |
|
|
370 |
|
|
|
300 |
|
|
|
8 |
|
|
|
12 |
|
Commodity contracts long-term |
|
|
511 |
|
|
|
508 |
|
|
|
1 |
|
|
|
6 |
|
|
Total Derivatives Designated as Cash Flow or Fair Value Hedges |
|
|
892 |
|
|
|
816 |
|
|
|
126 |
|
|
|
126 |
|
|
Derivatives Not Designated as Cash Flow or Fair Value Hedges: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts current |
|
|
1,430 |
|
|
|
1,336 |
|
|
|
1,428 |
|
|
|
1,459 |
|
Commodity contracts long-term |
|
|
388 |
|
|
|
167 |
|
|
|
363 |
|
|
|
275 |
|
|
Total Derivatives Not Designated as Cash Flow or Fair Value
Hedges |
|
|
1,818 |
|
|
|
1,503 |
|
|
|
1,791 |
|
|
|
1,734 |
|
|
Total Derivatives |
|
$ |
2,710 |
|
|
$ |
2,319 |
|
|
$ |
1,917 |
|
|
$ |
1,860 |
|
|
21
Accumulated Other Comprehensive Income
The following table summarizes the effects of ASC 815 on NRGs Accumulated OCI balance
attributable to cash flow hedge derivatives, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
Six months ended June 30, 2010 |
|
|
Energy |
|
Interest |
|
|
|
|
|
Energy |
|
Interest |
|
|
(In millions) |
|
Commodities |
|
Rate |
|
Total |
|
Commodities |
|
Rate |
|
Total |
|
Beginning Balance |
|
$ |
719 |
|
|
$ |
(56 |
) |
|
$ |
663 |
|
|
$ |
461 |
|
|
$ |
(55 |
) |
|
$ |
406 |
|
Reclassified from Accumulated OCI to income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Due to realization of previously deferred amounts |
|
|
(128 |
) |
|
|
(2 |
) |
|
|
(130 |
) |
|
|
(234 |
) |
|
|
|
|
|
|
(234 |
) |
Mark-to-market of cash flow hedge accounting contracts |
|
|
(16 |
) |
|
|
(8 |
) |
|
|
(24 |
) |
|
|
348 |
|
|
|
(11 |
) |
|
|
337 |
|
|
Accumulated OCI balance at June 30, 2010,
net of $308 tax |
|
$ |
575 |
|
|
$ |
(66 |
) |
|
$ |
509 |
|
|
$ |
575 |
|
|
$ |
(66 |
) |
|
$ |
509 |
|
|
Gains/(losses) expected to be realized from OCI
during the next 12 months, net of $186 tax |
|
$ |
348 |
|
|
$ |
(32 |
) |
|
$ |
316 |
|
|
$ |
348 |
|
|
$ |
(32 |
) |
|
$ |
316 |
|
|
(Losses)/gains recognized in income from the
ineffective portion of cash flow hedges |
|
$ |
(12 |
) |
|
$ |
2 |
|
|
$ |
(10 |
) |
|
$ |
(14 |
) |
|
$ |
2 |
|
|
$ |
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
Six months ended June 30, 2009 |
|
|
Energy |
|
Interest |
|
|
|
|
|
Energy |
|
Interest |
|
|
(In millions) |
|
Commodities |
|
Rate |
|
Total |
|
Commodities |
|
Rate |
|
Total |
|
Beginning Balance |
|
$ |
567 |
|
|
$ |
(79 |
) |
|
$ |
488 |
|
|
$ |
406 |
|
|
$ |
(91 |
) |
|
$ |
315 |
|
Reclassified from Accumulated OCI to income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- Due to realization of previously deferred amounts |
|
|
(76 |
) |
|
|
(1 |
) |
|
|
(77 |
) |
|
|
(188 |
) |
|
|
|
|
|
|
(188 |
) |
- Due to discontinuation of cash flow hedge
accounting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(135 |
) |
|
|
|
|
|
|
(135 |
) |
Mark-to-market of cash flow hedge accounting contracts |
|
|
(46 |
) |
|
|
14 |
|
|
|
(32 |
) |
|
|
362 |
|
|
|
25 |
|
|
|
387 |
|
|
Accumulated OCI balance at June 30, 2009,
net of $233 tax |
|
$ |
445 |
|
|
$ |
(66 |
) |
|
$ |
379 |
|
|
$ |
445 |
|
|
$ |
(66 |
) |
|
$ |
379 |
|
|
(Losses)/gains recognized in income from the
ineffective portion of cash flow hedges |
|
$ |
(3 |
) |
|
$ |
|
|
|
$ |
(3 |
) |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
1 |
|
|
Amounts reclassified from Accumulated OCI into income and amounts recognized in income
from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity
contracts and interest expense for interest rate contracts.
Accounting guidelines require a high degree of correlation between the derivative and the
hedged item throughout the period in order to qualify as a cash flow hedge. As of July 31, 2008,
the Companys regression analysis for natural gas prices to ERCOT power prices, while positively
correlated, did not meet the required threshold for cash flow hedge accounting for calendar years
2012 and 2013. As a result, the Company de-designated its 2012 and 2013 ERCOT cash flow hedges as
of July 31, 2008, and prospectively marked these derivatives to market. On April 1, 2009, the
required correlation threshold for cash flow hedge accounting was achieved for these transactions,
and accordingly, these hedges were re-designated as cash flow hedges.
As discussed in Note 3, Business Acquisitions, to the Companys financial statements in its
Annual Report on Form 10-K for the year ended December 31, 2009, on October 5, 2009, the Company
amended the CSRA with Merrill Lynch. In connection with the CSRA Amendment, NRG net settled
certain in-the-money transactions with Morgan Stanley. As these transactions were net settled,
$245 million in OCI was frozen and is recognized into income as the underlying power from the
baseload plants is generated.
The following table summarizes the amount of gain/(loss) resulting from fair value hedges
reflected in interest income/(expense) for interest rate contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Derivative |
|
$ |
|
|
|
$ |
(7 |
) |
|
$ |
3 |
|
|
$ |
(8 |
) |
Senior Notes (hedged item) |
|
$ |
|
|
|
$ |
7 |
|
|
$ |
(3 |
) |
|
$ |
8 |
|
|
22
Impact of Derivative Instruments on the Statement of Operations
In accordance with ASC 815, unrealized gains and losses associated with changes in the fair
value of derivative instruments not accounted for as cash flow 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 and cost of
operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Unrealized mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized
unrealized gains on settled
positions related to economic
hedges |
|
$ |
(51 |
) |
|
$ |
(18 |
) |
|
$ |
(91 |
) |
|
$ |
(34 |
) |
Reversal of loss positions
acquired as part of the Reliant
Energy acquisition as of May 1,
2009 |
|
|
60 |
|
|
|
210 |
|
|
|
150 |
|
|
|
210 |
|
Reversal of previously recognized
unrealized losses/(gains) on
settled positions related to
trading activity |
|
|
8 |
|
|
|
(35 |
) |
|
|
26 |
|
|
|
(104 |
) |
Net unrealized gains/(losses) on
open positions related to economic
hedges |
|
|
48 |
|
|
|
(40 |
) |
|
|
(70 |
) |
|
|
309 |
|
(Losses)/gains on ineffectiveness
associated with open positions
treated as cash flow hedges |
|
|
(12 |
) |
|
|
(3 |
) |
|
|
(14 |
) |
|
|
1 |
|
Net unrealized gains on open
positions related to trading
activity |
|
|
9 |
|
|
|
1 |
|
|
|
23 |
|
|
|
8 |
|
|
Total unrealized gains |
|
$ |
62 |
|
|
$ |
115 |
|
|
$ |
24 |
|
|
$ |
390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Revenue from operations energy commodities |
|
$ |
(83 |
) |
|
$ |
(210 |
) |
|
$ |
(14 |
) |
|
$ |
117 |
|
Cost of operations |
|
|
145 |
|
|
|
325 |
|
|
|
38 |
|
|
|
273 |
|
|
Total impact to statement of operations |
|
$ |
62 |
|
|
$ |
115 |
|
|
$ |
24 |
|
|
$ |
390 |
|
|
Reliant Energys loss positions were acquired as of May 1, 2009, and valued using forward
prices on that date. The roll-off amounts were offset by realized losses at the settled prices and
are reflected in the cost of operations during the same period.
For the six months ended June 30, 2010, the $70 million loss from economic hedge positions is
the result of a decrease in value of forward purchases and sales of natural gas, electricity and
fuel due to a decrease in forward power and gas prices.
For the six months ended June 30, 2009, the $309 million gain from economic hedge positions
includes $217 million recognized in earnings from previously deferred amounts in Accumulated OCI as
the Company discontinued cash flow hedge accounting for certain 2009 transactions in Texas and New
York due to lower expected generation, and $92 million of increase in value of forward purchases
and sales of electricity and fuel due to a decrease in forward power and gas prices.
Discontinued Normal Purchase and Sale for Coal Purchases Due to lower coal-fired generation
during the first quarter 2009, the Companys coal consumption was lower than forecasted. The
Company net settled some of its coal purchases under NPNS designation and thus was not able to
assert physical delivery under these coal contracts. The forward positions previously treated as
accrual accounting were reclassified into mark-to-market accounting during the first quarter of
2009 and prospectively. The impact of discontinuance of coal NPNS designated transactions resulted
in a derivative loss of $29 million that was reflected in the cost of operations for the six months
ended June 30, 2009.
23
Credit Risk Related Contingent Features
Certain of the Companys hedging agreements contain provisions that require the Company to
post additional collateral if the counterparty determines that there has been deterioration in
credit quality, generally termed adequate assurance under the agreements, or require the Company
to post additional collateral if there was a one notch downgrade in the Companys credit rating.
The collateral required for contracts that have adequate assurance clauses that are in a net
liability position as of June 30, 2010, was $63 million. The collateral required for contracts
with credit rating contingent features that are in a net liability position as of June 30, 2010,
was $11 million. The Company is also a party to certain marginable agreements where NRG has a net
liability position but the counterparty has not called for the collateral due, which is
approximately $15 million as of June 30, 2010.
See Note 5, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding
concentration of credit risk.
Note 8 Long-Term Debt
In March 2010, NRG made a repayment of approximately $229 million to its first lien lenders
under the Term Loan Facility. This payment resulted from the mandatory annual offer of a portion
of NRGs excess cash flow (as defined in the Senior Credit Facility) for the prior year.
Amendment and Extension of Maturity Dates
On June 30, 2010, NRG completed an amendment and extension of the Senior Credit Facility,
resulting in the following:
|
|
|
NRG extended the maturity date for approximately $1.0 billion of its $2.0 billion
outstanding Term Loan Facility to August 31, 2015, with the remaining amount due on the
original maturity date of February 1, 2013. The interest rate for the extended portion
of the facility increased from LIBOR+1.75% to LIBOR+3.25%; |
|
|
|
Borrowing capacity under the Revolving Credit Facility was reduced from $1.0 billion
to $875 million and its maturity was extended to August 31, 2015. The interest rate for
the amended Revolving Credit Facility is LIBOR+3.25%; |
|
|
|
The existing Synthetic Letter of Credit Facility was converted into a term loan-backed
funded letter of credit facility, or Funded Letter of Credit Facility, with the term loan
reflected as a non-current liability and the proceeds of the term loan reflected as
non-current restricted cash on NRGs balance sheet. Of the total $1.3 billion borrowed
under the term loan, $500 million will mature on February 1, 2013 and bear interest at
LIBOR+1.75%, while $800 million will mature August 31, 2015 and bear interest at
LIBOR+3.25%. |
|
|
|
Restricted cash supporting funded letter of credit Pursuant to the letter of credit
reimbursement agreements entered into as of June 30, 2010, or the LC Agreements, and the
Senior Credit Facility, as amended, NRG made capital contributions to NRG LC Facility
Company, or LCFC, a separate, bankruptcy-remote entity that is a wholly-owned subsidiary of
NRG. In addition, pursuant to reimbursement agreements related to the LC Agreements, NRG
or its subsidiaries is liable for certain reimbursement obligations to LCFC. As of June
30, 2010, LCFC has cash invested in short-term certificates of deposit with an aggregate
market value of $1.3 billion. Pursuant to the LC Agreements, which have a maximum
committed amount of $1.3 billion, LCFC is liable on various letters of credit issued by
Deutsche Bank AG, New York Branch and Citibank, N.A. These letters of credit will be used
to support the businesses of NRG and certain of its other subsidiaries and equity
investments. LCFC has secured its reimbursement and other obligations under the LC
Agreements with a pledge of the cash and cash equivalents that it owns. The LC Agreements
require LCFCs assets to be used first and foremost to satisfy claims of creditors of LCFC.
Although the cash and cash equivalents held by LCFC are included in the consolidated
assets of NRG, such cash and cash equivalents are not available to creditors of NRG. |
|
|
|
Expenses of approximately $45 million, including fees to the lenders and other fees,
were deferred and will be expensed in part over the original term of maturity through
2013 and in part over the amended maturity through 2015. |
As of June 30, 2010, NRG had issued $820 million of letters of credit under the Funded Letter
of Credit Facility, leaving $480 million available for future issuances. Under the Revolving
Credit Facility as of June 30, 2010, NRG had issued a letter of credit of $36 million, leaving $839
million available.
24
Dunkirk Power LLC Tax-Exempt Bonds
On February 1, 2010, the Company fixed the rate on the Dunkirk bonds originally issued in
April 2009, at 5.875%. In addition, the $59 million letter of credit issued by NRG in support of
the bonds was cancelled and replaced with an NRG guarantee.
Debt Related to Capital Allocation Program
On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a
cash payment to Credit Suisse, or CS, of $242 million to settle the outstanding principal and
interest, as compared to $249 million that would have been due at maturity in June 2010. As part
of the unwind, CS returned to NRG 6,600,000 shares of NRG common stock borrowed under the Share
Lending Agreement, or SLA, between the parties and released all 12,441,973 shares of NRG common
stock held as collateral for the CSF I Debt. The 6,600,000 shares of NRG common stock were
returned to treasury stock and will no longer be treated as outstanding for corporate law purposes.
The Company has now settled all obligations related to the CSF I and II Debt entered into in 2006,
as amended from time to time, as well as the SLA entered into in February 2009.
Blythe Credit Agreement
On June 24, 2010, NRG Solar Blythe LLC, or Blythe, entered into a credit agreement with a
bank, or the Blythe Credit Agreement, for a $30 million term loan which has an interest rate of
LIBOR plus an applicable margin which escalates 0.25% every three years and ranges from 2.5% at
closing to 3.75% in year fifteen. The term loan matures in June 2028, amortizes based upon a
predetermined schedule, and is secured by all of the assets of Blythe. The bank has also issued
two letters of credit on behalf of Blythe totaling approximately $6.4 million. Blythe pays an
availability fee of 100% of the applicable margin on these issued letters of credit.
Also related to the Blythe Credit Agreement, on June 25, 2010, Blythe entered into a fixed for
floating interest rate swap for 75% of the outstanding term loan amount, intended to hedge the
risks associated with floating interest rates. Blythe will pay its counterparty the equivalent of
a 3.563% fixed interest payment on a predetermined notional value, and Blythe will receive
quarterly the equivalent of a floating interest payment based on a three month LIBOR calculated on
the same notional value. All interest rate swap payments by Blythe and its counterparty are made
quarterly and the LIBOR is determined in advance of each interest period. The notional amount of
the swap, which matures on June 25, 2028, is $22 million and amortizes in proportion to the loan.
South Trent Financing Agreement
On June 14, 2010 NRG completed the acquisition of the South Trent, as discussed in Note 4,
Business Acquisitions and Dispositions. As part of the purchase price consideration, South Trent
entered into the Amended and Restated Financing Agreement, or Financing Agreement, with a group of
lenders, which matures on June 14, 2020. The Financing Agreement includes a $79 million term loan,
as well as a $10 million letter of credit facility in support of the PPA, for which the full amount
had been issued as of June 30, 2010. The Financing Agreement also provides for up to $8 million in
additional letter of credit facilities, none of which are utilized as of June 30, 2010. The term
loan accrues interest at LIBOR plus a margin based upon a grid, which is initially 2.50% and
increases every two years by 12.5 basis points. The term loan amortizes quarterly based upon a
predetermined schedule with the unamortized portion due at maturity.
Under the terms of the Financing Agreement, South Trent was required to enter into interest
rate protection agreements that would fix the interest rate for a minimum of 75% of the outstanding
principal amount. Accordingly, on June 14, 2010, South Trent entered into five interest rate
swaps, intended to hedge the risks associated with floating interest rates. For each of the
interest rate swaps, South Trent will pay its counterparty the equivalent of a 3.265% fixed
interest payment on a predetermined notional value, and South Trent will receive the quarterly
equivalent of a floating interest payment based on a three month LIBOR calculated on the same
notional value. All interest rate swap payments by South Trent and its counterparties are made
quarterly and the LIBOR is determined in advance of each interest period. The total notional
amount of these swaps, which mature on June 14, 2020, is $59 million. The swaps amortize in
proportion to the loan.
South Trent also entered into a series of forward-starting interest rate swaps that will
become effective June 14, 2020, and are effective for eight years. The swaps are intended to hedge
the risks associated with floating interest rates. For each of the interest rate swaps, South
Trent will pay its counterparty the equivalent of a 4.95% fixed interest payment on a predetermined
notional value, and receive the quarterly equivalent of a floating interest payment based on a
three month LIBOR calculated on the same notional value. All interest rate swap payments by South
Trent and its counterparties will be made quarterly and the LIBOR is determined in advance of each
interest period. The total notional amount of these swaps, which will mature on June 14, 2028, is
$21 million.
25
NRG Thermal Financing
On June 22, 2010 NRG Thermals largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG
Thermal Minneapolis, issued $100 million of 5.95% Series C notes due June 23, 2025, or the Series C
Notes. The Series C Notes are secured by substantially all of the assets of NRG Energy Center
Minneapolis. NRG Thermal has guaranteed the indebtedness and its guarantee is secured by a pledge
of the equity interest in all of NRG Thermals subsidiaries. At the same time, NRG Thermal amended
agreements for its other outstanding notes to conform to the covenants of the Series C Notes. The
proceeds of the loan were used to finance the acquisition of Northwind Phoenix, as discussed in
Note 4, Business Acquisitions and Dispositions.
GenConn Energy LLC related financings
NRG Connecticut Peaking Development LLC made funding requests under the equity bridge loan, or
EBL, during the quarter. The EBL is backed by a letter of credit issued by NRG under its Funded
Letter of Credit Facility equal to 104% of the amount outstanding. The proceeds of the EBL
received through June 30, 2010, were $115 million and the remaining amounts will be drawn as
necessary to fund interest on the EBL as the maximum amount permitted to be drawn for project costs
for both projects has been met. Of the $115 million, $55 million was drawn to fund Devon project
costs and will become due and payable upon the commercial operation
date, or COD, of the Devon project, which is expected to occur in
the third quarter of 2010.
Borrowings of an equity method investment In April 2009, GenConn secured financing for 50%
of the Devon and Middletown project construction costs through a seven-year term loan facility, and
also entered into a five-year revolving working capital loan and letter of credit facility, which
collectively with the term loan is referred to as the GenConn Facility. The aggregate credit
amount secured under the GenConn Facility, which is non-recourse to NRG, is $291 million, including
$48 million for the revolving facility. In August 2009, GenConn began to draw under the GenConn
Facility to cover costs related to the Devon project, and in June 2010 GenConn began to draw for
the Middletown project. As of June 30, 2010, $109 million had been drawn.
NINA Financing
On May 28, 2010, NINA borrowed $3 million under the TANE Facility. On June 1, 2010, NINA
repaid $20 million outstanding under its revolving credit facility, and the facility was
terminated.
26
Note 9 Changes in Capital Structure
The following table reflects the changes in NRGs common stock issued and outstanding during
the six months ended June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized |
|
Issued |
|
Treasury |
|
Outstanding |
|
Balance as of December 31, 2009
|
|
|
500,000,000 |
|
|
|
295,861,759 |
|
|
|
(41,866,451 |
) |
|
|
253,995,308 |
|
Shares issued under LTIP
|
|
|
|
|
|
|
179,259 |
|
|
|
|
|
|
|
179,259 |
|
Shares issued under NRG Employee
Stock Purchase Plan, or ESPP
|
|
|
|
|
|
|
|
|
|
|
54,845 |
|
|
|
54,845 |
|
Capital Allocation Plan
|
|
|
|
|
|
|
|
|
|
|
(2,214,000 |
) |
|
|
(2,214,000 |
) |
Shares returned by affiliates of CS
|
|
|
|
|
|
|
|
|
|
|
(6,600,000 |
) |
|
|
(6,600,000 |
) |
4% Preferred Stock conversion
|
|
|
|
|
|
|
7,701,450 |
|
|
|
|
|
|
|
7,701,450 |
|
|
Balance as of June 30, 2010
|
|
|
500,000,000 |
|
|
|
303,742,468 |
|
|
|
(50,625,606 |
) |
|
|
253,116,862 |
|
|
Employee Stock Purchase Plan
As of June 30, 2010, there were 363,623 shares of treasury stock reserved for issuance under
the ESPP. In July 2010, 66,145 shares of common stock were issued to employee accounts from
treasury stock.
2010 Capital Allocation Plan
As part of the Companys 2010 Capital Allocation Plan, the Company repurchased $50 million of
NRGs common stock during the quarter ended June 30, 2010. NRG intends to complete the remainder
of its $180 million of share repurchases by the end of 2010, subject to market prices, financial
restrictions under the Companys debt facilities and as permitted by securities laws.
Share Lending Agreements
As part of the CSF I Debt unwind on March 3, 2010, CS returned to NRG 6,600,000 shares of NRG
common stock borrowed under the SLA between the parties. The 6,600,000 shares of NRG common stock
were returned to treasury stock and will no longer be treated as outstanding for corporate law
purposes. See Note 8, Long-Term Debt, to this Form 10-Q for more information.
4% Preferred Stock
As of January 21, 2010, the Company completed the redemption of all remaining outstanding
shares of 4% Preferred Stock, with holders converting 154,029 Preferred Stock shares into 7,701,450
shares of common stock and the Company redeeming 28 Preferred Stock shares for $28 thousand in
cash.
27
Note 10 Equity Compensation
Non-Qualified Stock Options, or NQSOs
The following table summarizes the Companys NQSO activity as of June 30, 2010, and changes
during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Aggregate Intrinsic |
|
|
|
|
|
|
Average |
|
Value |
|
|
Shares |
|
Exercise Price |
|
(In millions) |
|
Outstanding as of December 31, 2009 |
|
|
4,793,585 |
|
|
$ |
25.07 |
|
|
|
|
|
Granted |
|
|
754,200 |
|
|
|
23.79 |
|
|
|
|
|
Exercised |
|
|
(111,331 |
) |
|
|
22.12 |
|
|
|
|
|
Forfeited |
|
|
(331,669 |
) |
|
|
30.16 |
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2010 |
|
|
5,104,785 |
|
|
|
24.61 |
|
|
$ |
10 |
|
Exercisable at June 30, 2010 |
|
|
3,288,301 |
|
|
$ |
23.65 |
|
|
$ |
10 |
|
|
The weighted average grant date fair value of NQSOs granted for the six months ended June 30,
2010, was $10.67.
Restricted Stock Units, or RSUs
The following table summarizes the Companys non-vested RSU awards as of June 30, 2010, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant-Date |
|
|
Units |
|
Fair Value Per Unit |
|
Non-vested as of December 31, 2009 |
|
|
1,614,769 |
|
|
$ |
30.78 |
|
Granted |
|
|
352,600 |
|
|
|
23.66 |
|
Vested |
|
|
(68,240 |
) |
|
|
28.56 |
|
Forfeited |
|
|
(109,180 |
) |
|
|
30.12 |
|
|
Non-vested as of June 30, 2010 |
|
|
1,789,949 |
|
|
$ |
29.50 |
|
|
Performance Units, or PUs
The following table summarizes the Companys non-vested PU awards as of June 30, 2010, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant- Date |
|
|
Units |
|
Fair Value Per Unit |
|
Non-vested as of December 31, 2009 |
|
|
617,300 |
|
|
$ |
24.27 |
|
Granted |
|
|
348,500 |
|
|
|
23.81 |
|
Forfeited |
|
|
(194,400 |
) |
|
|
22.73 |
|
|
Non-vested as of June 30, 2010 |
|
|
771,400 |
|
|
$ |
24.45 |
|
|
In the six months ended June 30, 2010, there were no performance unit payouts in accordance
with the terms of the performance units.
Deferral Stock Units, or DSUs
The following table summarizes the Companys outstanding DSU awards as of June 30, 2010, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant- Date |
|
|
Units |
|
Fair Value Per Unit |
|
Outstanding as of December 31, 2009 |
|
|
304,049 |
|
|
$ |
19.34 |
|
Granted |
|
|
59,067 |
|
|
|
22.18 |
|
Conversions |
|
|
(28,395 |
) |
|
|
21.77 |
|
|
Outstanding as of June 30, 2010 |
|
|
334,721 |
|
|
$ |
19.63 |
|
|
28
Note 11 Earnings Per Share
Basic earnings per share attributable to NRG common stockholders is computed by dividing net
income attributable to NRG Energy Inc. 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 attributable to NRG common stockholders 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.
On March 3, 2010, as part of the CSF I Debt unwind, CS returned 6,600,000 shares of NRG common
stock borrowed under the SLA between the parties. These shares had not been treated as outstanding
for earnings per share purposes because CS was required to return all borrowed shares (or identical
shares) upon termination of the SLA. See Note 8, Long-Term Debt, to this Form 10-Q, for more
information on the SLA.
The reconciliation of basic earnings per common share to diluted earnings per share
attributable to NRG is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
Six months ended |
|
|
June 30, |
|
June 30, |
(In millions, except per share data) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Basic earnings per share attributable to NRG common
stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc. |
|
$ |
211 |
|
|
$ |
433 |
|
|
$ |
269 |
|
|
$ |
631 |
|
Preferred stock dividends |
|
|
(3 |
) |
|
|
(7 |
) |
|
|
(5 |
) |
|
|
(21 |
) |
|
Net income attributable to NRG Energy, Inc. available
to common stockholders |
|
$ |
208 |
|
|
$ |
426 |
|
|
$ |
264 |
|
|
$ |
610 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
255 |
|
|
|
253 |
|
|
|
254 |
|
|
|
245 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc. |
|
$ |
0.82 |
|
|
$ |
1.68 |
|
|
$ |
1.04 |
|
|
$ |
2.49 |
|
|
Diluted earnings per share attributable to NRG common
stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders |
|
$ |
208 |
|
|
$ |
426 |
|
|
$ |
264 |
|
|
$ |
610 |
|
Add preferred stock dividends for dilutive preferred stock |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
14 |
|
|
Net income attributable to NRG Energy, Inc. available
to common stockholders |
|
$ |
208 |
|
|
$ |
430 |
|
|
$ |
264 |
|
|
$ |
624 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
255 |
|
|
|
253 |
|
|
|
254 |
|
|
|
245 |
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method) |
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
Incremental shares attributable to assumed conversion
features of outstanding preferred stock (if-converted
method) |
|
|
|
|
|
|
21 |
|
|
|
1 |
|
|
|
29 |
|
|
Total dilutive shares |
|
|
256 |
|
|
|
275 |
|
|
|
256 |
|
|
|
275 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc. |
|
$ |
0.81 |
|
|
$ |
1.56 |
|
|
$ |
1.03 |
|
|
$ |
2.27 |
|
|
The following table summarizes NRGs outstanding equity instruments that were anti-dilutive
and not included in the computation of the Companys diluted earnings per share for the three and
six months ended June 30:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions of shares) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Equity compensation NQSOs and PUs |
|
|
6 |
|
|
|
5 |
|
|
|
6 |
|
|
|
5 |
|
Embedded derivative of 3.625% redeemable perpetual preferred stock |
|
|
16 |
|
|
|
16 |
|
|
|
16 |
|
|
|
16 |
|
Embedded derivative of CSF II Debt |
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
8 |
|
|
Total |
|
|
22 |
|
|
|
29 |
|
|
|
22 |
|
|
|
29 |
|
|
29
Note 12 Segment Reporting
NRGs segment structure has changed to reflect the Companys acquisition of Reliant Energy
along with the previously reported 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
Three months ended |
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010 |
|
Energy |
|
Texas(a) |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
1,282 |
|
|
$ |
692 |
|
|
$ |
205 |
|
|
$ |
152 |
|
|
$ |
32 |
|
|
$ |
30 |
|
|
$ |
27 |
|
|
$ |
(4 |
) |
|
$ |
(283 |
) |
|
$ |
2,133 |
|
Depreciation and
amortization |
|
|
29 |
|
|
|
124 |
|
|
|
31 |
|
|
|
16 |
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
208 |
|
Equity in earnings of
unconsolidated
affiliates |
|
|
|
|
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
1 |
|
|
|
11 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
11 |
|
Income/(loss) before
income taxes |
|
|
277 |
|
|
|
157 |
|
|
|
(2 |
) |
|
|
4 |
|
|
|
8 |
|
|
|
31 |
|
|
|
(2 |
) |
|
|
(147 |
) |
|
|
1 |
|
|
|
327 |
|
Net income/(loss) |
|
|
277 |
|
|
|
157 |
|
|
|
(2 |
) |
|
|
4 |
|
|
|
8 |
|
|
|
21 |
|
|
|
(2 |
) |
|
|
(254 |
) |
|
|
1 |
|
|
|
210 |
|
Net loss attributable
to non-controlling
interest |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net income/(loss)
attributable to NRG
Energy, Inc. |
|
$ |
277 |
|
|
$ |
158 |
|
|
$ |
(2 |
) |
|
$ |
4 |
|
|
$ |
8 |
|
|
$ |
21 |
|
|
$ |
(2 |
) |
|
$ |
(254 |
) |
|
$ |
1 |
|
|
$ |
211 |
|
|
Total assets |
|
$ |
1,930 |
|
|
$ |
13,363 |
|
|
$ |
1,843 |
|
|
$ |
884 |
|
|
$ |
372 |
|
|
$ |
672 |
|
|
$ |
328 |
|
|
$ |
27,303 |
|
|
$ |
(21,592 |
) |
|
$ |
25,103 |
|
|
|
|
|
(a) |
|
Includes inter-segment sales of $281 million to Reliant Energy. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
Three months ended |
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
Energy(a) |
|
Texas(b) |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
1,175 |
|
|
$ |
619 |
|
|
$ |
237 |
|
|
$ |
139 |
|
|
$ |
42 |
|
|
$ |
34 |
|
|
$ |
28 |
|
|
$ |
32 |
|
|
$ |
(69 |
) |
|
$ |
2,237 |
|
Depreciation and
amortization |
|
|
43 |
|
|
|
117 |
|
|
|
30 |
|
|
|
17 |
|
|
|
2 |
|
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
213 |
|
Equity in
earnings/(loss) of
unconsolidated
affiliates |
|
|
|
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5 |
|
Income/(loss) from
continuing operations
before income taxes |
|
|
414 |
|
|
|
107 |
|
|
|
42 |
|
|
|
(9 |
) |
|
|
19 |
|
|
|
128 |
|
|
|
|
|
|
|
(119 |
) |
|
|
|
|
|
|
582 |
|
Net income/(loss) |
|
|
233 |
|
|
|
98 |
|
|
|
42 |
|
|
|
(9 |
) |
|
|
19 |
|
|
|
125 |
|
|
|
|
|
|
|
(76 |
) |
|
|
|
|
|
|
432 |
|
Net loss attributable
to non-controlling
interest |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net income/(loss)
attributable to NRG
Energy, Inc. |
|
$ |
233 |
|
|
$ |
99 |
|
|
$ |
42 |
|
|
$ |
(9 |
) |
|
$ |
19 |
|
|
$ |
125 |
|
|
$ |
|
|
|
$ |
(76 |
) |
|
$ |
|
|
|
$ |
433 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Includes inter-segment sales of $69 million to Reliant Energy. |
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
Six months ended |
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2010 |
|
Energy |
|
Texas(a) |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
2,458 |
|
|
$ |
1,562 |
|
|
$ |
484 |
|
|
$ |
295 |
|
|
$ |
67 |
|
|
$ |
65 |
|
|
$ |
63 |
|
|
$ |
(2 |
) |
|
$ |
(644 |
) |
|
$ |
4,348 |
|
Depreciation and
amortization |
|
|
59 |
|
|
|
241 |
|
|
|
63 |
|
|
|
32 |
|
|
|
6 |
|
|
|
|
|
|
|
5 |
|
|
|
4 |
|
|
|
|
|
|
|
410 |
|
Equity in earnings of
unconsolidated
affiliates |
|
|
|
|
|
|
11 |
|
|
|
(1 |
) |
|
|
|
|
|
|
1 |
|
|
|
15 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
25 |
|
Income/(loss) from
continuing operations
before income taxes |
|
|
89 |
|
|
|
532 |
|
|
|
50 |
|
|
|
|
|
|
|
14 |
|
|
|
41 |
|
|
|
2 |
|
|
|
(279 |
) |
|
|
1 |
|
|
|
450 |
|
Net income/(loss) |
|
|
89 |
|
|
|
532 |
|
|
|
50 |
|
|
|
|
|
|
|
14 |
|
|
|
29 |
|
|
|
2 |
|
|
|
(449 |
) |
|
|
1 |
|
|
|
268 |
|
Net loss attributable
to non-controlling
interest |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net income/(loss)
attributable to NRG
Energy, Inc. |
|
$ |
89 |
|
|
$ |
533 |
|
|
$ |
50 |
|
|
$ |
|
|
|
$ |
14 |
|
|
$ |
29 |
|
|
$ |
2 |
|
|
$ |
(449 |
) |
|
$ |
1 |
|
|
$ |
269 |
|
|
|
|
|
(a) |
|
Includes inter-segment sales of $642 million to Reliant Energy. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In millions) |
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
Six months ended |
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
Energy(a) |
|
Texas(b) |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
1,175 |
|
|
$ |
1,544 |
|
|
$ |
701 |
|
|
$ |
301 |
|
|
$ |
70 |
|
|
$ |
68 |
|
|
$ |
70 |
|
|
$ |
36 |
|
|
$ |
(70 |
) |
|
$ |
3,895 |
|
Depreciation and
amortization |
|
|
43 |
|
|
|
234 |
|
|
|
59 |
|
|
|
34 |
|
|
|
4 |
|
|
|
|
|
|
|
5 |
|
|
|
3 |
|
|
|
|
|
|
|
382 |
|
Equity in
earnings/(losses) of
unconsolidated
affiliates |
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Income/(loss) from
continuing operations
before income taxes |
|
|
414 |
|
|
|
485 |
|
|
|
253 |
|
|
|
(8 |
) |
|
|
16 |
|
|
|
142 |
|
|
|
4 |
|
|
|
(228 |
) |
|
|
|
|
|
|
1,078 |
|
Net income/(loss) |
|
|
233 |
|
|
|
315 |
|
|
|
253 |
|
|
|
(8 |
) |
|
|
16 |
|
|
|
137 |
|
|
|
4 |
|
|
|
(320 |
) |
|
|
|
|
|
|
630 |
|
Net loss attributable
to non-controlling
interest |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net income/(loss)
attributable to NRG
Energy, Inc. |
|
$ |
233 |
|
|
$ |
316 |
|
|
$ |
253 |
|
|
$ |
(8 |
) |
|
$ |
16 |
|
|
$ |
137 |
|
|
$ |
4 |
|
|
$ |
(320 |
) |
|
$ |
|
|
|
$ |
631 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Includes inter-segment sales of $69 million to Reliant Energy. |
31
Note 13 Income Taxes
Effective Tax Rate
The Companys Income tax provision consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Income tax expense |
|
$ |
117 |
|
|
$ |
150 |
|
|
$ |
182 |
|
|
$ |
448 |
|
Effective tax rate |
|
|
35.8 |
% |
|
|
25.8 |
% |
|
|
40.4 |
% |
|
|
41.5 |
% |
|
For the three months ended June 30, 2010, NRGs overall effective tax rate was different than
the statutory rate of 35% primarily due to state and local income taxes as well as recording
federal and state tax expense and interest for unrecognized tax benefits. For the three months
ended June 30, 2009, NRGs effective tax rate was different than the statutory rate of 35%
primarily due to a net state and local income tax benefit as a result of the Reliant Energy
acquisition, and the sale of the MIBRAG facility.
For the six months ended June 30, 2010, NRGs overall effective tax rate was different than
the statutory rate of 35% primarily due to state and local income taxes as well as recording
federal and state tax expense and interest for unrecognized tax benefits. For the six months ended
June 30, 2009, NRGs overall effective tax rate was different than the statutory rate of 35%
primarily due to an increase in valuation allowance as a result of capital losses generated in the
six month period for which there were no projected capital gains or available tax planning
strategies. Furthermore, the effective tax rate was decreased by the sale of the MIBRAG facility
as well as a net state and local income tax benefit as a result of the Reliant Energy acquisition.
Unrecognized tax benefits
As of June 30, 2010, NRG has recorded a $512 million non-current tax liability for
unrecognized tax benefits, primarily resulting from taxable earnings for the period for which there
are no net operating losses available to offset for financial statement purposes. NRG has accrued
interest related to these unrecognized tax benefits of approximately $17 million for the six months
ended June 30, 2010, and has accrued approximately $34 million since adoption. The Company
recognizes interest and penalties related to unrecognized tax benefits in income tax expense.
The Company continues to be under examination by the Internal Revenue Service for the years
2004 through 2006, as well as various state jurisdictions for multiple years.
Tax Receivable and Payable
As of June 30, 2010, NRG recorded a current tax payable of approximately $22 million that
represents a tax liability due for domestic state taxes of approximately $14 million, as well as
foreign taxes payable of approximately $8 million. In addition, as of June 30, 2010, NRG had a
domestic tax receivable of $77 million for property tax refunds primarily due to the New York State
Empire Zone program.
32
Note 14 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 employees. The total amount of employer contributions paid
for the six months ended June 30, 2010, was $11 million. NRG expects to make approximately $7
million in further contributions for the remainder of 2010.
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 June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Service cost benefits earned |
|
$ |
4 |
|
|
$ |
3 |
|
|
$ |
7 |
|
|
$ |
7 |
|
Interest cost on benefit obligation |
|
|
5 |
|
|
|
5 |
|
|
|
10 |
|
|
|
10 |
|
Prior service cost |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
Expected return on plan assets |
|
|
(6 |
) |
|
|
(4 |
) |
|
|
(10 |
) |
|
|
(8 |
) |
|
Net periodic benefit cost |
|
$ |
3 |
|
|
$ |
5 |
|
|
$ |
7 |
|
|
$ |
10 |
|
|
The net periodic cost related to all of the Companys other postretirement benefits plans
includes the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits Plans |
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Service cost benefits earned |
|
$ |
|
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
2 |
|
Interest cost on benefit obligation |
|
|
2 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
Net periodic benefit cost |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
4 |
|
|
$ |
5 |
|
|
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 six months ended June 30, 2010 was $1 million.
The Company recognized net periodic costs related to its 44% interest in STP defined benefits
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
Net periodic
benefit costs |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
4 |
|
|
$ |
5 |
|
|
33
Note 15 Commitments and Contingencies
First and Second Lien Structure
NRG has granted first and second liens to certain counterparties on substantially all of the
Companys assets 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. The Companys lien counterparties
may have a claim on NRGs assets to the extent market prices exceed the hedged price. As of June
30, 2010, all hedges under the first and second liens were in-the-money on a counterparty aggregate
basis.
Nuclear Innovation North America, LLC
CPS Settlement On March 1, 2010, an agreement was reached with CPS for NINA to acquire a
controlling interest in the STP Units 3 and 4 Project through a settlement of litigation between
the parties. As part of the agreement, NINA increased its ownership in the STP Units 3 and 4
Project from 50% to 92.375% and assumed full management control of the project. NRG also will pay
$80 million to CPS, subject to the United States Department of Energys, or U.S. DOE, approval of a
fully executed term sheet for a conditional U.S. DOE loan guarantee. The first $40 million would
be promptly paid after acceptance of the guarantee with the remaining $40 million paid six months
later. NRG also agreed to donate an additional $10 million, unconditionally, over four years in
annual payments of $2.5 million to the Residential Energy Assistance Partnership, or REAP, in San
Antonio. The first $2.5 million payment to REAP was made on March 17, 2010. In connection with
the agreement, the Company capitalized $90 million to construction in progress within property,
plant and equipment, and as of June 30, 2010, $87.5 million in liabilities remains on the condensed
consolidated balance sheet for the obligations to CPS and REAP. As part of the agreement with CPS,
all litigation was dismissed with prejudice.
NINA Investment and Option Agreement On May 10, 2010, NINA and Tokyo Electric Power Company
of Japan, or TEPCO, signed an Investment and Option Agreement whereby TEPCO agreed to acquire up to
a 20% interest in NINA Investments Holdings LLC, or Holdings, a wholly-owned subsidiary of NINA,
which indirectly holds NINAs ownership interest in the STP Units 3 and 4 Project. TEPCO will
initially invest $155 million for a 10% share of Holdings, which includes a $30 million option
premium payment to Holdings. This option, which expires approximately one year from the date of
signing the Investment and Option Agreement, will enable TEPCO to buy an additional 10% of Holdings
for another payment of $125 million. Pursuant to the terms of the Agreement, the closing is
contingent upon NINAs acceptance of a U.S. DOE loan guarantee commitment. Upon its initial
investment, TEPCO will hold a 9.238% interest in the STP Units 3 and 4 Project, diluting NINAs
investment to 83.137% (75.11% for NRG). If TEPCO exercises its option to increase its ownership of
Holdings another 10%, it will own 18.475% of the STP Units 3 and 4 Project, diluting NINAs
investment to 73.90% (66.8% for NRG).
U.S. DOE Loan Guarantee In early 2010, NRG announced that if the STP Units 3 and 4 Project
did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the intention of the
Company both to reduce substantially its commitment to fund on-going project expenditures as well
as to reduce development spending on the project overall while the outcome of the loan guarantee
was uncertain. At the end of the second quarter, with the outcome of the loan guarantee uncertain,
NRG began to curtail substantially its funding of on-going development expenses, immediately
reducing its spend by approximately 70%. Working with NRGs partner (which agreed to step-up its
commitment) and with other counterparties involved in the project, NRG also reduced the current
spend rate on project development but did so in a manner which allowed the project to stay on its
current schedule. NRG presently is in discussions with its partner and counterparties about a
second phase of spending reductions. Should NRG and its partners withdraw support from the project this may result in a reassessment of the probability of success
of the project and an impairment of the value of the capitalized assets for STP Units 3 and 4. An
impairment to NRG would result in a permanent write-down of $498 million of
construction-in-progress capitalized through June 30, 2010, plus any amounts capitalized through
the impairment date. The likelihood of NINA receiving a loan guarantee is largely dependent upon
additional appropriations for nuclear development by Congress or other means of properly securing
the necessary funding for additional nuclear loan guarantee volume. On July 1, 2010, the U.S.
House of Representatives passed an Emergency Supplemental Appropriations bill for fiscal year 2010,
which included an additional $9 billion in loan guarantee authority for nuclear power facilities.
The $9 billion in nuclear loan guarantee volume accelerates into 2010 a portion of the $36 billion
in additional loan guarantee authority requested by the Obama administration for fiscal year 2011.
The legislation passed by the House of Representatives, however, was rejected by the U.S. Senate.
If Congress fails to agree on the necessary appropriation this session, the required funding will
be subject to the normal fiscal year 2011 budget appropriation process, which as currently
contemplated, would provide enough appropriations for the benefit of a loan guarantee to the STP
Units 3 and 4 Project.
34
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. NRG records reserves for estimated losses from contingencies when information
available indicates that a loss is probable and the amount of the loss, or range of loss, can be
reasonably estimated. In addition legal costs are expensed as incurred. Management has assessed
each of the following matters based on current information and made a judgment concerning its
potential outcome, considering the nature of the claim, the amount and nature of damages sought,
and the probability of success. Unless specified below, the Company is unable to predict the
outcome of these legal proceedings or reasonably estimate the scope or amount of any associated
costs and potential liabilities. As additional information becomes available, management adjusts
its assessment and estimates of such contingencies accordingly. Because litigation is subject to
inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate
resolution of the Companys liabilities and contingencies could be at amounts that are different
from its currently recorded reserves and that such difference could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other
litigation or legal proceedings arising in the ordinary course of business. In managements
opinion, the disposition of these ordinary course matters will not materially adversely affect
NRGs consolidated financial position, results of operations, or cash flows.
California Department of Water Resources
This matter concerns, among other contracts and other defendants, the California Department of
Water Resources, or CDWR and its wholesale power contract with subsidiaries of WCP (Generation)
Holdings, Inc., or WCP. The case originated with a February 2002 complaint filed by the State of
California alleging that many parties, including WCP subsidiaries, overcharged the State of
California. For WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002.
The complaint demanded that the Federal Energy Regulatory Commission, or FERC abrogate the CDWR
contract and sought refunds associated with revenues collected under the contract. In 2003, the
FERC rejected this complaint, denied rehearing, and the case was appealed to the U.S. Court of
Appeals for the Ninth Circuit where oral argument was held on December 8, 2004. On December 19,
2006, the Ninth Circuit decided that in the FERCs review of the contracts at issue, the FERC could
not rely on the Mobile-Sierra standard presumption of just and reasonable rates, where such
contracts were not reviewed by the FERC with full knowledge of the then existing market conditions.
WCP and others sought review by the U.S. Supreme Court. WCPs appeal was not selected, but
instead held by the Supreme Court. In the appeal that was selected by the Supreme Court, on June
26, 2008 the Supreme Court ruled: (i) that the Mobile-Sierra public interest standard of review
applied to contracts made under a sellers market-based rate authority; (ii) that the public
interest bar required to set aside a contract remains a very high one to overcome; and (iii) that
the Mobile-Sierra presumption of contract reasonableness applies when a contract is formed during a
period of market dysfunction unless (a) such market conditions were caused by the illegal actions
of one of the parties or (b) the contract negotiations were tainted by fraud or duress. In this
related case, the U.S. Supreme Court affirmed the Ninth Circuits decision agreeing that the case
should be remanded to the FERC to clarify the FERCs 2003 reasoning regarding its rejection of the
original complaint relating to the financial burdens under the contracts at issue and to alleged
market manipulation at the time these contracts were formed. As a result, the U.S. Supreme Court
then reversed and remanded the WCP CDWR case to the Ninth Circuit for treatment consistent with its
June 26, 2008 decision in the related case. On October 20, 2008, the Ninth Circuit asked the
parties in the remanded CDWR case, including WCP and the FERC, whether that Court should answer a
question the U.S. Supreme Court did not address in its June 26, 2008 decision; whether the
Mobile-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 that case. Without answering that
reserved question, on December 4, 2008, the Ninth Circuit vacated its prior opinion and remanded
the WCP CDWR case back to the FERC for proceedings consistent with the U.S. Supreme Courts June
26, 2008 decision. On December 15, 2008, WCP and the other seller-defendants filed with the FERC a
Motion for Order Governing Proceedings on Remand. On January 14, 2009, the Public Utilities
Commission of the State of California filed an Answer and Cross Motion for an Order Governing
Procedures on Remand and on January 28, 2009, WCP and the other seller-defendants filed their
reply.
At this time, while NRG cannot predict with certainty whether WCP will be required to make
refunds for rates collected under the CDWR contract or estimate the range of any such possible
refunds, a reconsideration of the CDWR contract by the FERC with a resulting order mandating
significant refunds could have a material adverse impact on NRGs financial position, statement of
operations, and statement of cash flows. As part of the 2006 acquisition of Dynegys 50% ownership
interest in WCP, WCP and NRG assumed responsibility for any risk of loss arising from this case,
unless any such loss was deemed to have resulted from certain acts of gross negligence or willful
misconduct on the part of Dynegy, in which case any such loss would be shared equally between WCP
and Dynegy.
35
On January 14, 2010, the U.S. Supreme Court issued its decision in an unrelated proceeding
involving the Mobile-Sierra doctrine that will affect the standard of review applied to the CDWR
contract on remand before the FERC. In NRG Power Marketing v. Maine Public Utilities Commission,
the Supreme Court held that the Mobile-Sierra presumption regarding the reasonableness of contract
rates does not depend on the identity of the complainant who seeks a FERC investigation/refund.
Louisiana Generating, LLC
On February 11, 2009, the U.S. Department of Justice, or U.S. DOJ, acting at the request of
the U.S. Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana
Generating, LLC, or LaGen, in federal district court in the Middle District of Louisiana alleging
violations of the Clean Air Act, or CAA, at the Big Cajun II power plant. This is the same matter
for which Notices of Violation, or NOVs, were issued to LaGen on February 15, 2005, and on December
8, 2006. Specifically, it is alleged that in the late 1990s, several years prior to NRGs
acquisition of the Big Cajun II power plant from the Cajun Electric bankruptcy and several years
prior to the NRG bankruptcy, modifications were made to Big Cajun II Units 1 and 2 by the prior
owners without appropriate or adequate permits and without installing and employing the best
available control technology, or BACT, to control emissions of nitrogen oxides and/or sulfur
dioxides. The relief sought in the complaint includes a request for an injunction to: (i) preclude
the operation of Units 1 and 2 except in accordance with the CAA; (ii) order the installation of
BACT on Units 1 and 2 for each pollutant subject to regulation under the CAA; (iii) obtain all
necessary permits for Units 1 and 2; (iv) order the surrender of emission allowances or credits;
(v) conduct audits to determine if any additional modifications have been made which would require
compliance with the CAAs Prevention of Significant Deterioration program; (vi) award to the
Department of Justice its costs in prosecuting this litigation; and (vii) assess civil penalties of
up to $27,500 per day for each CAA violation found to have occurred between January 31, 1997, and
March 15, 2004, up to $32,500 for each CAA violation found to have occurred between March 15, 2004,
and January 12, 2009, and up to $37,500 for each CAA violation found to have occurred after January
12, 2009.
On April 27, 2009, LaGen made several filings. It filed an objection in the Cajun Electric
Cooperative Power, Inc.s bankruptcy proceeding in the U.S. Bankruptcy Court for the Middle
District of Louisiana to seek to prevent the bankruptcy from closing. It also filed a complaint in
the same bankruptcy proceeding in the same court seeking a judgment that: (i) it did not assume
liability from Cajun Electric for any claims or other liabilities under environmental laws with
respect to Big Cajun II that arose, or are based on activities that were undertaken, prior to the
closing date of the acquisition; (ii) it is not otherwise the successor to Cajun Electric; and
(iii) Cajun Electric and/or the Bankruptcy Trustee are exclusively liable for the violations
alleged in the February 11, 2009, lawsuit to the extent that such claims are determined to have
merit. On April 15, 2010, the bankruptcy court signed an order granting LaGens stipulation of
voluntary dismissal without prejudice of its adversary bankruptcy action.
On June 8, 2009, the parties filed a joint status report in the U.S. DOJ lawsuit setting forth
their views of the case and proposing a trial schedule. On June 18, 2009, LaGen filed a motion to
bifurcate the U.S. DOJ lawsuit into separate liability and remedy phases, and on June 30, 2009, the
U.S. DOJ filed its opposition. On April 28, 2010, the district court entered a Joint Case
Management Order, and LaGens motion for bifurcation was effectively granted, in that the district
court set trial on the liability phase for mid-2011, and, if necessary, trial on the damages
(remedy) phase for mid-2012. On August 24, 2009, LaGen filed a motion to dismiss this lawsuit, and
on September 25, 2009, the U.S. DOJ filed its opposition to the motion to dismiss. On February 18,
2010, the LDEQ filed a motion to intervene in the above lawsuit and a complaint against LaGen for
alleged violations of Louisianas Prevention of Significant Deterioration, or PSD regulations, and
Louisianas Title V operating permit program. LDEQ seeks substantially similar relief to that
requested by the U.S. DOJ. On February 19, 2010, the district court granted LDEQs motion to
intervene. On April 26, 2010, LaGen filed a motion to dismiss LDEQs complaint. On July 21, 2010,
LaGen argued its motions to dismiss, while the U.S. DOJ and LDEQ argued in opposition to the
motions. The judge ordered the parties to submit further briefing within thirty days.
On February 18, 2010, the Louisiana Department of Environmental Quality, or LDEQ, filed a
motion to intervene in the above lawsuit and a complaint against LaGen for alleged violations of
Louisianas Prevention of Significant Deterioration, or PSD regulations and Louisianas Title V
operating permit program. LDEQ seeks substantially similar relief to that requested by the U.S.
DOJ. On February 19, 2010, the district court granted LDEQs motion to intervene. On April 26,
2010, LaGen filed a motion to dismiss LDEQs complaint. On April 28, 2010, the district court
entered a Joint Case Management Order in this matter. As a result of entering this order, LaGens
motion for bifurcation was effectively granted. As such, the first trial on liability will take
place on or about May 2011. The second trial on the remedy will take place on or about March 2012.
On July 21, 2010, LaGen argued its motions to dismiss, while the U.S. DOJ and LDEQ argued in
opposition to the motions. The judge ordered the parties to submit further briefing within thirty
days.
36
Dunkirk Construction Litigation
In 2005, NRG entered into a Consent Decree with the New York State Department of Environmental
Conservation whereby it agreed to reduce certain emissions generated by its Huntley and Dunkirk
power plants. Pursuant to the Consent Decree, on November 21, 2007, Clyde Bergemann EEC, or CBEEC,
and NRG entered into a firm fixed price contract for the supply of equipment, material and services
for six fabric filters for NRGs Dunkirk Electric Power Generating Station. Subsequent to
contracting with NRG, CBEEC subcontracted with Hohl Industrial Services, Inc., or Hohl, to perform
steel erection and equipment installation at Dunkirk.
On August 28, 2009, Hohl filed its original complaint against NRG, its subsidiary Dunkirk
Power LLC, or Dunkirk Power, and CBEEC among others for claims of breach of contract, quantum
meruit, unjust enrichment and foreclosure of mechanics liens. As part of CBEECs contractual
obligation to NRG, CBEEC agreed to defend NRG, under a reservation of rights. CBEEC filed an answer
to the above complaint on behalf of itself, NRG, and Dunkirk Power on October 5, 2009. On December
16, 2009, CBEEC filed a Motion for Summary Judgment on behalf of itself, NRG, and Dunkirk Power.
On February 1, 2010, NRG and Dunkirk Power filed a Motion for Leave to file an Amended Answer with
Cross-Claims against CBEEC. NRG asserted breach of contract claims seeking liquidated damages for
the delays caused by CBEEC. NRG also retained its own counsel to represent its interest in the
cross-claims and reserved its rights to seek reimbursement from CBEEC. On February 17, 2010, CBEEC
filed an Amended Answer with Affirmative Defenses, Counterclaims and Cross-Claims against NRG, in
which it sought $30 million alleging breach of contract, quantum meruit, unjust enrichment, and
foreclosure of two mechanics liens, as a result of alleged delays caused by NRG and Dunkirk Power.
On March 5, 2010, CBEEC and NRG resolved their disputed cross-claims. In April 2010, the other
parties to this litigation settled their disputes which settlement is expected to be final in the
third quarter of 2010.
Excess Mitigation Credits
From January 2002 to April 2005, CenterPoint Energy applied excess mitigation credits, or
EMCs, to its monthly charges to retail electric providers as ordered by the PUCT. The PUCT imposed
these credits to facilitate the transition to competition in Texas, which had the effect of
lowering the retail electric providers monthly charges payable to CenterPoint Energy. As
indicated in its Petition for Review filed with the Supreme Court of Texas on June 2, 2008,
CenterPoint Energy has claimed that the portion of those EMCs credited to Reliant Energy Retail
Services, LLC, or RERS, a retail electric provider and NRG subsidiary acquired from RRI, totaled
$385 million for RERSs Price to Beat Customers. It is unclear what the actual number may be.
Price to Beat was the rate RERS was required by state law to charge residential and small
commercial customers that were transitioned to RERS from the incumbent integrated utility company
commencing in 2002. In its original stranded cost case brought before the PUCT on March 31, 2004,
CenterPoint Energy sought recovery of all EMCs that were credited to all retail electric providers,
including RERS, and the PUCT ordered that relief in its Order on Rehearing in Docket No. 29526, on
December 17, 2004. After an appeal to state district court, the court entered a final judgment on
August 26, 2005, affirming the PUCTs order with regard to EMCs credited to RERS. Various parties
filed appeals of that judgment with the Court of Appeals for the Third District of Texas with the
first such appeal filed on the same date as the state district court judgment and the last such
appeal filed on October 10, 2005. On April 17, 2008, the Court of Appeals for the Third District
reversed the lower courts decision ruling that CenterPoint Energys stranded cost recovery should
exclude only EMCs credited to RERS for its Price to Beat customers. On June 2, 2008, CenterPoint
Energy filed a Petition for Review with the Supreme Court of Texas and on June 19, 2009, the Court
agreed to consider the CenterPoint Energy appeal as well as two related petitions for review filed
by other entities. Oral argument occurred on October 6, 2009.
In November 2008, CenterPoint Energy and Reliant Energy Inc., or REI, on behalf of itself and
affiliates including RERS, agreed to suspend unexpired deadlines, if any, related to limitations
periods that might exist for possible claims against REI and its affiliates if CenterPoint Energy
is ultimately not allowed to include in its stranded cost calculation those EMCs previously
credited to RERS. Regardless of the outcome of the Texas Supreme Court proceeding, NRG believes
that any possible future CenterPoint Energy claim against RERS for EMCs credited to RERS would lack
legal merit. No such claim has been filed.
37
Note 16 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 power
markets are subject to ongoing legislative and regulatory changes that may impact NRGs wholesale
and retail businesses.
In addition to the regulatory proceedings noted below, NRG and its subsidiaries are a party to
other regulatory proceedings arising in the ordinary course of business or have other regulatory
exposure. 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.
PJM On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008,
dismissing a complaint filed by the Maryland Public Service Commission, or MDPSC, together with
other load interests, against PJM challenging the results of the Reliability Pricing Model, or RPM
transition Base Residual Auctions for installed capacity, held between April 2007 and January 2008.
The complaint had sought 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
August 14, 2009, the MDPSC and the New Jersey Board of Public Utilities filed an appeal of FERCs
orders to the U.S. Court of Appeals for the Fourth Circuit, and a successful appeal could disrupt
the auction-determined results and create a refund obligation for market participants. The case
has been transferred to the U.S. Court of Appeals for the DC Circuit.
Midwest ISO v. PJM On March 8, 2010, Midwest ISO filed a complaint against PJM seeking
payments from PJM related to inter-market operations and settlements for congestion costs between
the systems for the period from April 2005 to the present. If the Midwest ISOs allegations are
true, PJM may have significant liability. If PJM makes any payments to the Midwest ISO related to
these claims, PJM is expected to seek to recover the payments from entities that served load and
held transmission congestion rights on PJM during the period in dispute, including NRG, which
provided basic generation service and thus effectively served load. At this time, NRGs share of
any payment by PJM is not expected to be material.
Retail (Replacement Reserve) On November 14, 2006, Constellation Energy Commodities Group,
or Constellation, filed a complaint with the PUCT alleging that ERCOT misapplied the Replacement
Reserve Settlement, or RPRS, Formula contained in the ERCOT protocols from April 10, 2006, through
September 27, 2006. Specifically, Constellation disputed approximately $4 million in
under-scheduling charges for capacity insufficiency asserting that ERCOT applied the wrong
protocol. REPS, other market participants, ERCOT, and PUCT staff opposed Constellations
complaint. On January 25, 2008, the PUCT entered an order finding that ERCOT correctly settled the
capacity insufficiency charges for the disputed dates in accordance with ERCOT protocols and denied
Constellations complaint. On April 9, 2008, Constellation appealed the PUCT order to the Civil
District Court of Travis County, Texas and on June 19, 2009, the court issued a judgment reversing
the PUCT order, finding that the ERCOT protocols were in irreconcilable conflict with each other.
On July 20, 2009, REPS filed an appeal to the Third Court of Appeals in Travis County, Texas,
thereby staying the effect of the trial courts decision. If all appeals are unsuccessful, on
remand to the PUCT, it would determine the appropriate methodology for giving effect to the trial
courts decision. It is not known at this time whether only Constellations under-scheduling
charges, the under-scheduling charges of all other QSEs that disputed REPS charges for the same
time frame, the entire market, or some other approach would be used for any resettlement.
Under the PUCT ordered formula, Qualified Scheduling Entities, or QSEs, who under-scheduled
capacity within any of ERCOTs four congestion zones were assessed under-scheduling charges which
defrayed the costs incurred by ERCOT for RPRS that would otherwise be spread among all load-serving
QSEs. Under the Courts decision, all RPRS costs would be assigned to all load-serving QSEs based
upon their load ratio share without assessing any separate charge to those QSEs who under-scheduled
capacity. If under-scheduling charges for capacity insufficient QSEs were not used to defray RPRS
costs, REPSs share of the total RPRS costs allocated to QSEs would increase.
38
Note 17 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 United States. 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 Gases, or GHG including carbon dioxide, or 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 from 2010 through 2014 to meet NRGs environmental commitments will be approximately
$0.9 billion and are primarily associated with controls on the Companys Big Cajun and Indian River
facilities. These capital expenditures, in general, are related to installation of particulate,
sulfur dioxide, or SO2, nitrogen oxide, or 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 a section of the Clean Water Act regulating cooling water intake
structures, or Phase II 316(b) Rule. NRG continues to explore cost effective alternatives that can
achieve desired results. This estimate reflects anticipated schedules and controls related to the
Clean Air Interstate Rule, or CAIR, Clean Air Transport Rule, or CATR, Maximum Achievable Control
Technology, or MACT for mercury, and the Phase II 316(b) Rule which are under remand to the U.S.
EPA, and, as such, the full impact on the scope and timing of environmental retrofits from any new
or revised regulations cannot be determined at this time.
NRGs current contracts with the Companys rural electrical customers in the South Central
region allow for recovery of a portion of the regions capital costs once in operation, along with
a capital return incurred by complying with new laws, including interest over the asset life of the
required expenditures. The actual recoveries will depend, among other things, on the timing of the
completion of the capital project and the remaining duration of the contracts.
Northeast Region
In January 2006, NRGs Indian River Operations, Inc. received a letter of informal
notification from DNREC stating that it may be a potentially responsible party with respect to
Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility.
On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the
Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is
required in relation to surface water and that a previously planned shoreline stabilization project
would satisfactorily address shoreline erosion. The landfill itself will require a further
Remedial Investigation and Feasibility Study to determine the type and scope of any additional work
required. Until the Remedial Investigation and Feasibility Study is completed, the Company is
unable to predict the impact of any required remediation. On May 29, 2008, DNREC requested that
NRGs Indian River Operations, Inc. 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 DNREC and other trustees to close out the assessment phase.
Pursuant to a consent order dated September 25, 2007, between NRG and DNREC, NRG agreed to
operate the four units at the Indian River plant in a manner that would limit the emissions of
NOx and SO2, and to mothball Units 1 and 2 on May 1, 2011 and May 1, 2010,
respectively. In addition, Units 3 and 4, with a combined generating capacity of approximately 565
MW, could not operate beyond December 31, 2011 unless appropriate control technology was installed
on each unit. Unit 2 was mothballed as planned on May 1, 2010. On July 21, 2010, the court
approved an amended consent order, pursuant to which NRG will retire Unit 3 (155 MW) by December
31, 2013, thereby extending the operable period of the unit by two years without installing
additional control technology. Units 1, 2 and 4 are not affected by the amended consent order.
South Central Region
On February 11, 2009, the U.S. DOJ acting at the request of the U.S. EPA commenced a lawsuit
against LaGen in federal district court in the Middle District of Louisiana alleging violations of
the CAA at the Big Cajun II power plant. This is the same matter for which NOVs were issued to
LaGen on February 15, 2005, and on December 8, 2006. Further discussion on this matter can be
found in Note 15, Commitments and Contingencies, to this Form 10-Q, Louisiana Generating, LLC.
39
Note 18 Condensed Consolidating Financial Information
As of June 30, 2010, the Company had outstanding $1.2 billion of 7.25% Senior Notes due 2014,
$2.4 billion of 7.375% Senior Notes due 2016, $1.1 billion of 7.375% Senior Notes due 2017, and
$700 million of 8.50% Senior Notes due 2019. These notes are guaranteed by certain of NRGs
current and future wholly-owned domestic subsidiaries, or guarantor subsidiaries.
Unless otherwise noted below, each of the following guarantor subsidiaries fully and
unconditionally guaranteed the Senior Notes as of June 30, 2010:
|
|
|
Arthur Kill Power LLC
|
|
NRG Generation Holdings, Inc. |
Astoria Gas Turbine Power LLC
|
|
NRG Huntley Operations Inc. |
Berrians I Gas Turbine Power LLC
|
|
NRG International LLC |
Big Cajun II Unit 4 LLC
|
|
NRG MidAtlantic Affiliate Services Inc. |
Cabrillo Power I LLC
|
|
NRG Middletown Operations Inc. |
Cabrillo Power II LLC
|
|
NRG Montville Operations Inc. |
Carbon Management Solutions LLC
|
|
NRG New Jersey Energy Sales LLC |
Clean Edge Energy LLC
|
|
NRG New Roads Holdings LLC |
Conemaugh Power LLC
|
|
NRG North Central Operations, Inc. |
Connecticut Jet Power LLC
|
|
NRG Northeast Affiliate Services Inc. |
Devon Power LLC
|
|
NRG Norwalk Harbor Operations Inc. |
Dunkirk Power LLC
|
|
NRG Operating Services Inc. |
Eastern Sierra Energy Company
|
|
NRG Oswego Harbor Power Operations Inc. |
Elbow Creek Wind Project LLC
|
|
NRG Power Marketing LLC |
El Segundo Power, LLC
|
|
NRG Retail LLC |
El Segundo Power II LLC
|
|
NRG Saguaro Operations Inc. |
GCP Funding Company LLC
|
|
NRG South Central Affiliate Services Inc. |
Huntley IGCC LLC
|
|
NRG South Central Generating LLC |
Huntley Power LLC
|
|
NRG South Central Operations Inc. |
Indian River IGCC LLC
|
|
NRG South Texas LP |
Indian River Operations Inc.
|
|
NRG Texas LLC |
Indian River Power LLC
|
|
NRG Texas C & I Supply LLC |
James River Power LLC
|
|
NRG Texas Holding Inc. |
Keystone Power LLC
|
|
NRG Texas Power LLC |
Langford Wind Power, LLC
|
|
NRG West Coast LLC |
Louisiana Generating LLC
|
|
NRG Western Affiliate Services Inc. |
Middletown Power LLC
|
|
Oswego Harbor Power LLC |
Montville IGCC LLC
|
|
Reliant Energy Power Supply, LLC |
Montville Power LLC
|
|
Reliant Energy Retail Holdings, LLC |
NEO Corporation
|
|
Reliant Energy Retail Services, LLC |
NEO Freehold-Gen LLC
|
|
RE Retail Receivables, LLC |
NEO Power Services Inc.
|
|
RERH Holdings, LLC |
New Genco GP LLC
|
|
Reliant Energy Services Texas LLC |
Norwalk Power LLC
|
|
Reliant Energy Texas Retail LLC |
NRG Affiliate Services Inc.
|
|
Saguaro Power LLC |
NRG Arthur Kill Operations Inc.
|
|
Somerset Operations Inc. |
NRG Artesian Energy LLC
|
|
Somerset Power LLC |
NRG Astoria Gas Turbine Operations Inc.
|
|
Texas Genco Financing Corp. |
NRG Bayou Cove LLC
|
|
Texas Genco GP, LLC |
NRG Cabrillo Power Operations Inc.
|
|
Texas Genco Holdings, Inc. |
NRG California Peaker Operations LLC
|
|
Texas Genco LP, LLC |
NRG Cedar Bayou Development Company LLC
|
|
Texas Genco Operating Services, LLC |
NRG Connecticut Affiliate Services Inc.
|
|
Texas Genco Services, LP |
NRG Construction LLC
|
|
Vienna Operations, Inc. |
NRG Devon Operations Inc.
|
|
Vienna Power LLC |
NRG Dunkirk Operations, Inc.
|
|
WCP (Generation) Holdings LLC |
NRG Energy Services LLC
|
|
West Coast Power LLC |
NRG El Segundo Operations Inc. |
|
|
40
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, the guarantor subsidiaries and the non-guarantor subsidiaries in accordance
with Rule 3-10 under the Securities and Exchange Commissions Regulation S-X. The financial
information may not necessarily be indicative of results of operations or financial position had
the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.
In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor
subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies
acquired, the fair values of the assets and liabilities acquired have been presented on a
push-down accounting basis.
41
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
2,066 |
|
|
$ |
74 |
|
|
$ |
|
|
|
$ |
(7 |
) |
|
$ |
2,133 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
1,283 |
|
|
|
53 |
|
|
|
|
|
|
|
(7 |
) |
|
|
1,329 |
|
Depreciation and amortization |
|
|
202 |
|
|
|
4 |
|
|
|
2 |
|
|
|
|
|
|
|
208 |
|
Selling, general and administrative |
|
|
72 |
|
|
|
2 |
|
|
|
65 |
|
|
|
|
|
|
|
139 |
|
Development costs |
|
|
|
|
|
|
3 |
|
|
|
10 |
|
|
|
|
|
|
|
13 |
|
|
Total operating costs and expenses |
|
|
1,557 |
|
|
|
62 |
|
|
|
77 |
|
|
|
(7 |
) |
|
|
1,689 |
|
|
Operating Income/(Loss) |
|
|
509 |
|
|
|
12 |
|
|
|
(77 |
) |
|
|
|
|
|
|
444 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
15 |
|
|
|
|
|
|
|
332 |
|
|
|
(347 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
1 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
11 |
|
Other income, net |
|
|
2 |
|
|
|
14 |
|
|
|
3 |
|
|
|
|
|
|
|
19 |
|
Interest expense |
|
|
(6 |
) |
|
|
(9 |
) |
|
|
(132 |
) |
|
|
|
|
|
|
(147 |
) |
|
Total other income/(expense) |
|
|
12 |
|
|
|
15 |
|
|
|
203 |
|
|
|
(347 |
) |
|
|
(117 |
) |
|
Income/(Losses) Before Income Taxes |
|
|
521 |
|
|
|
27 |
|
|
|
126 |
|
|
|
(347 |
) |
|
|
327 |
|
Income tax expense/(benefit) |
|
|
190 |
|
|
|
12 |
|
|
|
(85 |
) |
|
|
|
|
|
|
117 |
|
|
Net Income |
|
|
331 |
|
|
|
15 |
|
|
|
211 |
|
|
|
(347 |
) |
|
|
210 |
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net Income attributable to NRG Energy, Inc. |
|
$ |
332 |
|
|
$ |
15 |
|
|
$ |
211 |
|
|
$ |
(347 |
) |
|
$ |
211 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
42
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
4,193 |
|
|
$ |
169 |
|
|
$ |
|
|
|
$ |
(14 |
) |
|
$ |
4,348 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
2,856 |
|
|
|
119 |
|
|
|
7 |
|
|
|
(14 |
) |
|
|
2,968 |
|
Depreciation and amortization |
|
|
392 |
|
|
|
14 |
|
|
|
4 |
|
|
|
|
|
|
|
410 |
|
Selling general and administrative |
|
|
139 |
|
|
|
5 |
|
|
|
125 |
|
|
|
|
|
|
|
269 |
|
Development costs |
|
|
|
|
|
|
6 |
|
|
|
16 |
|
|
|
|
|
|
|
22 |
|
|
Total operating costs and expenses |
|
|
3,387 |
|
|
|
144 |
|
|
|
152 |
|
|
|
(14 |
) |
|
|
3,669 |
|
|
Gain on sale of assets |
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
23 |
|
|
Operating Income/(Loss) |
|
|
806 |
|
|
|
25 |
|
|
|
(129 |
) |
|
|
|
|
|
|
702 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
22 |
|
|
|
|
|
|
|
526 |
|
|
|
(548 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
1 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
25 |
|
Other income, net |
|
|
3 |
|
|
|
17 |
|
|
|
3 |
|
|
|
|
|
|
|
23 |
|
Interest expense |
|
|
(11 |
) |
|
|
(23 |
) |
|
|
(266 |
) |
|
|
|
|
|
|
(300 |
) |
|
Total other income/(expense) |
|
|
15 |
|
|
|
18 |
|
|
|
263 |
|
|
|
(548 |
) |
|
|
(252 |
) |
|
Income/(Losses) Before Income Taxes |
|
|
821 |
|
|
|
43 |
|
|
|
134 |
|
|
|
(548 |
) |
|
|
450 |
|
Income tax expense/(benefit) |
|
|
301 |
|
|
|
16 |
|
|
|
(135 |
) |
|
|
|
|
|
|
182 |
|
|
Net Income |
|
|
520 |
|
|
|
27 |
|
|
|
269 |
|
|
|
(548 |
) |
|
|
268 |
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net Income attributable to NRG Energy, Inc. |
|
$ |
521 |
|
|
$ |
27 |
|
|
$ |
269 |
|
|
$ |
(548 |
) |
|
$ |
269 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
43
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
NRG Energy, Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
34 |
|
|
$ |
154 |
|
|
$ |
1,980 |
|
|
$ |
|
|
|
$ |
2,168 |
|
Funds deposited by counterparties |
|
|
310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
310 |
|
Restricted cash |
|
|
1 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
Accounts receivable, net |
|
|
876 |
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
909 |
|
Inventory |
|
|
527 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
535 |
|
Derivative instruments valuation |
|
|
1,800 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,800 |
|
Cash collateral paid in support of
energy risk management activities |
|
|
389 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
391 |
|
Prepayments and other current assets |
|
|
62 |
|
|
|
55 |
|
|
|
240 |
|
|
|
(114 |
) |
|
|
243 |
|
|
Total current assets |
|
|
3,999 |
|
|
|
264 |
|
|
|
2,220 |
|
|
|
(114 |
) |
|
|
6,369 |
|
|
Net property, plant and equipment |
|
|
10,515 |
|
|
|
1,125 |
|
|
|
153 |
|
|
|
|
|
|
|
11,793 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
753 |
|
|
|
258 |
|
|
|
20,751 |
|
|
|
(21,762 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
42 |
|
|
|
352 |
|
|
|
|
|
|
|
|
|
|
|
394 |
|
Capital leases and notes receivable,
less current portion |
|
|
5,626 |
|
|
|
431 |
|
|
|
3,169 |
|
|
|
(8,792 |
) |
|
|
434 |
|
Goodwill |
|
|
1,713 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
1,716 |
|
Intangible assets, net |
|
|
1,567 |
|
|
|
58 |
|
|
|
33 |
|
|
|
(32 |
) |
|
|
1,626 |
|
Nuclear decommissioning trust fund |
|
|
360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
360 |
|
Derivative instruments valuation |
|
|
899 |
|
|
|
|
|
|
|
11 |
|
|
|
|
|
|
|
910 |
|
Restricted cash supporting funded
letter of credit facility |
|
|
|
|
|
|
1,300 |
|
|
|
|
|
|
|
|
|
|
|
1,300 |
|
Other non-current assets |
|
|
39 |
|
|
|
13 |
|
|
|
149 |
|
|
|
|
|
|
|
201 |
|
|
Total other assets |
|
|
10,999 |
|
|
|
2,415 |
|
|
|
24,113 |
|
|
|
(30,586 |
) |
|
|
6,941 |
|
|
Total Assets |
|
$ |
25,513 |
|
|
$ |
3,804 |
|
|
$ |
26,486 |
|
|
$ |
(30,700 |
) |
|
$ |
25,103 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and
capital leases |
|
$ |
58 |
|
|
$ |
159 |
|
|
$ |
20 |
|
|
$ |
(58 |
) |
|
$ |
179 |
|
Accounts payable |
|
|
(3,111 |
) |
|
|
483 |
|
|
|
3,318 |
|
|
|
|
|
|
|
690 |
|
Derivative instruments valuation |
|
|
1,434 |
|
|
|
2 |
|
|
|
48 |
|
|
|
|
|
|
|
1,484 |
|
Deferred income taxes |
|
|
(4 |
) |
|
|
|
|
|
|
248 |
|
|
|
|
|
|
|
244 |
|
Cash collateral received in support of
energy risk management activities |
|
|
310 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
310 |
|
Accrued expenses and other current
liabilities |
|
|
345 |
|
|
|
33 |
|
|
|
302 |
|
|
|
(57 |
) |
|
|
623 |
|
|
Total current liabilities |
|
|
(968 |
) |
|
|
677 |
|
|
|
3,936 |
|
|
|
(115 |
) |
|
|
3,530 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
2,936 |
|
|
|
853 |
|
|
|
12,994 |
|
|
|
(8,792 |
) |
|
|
7,991 |
|
Funded letter of credit |
|
|
|
|
|
|
|
|
|
|
1,300 |
|
|
|
|
|
|
|
1,300 |
|
Nuclear decommissioning reserve |
|
|
309 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
309 |
|
Nuclear decommissioning trust liability |
|
|
234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
234 |
|
Deferred income taxes |
|
|
2,231 |
|
|
|
(193 |
) |
|
|
(270 |
) |
|
|
|
|
|
|
1,768 |
|
Derivative instruments valuation |
|
|
364 |
|
|
|
40 |
|
|
|
29 |
|
|
|
|
|
|
|
433 |
|
Out-of-market contracts |
|
|
283 |
|
|
|
6 |
|
|
|
|
|
|
|
(31 |
) |
|
|
258 |
|
Other non-current liabilities |
|
|
739 |
|
|
|
27 |
|
|
|
236 |
|
|
|
|
|
|
|
1,002 |
|
|
Total non-current liabilities |
|
|
7,096 |
|
|
|
733 |
|
|
|
14,289 |
|
|
|
(8,823 |
) |
|
|
13,295 |
|
|
Total liabilities |
|
|
6,128 |
|
|
|
1,410 |
|
|
|
18,225 |
|
|
|
(8,938 |
) |
|
|
16,825 |
|
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
248 |
|
|
|
|
|
|
|
248 |
|
Stockholders Equity |
|
|
19,385 |
|
|
|
2,394 |
|
|
|
8,013 |
|
|
|
(21,762 |
) |
|
|
8,030 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
25,513 |
|
|
$ |
3,804 |
|
|
$ |
26,486 |
|
|
$ |
(30,700 |
) |
|
$ |
25,103 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
44
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2010
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
520 |
|
|
$ |
27 |
|
|
$ |
269 |
|
|
$ |
(548 |
) |
|
$ |
268 |
|
Adjustments to reconcile net income to net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity in (earnings)/losses of unconsolidated
affiliates and consolidated subsidiaries |
|
|
10 |
|
|
|
(11 |
) |
|
|
(489 |
) |
|
|
481 |
|
|
|
(9 |
) |
Depreciation and amortization |
|
|
392 |
|
|
|
14 |
|
|
|
4 |
|
|
|
|
|
|
|
410 |
|
Provision for bad debts |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22 |
|
Amortization of nuclear fuel |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Amortization of financing costs and debt discount/premiums |
|
|
|
|
|
|
3 |
|
|
|
12 |
|
|
|
|
|
|
|
15 |
|
Amortization of intangibles and out-of-market contracts |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Changes in deferred income taxes and liability for unrecognized tax
benefits |
|
|
300 |
|
|
|
2 |
|
|
|
(123 |
) |
|
|
|
|
|
|
179 |
|
Changes in nuclear decommissioning trust liability |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Changes in derivatives |
|
|
(57 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
(55 |
) |
Changes in collateral deposits supporting energy risk management
activities |
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(30 |
) |
Loss/(gain) on sale of assets |
|
|
12 |
|
|
|
|
|
|
|
(23 |
) |
|
|
|
|
|
|
(11 |
) |
Loss on sale of emission allowances |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
15 |
|
Changes in option premiums collected, net of acquisition |
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34 |
|
Cash (used)/provided by changes in other working capital, net of
acquisitions |
|
|
(505 |
) |
|
|
(75 |
) |
|
|
315 |
|
|
|
|
|
|
|
(265 |
) |
|
Net Cash Provided/(Used) by Operating Activities |
|
|
730 |
|
|
|
(38 |
) |
|
|
(20 |
) |
|
|
(67 |
) |
|
|
605 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries |
|
|
(739 |
) |
|
|
|
|
|
|
(142 |
) |
|
|
881 |
|
|
|
|
|
Acquisition of businesses |
|
|
|
|
|
|
(141 |
) |
|
|
|
|
|
|
|
|
|
|
(141 |
) |
Investment in subsidiaries |
|
|
|
|
|
|
1,721 |
|
|
|
(1,721 |
) |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(145 |
) |
|
|
(159 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
(330 |
) |
Increase in restricted cash, net |
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
(11 |
) |
Decrease in notes receivable |
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Purchases of emission allowances |
|
|
(45 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45 |
) |
Proceeds from sale of emission allowances |
|
|
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11 |
|
Investments in nuclear decommissioning trust fund securities |
|
|
(76 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(76 |
) |
Proceeds from sales of nuclear decommissioning trust fund securities |
|
|
67 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
67 |
|
Proceeds from renewable energy grants |
|
|
84 |
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
102 |
|
Proceeds from sale of assets, net |
|
|
1 |
|
|
|
|
|
|
|
29 |
|
|
|
|
|
|
|
30 |
|
Other |
|
|
|
|
|
|
(2 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
(7 |
) |
|
Net Cash (Used)/Provided by Investing Activities |
|
|
(842 |
) |
|
|
1,441 |
|
|
|
(1,865 |
) |
|
|
881 |
|
|
|
(385 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans |
|
|
127 |
|
|
|
15 |
|
|
|
739 |
|
|
|
(881 |
) |
|
|
|
|
Payment of intercompany dividends |
|
|
(30 |
) |
|
|
(37 |
) |
|
|
|
|
|
|
67 |
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Payments for treasury stock |
|
|
|
|
|
|
|
|
|
|
(50 |
) |
|
|
|
|
|
|
(50 |
) |
Net receipt from acquired derivatives that include financing elements |
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Installment proceeds from sale of non-controlling interest in subsidiary |
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
50 |
|
Proceeds from issuance of long-term debt |
|
|
3 |
|
|
|
138 |
|
|
|
|
|
|
|
|
|
|
|
141 |
|
Proceeds from issuance of term loan for funded letter of credit facility |
|
|
|
|
|
|
|
|
|
|
1,300 |
|
|
|
|
|
|
|
1,300 |
|
Increase in restricted cash supporting funded letter of credit facility |
|
|
|
|
|
|
(1,300 |
) |
|
|
|
|
|
|
|
|
|
|
(1,300 |
) |
Proceeds from issuance of common stock |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Payment of deferred debt issuance costs |
|
|
(1 |
) |
|
|
(7 |
) |
|
|
(45 |
) |
|
|
|
|
|
|
(53 |
) |
Payment of short and long-term debt |
|
|
|
|
|
|
(219 |
) |
|
|
(240 |
) |
|
|
|
|
|
|
(459 |
) |
|
Net Cash Provided/(Used) by Financing Activities |
|
|
126 |
|
|
|
(1,360 |
) |
|
|
1,701 |
|
|
|
(814 |
) |
|
|
(347 |
) |
Effect of exchange rate changes on cash and cash equivalents |
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
(9 |
) |
|
Net Increase/(Decrease) in Cash and Cash Equivalents |
|
|
14 |
|
|
|
34 |
|
|
|
(184 |
) |
|
|
|
|
|
|
(136 |
) |
Cash and Cash Equivalents at Beginning of Period |
|
|
20 |
|
|
|
120 |
|
|
|
2,164 |
|
|
|
|
|
|
|
2,304 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
34 |
|
|
$ |
154 |
|
|
$ |
1,980 |
|
|
$ |
|
|
|
$ |
2,168 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
45
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
1,025 |
|
|
$ |
1,254 |
|
|
$ |
32 |
|
|
$ |
(74 |
) |
|
$ |
2,237 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
596 |
|
|
|
719 |
|
|
|
1 |
|
|
|
(74 |
) |
|
|
1,242 |
|
Depreciation and amortization |
|
|
157 |
|
|
|
54 |
|
|
|
2 |
|
|
|
|
|
|
|
213 |
|
Selling, general and administrative |
|
|
17 |
|
|
|
51 |
|
|
|
63 |
|
|
|
|
|
|
|
131 |
|
Acquisition related transaction and integration costs |
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
23 |
|
Development costs |
|
|
2 |
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
9 |
|
|
Total operating costs and expenses |
|
|
772 |
|
|
|
827 |
|
|
|
93 |
|
|
|
(74 |
) |
|
|
1,618 |
|
|
Operating Income/(Loss) |
|
|
253 |
|
|
|
427 |
|
|
|
(61 |
) |
|
|
|
|
|
|
619 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
120 |
|
|
|
|
|
|
|
477 |
|
|
|
(597 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
Gain on sale of equity method investment |
|
|
|
|
|
|
128 |
|
|
|
|
|
|
|
|
|
|
|
128 |
|
Other income/(expense), net |
|
|
2 |
|
|
|
(12 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(11 |
) |
Interest expense |
|
|
(18 |
) |
|
|
(38 |
) |
|
|
(103 |
) |
|
|
|
|
|
|
(159 |
) |
|
Total other income/(expense) |
|
|
107 |
|
|
|
80 |
|
|
|
373 |
|
|
|
(597 |
) |
|
|
(37 |
) |
|
Income/(Loss) Before Income Taxes |
|
|
360 |
|
|
|
507 |
|
|
|
312 |
|
|
|
(597 |
) |
|
|
582 |
|
Income tax expense/(benefit) |
|
|
97 |
|
|
|
174 |
|
|
|
(121 |
) |
|
|
|
|
|
|
150 |
|
|
Net Income |
|
|
263 |
|
|
|
333 |
|
|
|
433 |
|
|
|
(597 |
) |
|
|
432 |
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net Income/(Loss) attributable to NRG Energy, Inc. |
|
$ |
264 |
|
|
$ |
333 |
|
|
$ |
433 |
|
|
$ |
(597 |
) |
|
$ |
433 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
46
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
2,591 |
|
|
$ |
1,349 |
|
|
$ |
32 |
|
|
$ |
(77 |
) |
|
$ |
3,895 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
1,294 |
|
|
|
787 |
|
|
|
4 |
|
|
|
(77 |
) |
|
|
2,008 |
|
Depreciation and amortization |
|
|
315 |
|
|
|
64 |
|
|
|
3 |
|
|
|
|
|
|
|
382 |
|
Selling, general and administrative |
|
|
34 |
|
|
|
54 |
|
|
|
126 |
|
|
|
|
|
|
|
214 |
|
Acquisition related transaction and integration costs |
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
35 |
|
Development costs |
|
|
4 |
|
|
|
5 |
|
|
|
13 |
|
|
|
|
|
|
|
22 |
|
|
Total operating costs and expenses |
|
|
1,647 |
|
|
|
910 |
|
|
|
181 |
|
|
|
(77 |
) |
|
|
2,661 |
|
|
Operating Income/(Loss) |
|
|
944 |
|
|
|
439 |
|
|
|
(149 |
) |
|
|
|
|
|
|
1,234 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
129 |
|
|
|
|
|
|
|
874 |
|
|
|
(1,003 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
4 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Gain on sale of equity method investment |
|
|
|
|
|
|
128 |
|
|
|
|
|
|
|
|
|
|
|
128 |
|
Other income/(expense), net |
|
|
3 |
|
|
|
(19 |
) |
|
|
2 |
|
|
|
|
|
|
|
(14 |
) |
Interest expense |
|
|
(66 |
) |
|
|
(59 |
) |
|
|
(172 |
) |
|
|
|
|
|
|
(297 |
) |
|
Total other income/(expense) |
|
|
70 |
|
|
|
73 |
|
|
|
704 |
|
|
|
(1,003 |
) |
|
|
(156 |
) |
|
Income/(Loss) Before Income Taxes |
|
|
1,014 |
|
|
|
512 |
|
|
|
555 |
|
|
|
(1,003 |
) |
|
|
1,078 |
|
Income tax expense/(benefit) |
|
|
349 |
|
|
|
175 |
|
|
|
(76 |
) |
|
|
|
|
|
|
448 |
|
|
Net Income |
|
|
665 |
|
|
|
337 |
|
|
|
631 |
|
|
|
(1,003 |
) |
|
|
630 |
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Net Income attributable to NRG Energy, Inc. |
|
$ |
666 |
|
|
$ |
337 |
|
|
$ |
631 |
|
|
$ |
(1,003 |
) |
|
$ |
631 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
47
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
Guarantor |
|
NRG Energy, Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
ASSETS |
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
20 |
|
|
$ |
120 |
|
|
$ |
2,164 |
|
|
$ |
|
|
|
$ |
2,304 |
|
Funds deposited by counterparties |
|
|
177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
177 |
|
Restricted cash |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Accounts receivable-trade, net |
|
|
837 |
|
|
|
39 |
|
|
|
|
|
|
|
|
|
|
|
876 |
|
Inventory |
|
|
529 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
541 |
|
Derivative instruments valuation |
|
|
1,636 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,636 |
|
Cash collateral paid in support of
energy risk management activities |
|
|
359 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
361 |
|
Prepayments and other current assets |
|
|
194 |
|
|
|
61 |
|
|
|
157 |
|
|
|
(101 |
) |
|
|
311 |
|
|
Total current assets |
|
|
3,753 |
|
|
|
235 |
|
|
|
2,321 |
|
|
|
(101 |
) |
|
|
6,208 |
|
|
Net Property, Plant and Equipment |
|
|
10,494 |
|
|
|
1,009 |
|
|
|
61 |
|
|
|
|
|
|
|
11,564 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
613 |
|
|
|
222 |
|
|
|
16,862 |
|
|
|
(17,697 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
42 |
|
|
|
367 |
|
|
|
|
|
|
|
|
|
|
|
409 |
|
Capital leases and note receivable,
less current portion |
|
|
4,982 |
|
|
|
504 |
|
|
|
3,027 |
|
|
|
(8,009 |
) |
|
|
504 |
|
Goodwill |
|
|
1,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,718 |
|
Intangible assets, net |
|
|
1,755 |
|
|
|
20 |
|
|
|
33 |
|
|
|
(31 |
) |
|
|
1,777 |
|
Nuclear decommissioning trust fund |
|
|
367 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
367 |
|
Derivative instruments valuation |
|
|
718 |
|
|
|
|
|
|
|
8 |
|
|
|
(43 |
) |
|
|
683 |
|
Other non-current assets |
|
|
29 |
|
|
|
8 |
|
|
|
111 |
|
|
|
|
|
|
|
148 |
|
|
Total other assets |
|
|
10,224 |
|
|
|
1,121 |
|
|
|
20,041 |
|
|
|
(25,780 |
) |
|
|
5,606 |
|
|
Total Assets |
|
$ |
24,471 |
|
|
$ |
2,365 |
|
|
$ |
22,423 |
|
|
$ |
(25,881 |
) |
|
$ |
23,378 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases |
|
$ |
58 |
|
|
$ |
310 |
|
|
$ |
261 |
|
|
$ |
(58 |
) |
|
$ |
571 |
|
Accounts payable |
|
|
(852 |
) |
|
|
393 |
|
|
|
1,156 |
|
|
|
|
|
|
|
697 |
|
Derivative instruments valuation |
|
|
1,469 |
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
1,473 |
|
Deferred income taxes |
|
|
456 |
|
|
|
11 |
|
|
|
(270 |
) |
|
|
|
|
|
|
197 |
|
Cash collateral received in support of energy risk management
activities |
|
|
177 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
177 |
|
Accrued expenses and other current liabilities |
|
|
261 |
|
|
|
82 |
|
|
|
347 |
|
|
|
(43 |
) |
|
|
647 |
|
|
Total current liabilities |
|
|
1,569 |
|
|
|
798 |
|
|
|
1,496 |
|
|
|
(101 |
) |
|
|
3,762 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
2,533 |
|
|
|
1,003 |
|
|
|
12,320 |
|
|
|
(8,009 |
) |
|
|
7,847 |
|
Nuclear decommissioning reserve |
|
|
300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
300 |
|
Nuclear decommissioning trust liability |
|
|
255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
255 |
|
Deferred income taxes |
|
|
1,711 |
|
|
|
(165 |
) |
|
|
237 |
|
|
|
|
|
|
|
1,783 |
|
Derivative instruments valuation |
|
|
323 |
|
|
|
28 |
|
|
|
79 |
|
|
|
(43 |
) |
|
|
387 |
|
Out-of-market contracts |
|
|
318 |
|
|
|
7 |
|
|
|
|
|
|
|
(31 |
) |
|
|
294 |
|
Other non-current liabilities |
|
|
431 |
|
|
|
16 |
|
|
|
359 |
|
|
|
|
|
|
|
806 |
|
|
Total non-current liabilities |
|
|
5,871 |
|
|
|
889 |
|
|
|
12,995 |
|
|
|
(8,083 |
) |
|
|
11,672 |
|
|
Total liabilities |
|
|
7,440 |
|
|
|
1,687 |
|
|
|
14,491 |
|
|
|
(8,184 |
) |
|
|
15,434 |
|
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
17,031 |
|
|
|
678 |
|
|
|
7,685 |
|
|
|
(17,697 |
) |
|
|
7,697 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
24,471 |
|
|
$ |
2,365 |
|
|
$ |
22,423 |
|
|
$ |
(25,881 |
) |
|
$ |
23,378 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
48
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
666 |
|
|
$ |
337 |
|
|
$ |
630 |
|
|
$ |
(1,003 |
) |
|
$ |
630 |
|
Adjustments to reconcile net income to net cash provided by
operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity in (earnings)/losses of
unconsolidated affiliates and consolidated subsidiaries |
|
|
197 |
|
|
|
(23 |
) |
|
|
(544 |
) |
|
|
343 |
|
|
|
(27 |
) |
Depreciation and amortization |
|
|
315 |
|
|
|
64 |
|
|
|
3 |
|
|
|
|
|
|
|
382 |
|
Provision for bad debts |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Amortization of nuclear fuel |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Amortization of financing costs and debt discount/premiums |
|
|
|
|
|
|
7 |
|
|
|
14 |
|
|
|
|
|
|
|
21 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(49 |
) |
|
|
64 |
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Changes in deferred income taxes and liability for
unrecognized tax benefits |
|
|
100 |
|
|
|
14 |
|
|
|
331 |
|
|
|
|
|
|
|
445 |
|
Changes in nuclear decommissioning liability |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Changes in derivatives |
|
|
(198 |
) |
|
|
(170 |
) |
|
|
|
|
|
|
|
|
|
|
(368 |
) |
Changes in collateral deposits supporting energy risk
management activities |
|
|
274 |
|
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
245 |
|
Gain on sale of equity method investment |
|
|
|
|
|
|
(128 |
) |
|
|
|
|
|
|
|
|
|
|
(128 |
) |
Gain on sale of assets |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
Gain on sale of emission allowances |
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9 |
) |
Gain recognized on settlement of pre-existing relationship |
|
|
|
|
|
|
|
|
|
|
(31 |
) |
|
|
|
|
|
|
(31 |
) |
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
13 |
|
Changes in option premium collected, net of acquisition |
|
|
(265 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(270 |
) |
Cash provided/(used) by changes in other working capital,
net of acquisition |
|
|
533 |
|
|
|
170 |
|
|
|
(941 |
) |
|
|
|
|
|
|
(238 |
) |
|
Net Cash Provided/(Used) by Operating Activities |
|
|
1,597 |
|
|
|
310 |
|
|
|
(525 |
) |
|
|
(660 |
) |
|
|
722 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries |
|
|
(901 |
) |
|
|
|
|
|
|
160 |
|
|
|
741 |
|
|
|
|
|
Acquisition of Reliant Energy, net of cash acquired |
|
|
|
|
|
|
(57 |
) |
|
|
(288 |
) |
|
|
|
|
|
|
(345 |
) |
Investment in Reliant Energy |
|
|
|
|
|
|
200 |
|
|
|
(200 |
) |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(263 |
) |
|
|
(109 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(374 |
) |
(Increase)/decrease in restricted cash, net |
|
|
6 |
|
|
|
(9 |
) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Decrease/(increase) in notes receivable |
|
|
|
|
|
|
(47 |
) |
|
|
36 |
|
|
|
|
|
|
|
(11 |
) |
Purchases of emission allowances |
|
|
(52 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(52 |
) |
Proceeds from sale of emission allowances |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15 |
|
Investment in nuclear decommissioning trust fund securities |
|
|
(172 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(172 |
) |
Proceeds from sales of nuclear decommissioning trust fund
securities |
|
|
157 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
157 |
|
Proceeds from sale of assets, net |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Other investment |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
(5 |
) |
Proceeds from sale of equity method investment |
|
|
|
|
|
|
284 |
|
|
|
|
|
|
|
|
|
|
|
284 |
|
|
Net Cash (Used)/Provided by Investing Activities |
|
|
(1,204 |
) |
|
|
262 |
|
|
|
(299 |
) |
|
|
741 |
|
|
|
(500 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans |
|
|
(188 |
) |
|
|
28 |
|
|
|
901 |
|
|
|
(741 |
) |
|
|
|
|
Payment from intercompany dividends |
|
|
(330 |
) |
|
|
(330 |
) |
|
|
|
|
|
|
660 |
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(21 |
) |
|
|
|
|
|
|
(21 |
) |
Receipt from/(payment of) from financing element of acquired
derivatives |
|
|
102 |
|
|
|
(124 |
) |
|
|
|
|
|
|
|
|
|
|
(22 |
) |
Installment proceeds from sale of noncontrolling interest in
subsidiary |
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
50 |
|
Proceeds from issuance of long-term debt |
|
|
34 |
|
|
|
98 |
|
|
|
688 |
|
|
|
|
|
|
|
820 |
|
Payment of deferred debt issuance costs |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(27 |
) |
|
|
|
|
|
|
(29 |
) |
Payment of short and long-term debt |
|
|
|
|
|
|
(20 |
) |
|
|
(213 |
) |
|
|
|
|
|
|
(233 |
) |
|
Net Cash (Used)/Provided by Financing Activities |
|
|
(383 |
) |
|
|
(299 |
) |
|
|
1,328 |
|
|
|
(81 |
) |
|
|
565 |
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
Net Decrease in Cash and Cash Equivalent |
|
|
10 |
|
|
|
274 |
|
|
|
504 |
|
|
|
|
|
|
|
788 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
(2 |
) |
|
|
159 |
|
|
|
1,337 |
|
|
|
|
|
|
|
1,494 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
8 |
|
|
$ |
433 |
|
|
$ |
1,841 |
|
|
$ |
|
|
|
$ |
2,282 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
49
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As you read this discussion and analysis, refer to the Companys Condensed Consolidated
Statements of Operations to this Form 10-Q, which present the results of operations for the three
and six months ended June 30, 2010, and 2009. Also refer to NRGs Annual Report on Form 10-K for
the year ended December 31, 2009, which includes detailed discussions of various items impacting
the Companys business, results of operations and financial condition, including: 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 and Estimates section.
The discussion and analysis below has been organized as follows:
|
|
|
Executive Summary, including introduction and overview, business strategy, and changes to
the business environment during the period including regulatory and environmental matters; |
|
|
|
|
Results of operations beginning with an overview of the Companys consolidated results,
followed by a more detailed discussion of those results by operating segment; |
|
|
|
|
Financial condition addressing liquidity position, sources and uses of cash, capital
resources and requirements, commitments, and off-balance sheet arrangements; and |
|
|
|
|
Known trends that may affect NRGs results of operations and financial condition in the
future. |
50
Executive Summary
Introduction and Overview
NRG Energy, Inc., or NRG or the Company, is primarily a wholesale power generation company
with a significant presence in major competitive power markets in the United States, as well as a
major retail electricity provider in the ERCOT (Texas) market through Reliant Energy. NRG is
engaged in the ownership, development, construction and operation of power generation facilities,
the transacting in and trading of fuel and transportation services, the trading of energy, capacity
and related products in the United States and select international markets, and the supply of
electricity and energy services to retail electricity customers in the Texas market.
As of June 30, 2010, NRG had a total global generation portfolio of 187 active operating
fossil fuel and nuclear generation units, at 44 power generation plants, with an aggregate
generation capacity of approximately 23,985 MW, and approximately 255 MW under construction which
includes partner interests of 125 MW. In addition to its fossil fuel plant ownership, NRG has
ownership interests in operating renewable facilities with an aggregate generation capacity of 465
MW, consisting of four wind farms representing an aggregate generation capacity of 445 MW and a 20
MW solar facility. Within the United States, NRG has large and diversified power generation
portfolios in terms of geography, fuel-type and dispatch levels, with approximately 22,980 MW of
fossil fuel and nuclear generation capacity in 179 active generating units at 42 plants. The
Companys power generation facilities are most heavily concentrated in Texas (approximately 11,440
MW, including 445 MW from four wind farms), the Northeast (approximately 6,885 MW), South Central
(approximately 2,855 MW), and West (approximately 2,150 MW, including 20 MW from a solar facility)
regions of the United States, with approximately 115 MW of additional generation capacity from the
Companys thermal assets. In addition, through certain foreign subsidiaries, NRG has investments
in power generation projects located in Australia and Germany with approximately 1,005 MW of
generation capacity.
NRGs principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired,
nuclear and renewable facilities, representing approximately 45%, 31%, 17%, 5% and 2% of the
Companys total domestic generation capacity, respectively. In addition, 9% of NRGs domestic
generating facilities have dual or multiple fuel capacity, which allows those plants to dispatch
with the lowest cost fuel option.
NRGs domestic generation facilities consist of intermittent, baseload, intermediate and
peaking power generation facilities, the ranking of which is referred to as the Merit Order, and
include thermal energy production plants. The sale of capacity and power from baseload generation
facilities accounts for the majority of the Companys revenues and provides a stable source of cash
flow. In addition, NRGs generation portfolio provides the Company with opportunities to capture
additional revenues by selling power during periods of peak demand, offering capacity or similar
products to retail electric providers and others, and providing ancillary services to support
system reliability.
Reliant Energy, the Companys retail electricity provider, arranges for the transmission and
delivery of electricity to customers, bills customers, collects payments for electricity sold and
maintains call centers to provide customer service. Based on metered locations, as of June 30,
2010, Reliant Energy had approximately 1.5 million Mass customers and approximately 0.1 million C&I
customers, with expected annual volumes for these customer classes of 20 TWhs and 25-30 TWhs,
respectively.
Furthermore, NRG is focused on the development and investment in energy-related new businesses
and new technologies where the benefits of such investments represent significant commercial
opportunities and create a comparative advantage for the Company. These investments include low or
no GHG emitting energy generating sources, such as nuclear, wind, solar thermal, photovoltaic,
biomass, clean coal and gasification, the retrofit of post-combustion carbon capture
technologies, and developments in the electric vehicle ecosystem.
NRGs Business Strategy
NRGs business strategy is intended to maximize shareholder value through the production and
sale of safe, reliable and affordable power to its customers in the markets served by the Company,
while aggressively positioning the Company to meet the markets increasing demand for sustainable
and low carbon energy solutions. This dual strategy is designed to perfect the Companys core
business of competitive power generation and establish the Company as a leading provider of
sustainable energy solutions, while utilizing the Companys retail business to complement and
advance both initiatives.
51
The Companys core business is focused on: (i) top decile operating performance of its
existing operating assets, (ii) optimal hedging of baseload and retail operations, while retaining
optionality on the Companys gas fleet, (iii) repowering of power generation assets at existing
sites and reducing environmental impacts, (iv) pursuit of selective acquisitions, joint ventures,
divestitures and investments, and (v) engaging in a proactive capital allocation plan focused on
achieving the regular return of capital to stockholders within the dictates of prudent balance
sheet management.
In addition, the Company believes that success in providing energy solutions that address
sustainability and climate change concerns will not only reduce the carbon and capital intensity of
the Company in the future, it also will reduce the real and perceived linkage between the Companys
financial performance and prospects, and volatile commodity prices, particularly with respect to
natural gas. The Companys initiatives in this area of future growth are focused on: (i) low
carbon baseload primarily nuclear generation, (ii) renewables, with a concentration in solar and
wind generation and development, (iii) fast start, high efficiency gas-fired capacity in the
Companys core regions, (iv) electric vehicle ecosystems, and (v) smart grid services. The
Companys advancements in each of these areas are driven by select acquisitions, joint ventures,
and investments that are more fully described in the Companys 2009 Annual Report on Form 10-K, the
Quarterly Report on Form 10-Q for the quarter ended March 31, 2010, and this Form 10-Q.
Environmental Matters
Environmental Regulatory Landscape
A number of regulations that could significantly impact the power generation industry are in
development or under review by the U.S. EPA: CAIR, MACT, NAAQS revisions, coal combustion
byproducts, once-through cooling, and GHG regulations. While most of these regulations have been
considered for some time, they are expected to gain clarity in 2010 through 2011. The timing and
stringency of these regulations will provide a framework for the retrofit of existing fossil plants
and deployment of new, cleaner technologies in the next decade. The Company has included capital to
meet anticipated CAIR Phase I and II, CATR, MACT standards for mercury, and the installation of
Best Technology Available under the 316(b) Rule in the current estimated environmental capital
expenditure. While the Company cannot predict the impact of future regulations and would likely
face additional investments over time, these expenditures, combined with the Companys already
existing air quality controls, use of Powder River Basin coal, closed cycle cooling, and dry ash
handling systems position NRG well to meet more stringent requirements.
The U.S. EPA released the proposed Clean Air Transport Rule, or CATR, on July 6, 2010. This
rule is designed to replace CAIR and address the findings of the D.C. Court of Appeals that
initially vacated the rule. It is designed to bring 31 states and D.C. into attainment with PM 2.5
and ozone national ambient air quality standards through emission reductions in SO2 and
NOx. Proposed implementation would be through a cap and trade program starting in 2012
with constrained trading between states in the CATR regions. In 2014 the SO2 cap would
be further reduced in certain states. Under CATR, CAIR use of discounted Acid Rain SO2
allowances would be discontinued and replaced with a completely distinct CATR SO2
allowance program. Acid Rain allowances would still be required on a 1:1 basis under the Acid Rain
Program. NRG continues to evaluate the proposed rule and any impact it has to emission markets and
currently estimates that the proposed rule, if it becomes effective, could result in up to a $50
million future impairment of the Companys SO2 emission allowance intangible assets.
NRGs planned environmental capital expenditures are consistent with reductions anticipated in the
rule.
The New York State Department of Environmental Conservation finalized the NOx RACT
Rule on July 14, 2010. This rule identifies new NOx emission limits for major sources
which must be met by July 1, 2014. Plants can comply or request an alternate Reasonably Available
Control Technology, or RACT, limit. All of NRGs facilities are able to meet the new standards
with the exception of Oswego, which will apply for an alternate limit.
On May 4, 2010, the U.S. EPA proposed two options for the regulation of coal combustion
residue, commonly known as coal ash. Under the Proposals first regulatory option, the U.S. EPA
would reverse its August 1993 and May 2000 Bevill Regulatory Determinations and list coal ash as a
special waste subject to regulation under hazardous waste regulations. The second regulatory
option would leave the Bevill Determination in place and regulate disposal of coal ash as
non-hazardous. Under both options, an exemption for the beneficial use of coal ash would remain in
place. Additionally, under both options, the U.S. EPA would establish dam safety requirements to
address the structural integrity of surface impoundments. While it is not possible to predict the
impact of this rule until it is final, as proposed it is not expected to have a material impact on
NRGs operations, as all flyash disposal sites are dry landfills; however, should the U.S. EPA
implement the hazardous waste option, NRG may incur significant costs due to loss of markets for
beneficial reuse. Given the recent release of this proposed rule, NRG will continue to monitor
developments and their respective impact on the Companys operations.
52
On May 4, 2010, the California State Water Resources Control Board adopted a statewide 316(b)
policy to mitigate once through cooling in California. Options for power plants with once through
cooling include transitioning to a closed loop system, retirement or submitting an alternative plan
that meets equivalent mitigation criteria. Specified compliance dates for NRGs El Segundo and
Encina Power Plants are December 31, 2015, and December 31, 2017, respectively. NRG is analyzing
compliance through a mix of alternative mitigation plans and repowering.
In June 2010, the U.S. EPA issued a Section 308 Information Collection Request to steam
electric power generating plants across the industry, including 13 NRG facilities. The
questionnaire focuses on water and wastewater discharges from power plants. The U.S. EPA indicated
results will be used to develop new effluent guidelines for the industry.
Finalization of the Endangerment Finding, a rule addressing tailpipe limitations for light
duty vehicles, and a final interpretation of the Johnson Memorandum set the stage for regulation of
GHGs from stationary sources. On June 3, 2010, the U.S. EPA published the final rule tailoring the
applicability criteria that determine which new and modified sources will become subject to
permitting requirements for GHGs under the Prevention of Significant Deterioration, or PSD and
Title V programs of the Clean Air Act. The rule raised applicability triggers to 75,000 or 100,000
tons per year CO2 equivalents, or CO2e, and implemented the requirements in
two phases on January 2, 2011 or July 2, 2011. The immediate impact to NRGs new and modified
facilities is not expected to be material; the Company will continue to evaluate the potential
long-term impact as regulatory programs are implemented over time.
Climate Change Legislation
In 2009, in the course of producing approximately 71 million MWh of electricity, NRGs power
plants emitted 59 million tonnes of CO2, of which 53 million tonnes were emitted in the
United States, 3 million tonnes in Germany and 3 million tonnes in Australia. During the same
period, NRG emitted approximately 8 million tons of CO2 in the RGGI region. The impact
from legislation or federal, regional or state regulation of GHGs on the Companys financial
performance will depend on a number of factors, including the overall level of GHG reductions
required under any such regulations, the price and availability of offsets, and the extent to which
NRG would be entitled to receive CO2 emissions allowances without having to purchase
them in an auction or on the open market. Thereafter, under any such legislation or regulation, the
impact on NRG would depend on the Companys level of success in developing and deploying low and no
carbon technologies such as those being pursued as discussed in the above.
Congress has been unable to come to an agreement on climate legislation during this session.
Lack of legislation will prolong the uncertainty of the nature and timing of GHG requirements and
their resulting impact on NRG.
Regulatory Matters
As operators of power plants and participants in wholesale energy markets, certain NRG
entities are subject to regulation by various federal and state government agencies. These include
the U.S. Commodity Futures Trading Commission, or CFTC, FERC, U.S. Nuclear Regulatory Commission,
or NRC, PUCT and other public utility commissions in certain states where NRGs generating or
thermal assets are located. In addition, NRG is subject to the market rules, procedures and
protocols of the various ISO markets in which it participates. Certain of the Reliant Energy
entities are competitive Retail Electric Providers, or REPs, and as such are subject to the rules
and regulations of the PUCT governing REPs. NRG must also comply with the mandatory reliability
requirements imposed by the North American Electric Reliability Corporation, or NERC, and the
regional reliability councils in the regions where the Company operates. The operations of, and
wholesale electric sales from, NRGs Texas region are not subject to rate regulation by the FERC,
as they are deemed to operate solely within the ERCOT market and not in interstate commerce.
Financial
Reform On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform
and Consumer Protection Act, or the Dodd-Frank Act, which, among other things, aims to improve
transparency and accountability in derivative markets. While the Dodd-Frank Act increases the
CFTCs regulatory authority over over-the-counter derivatives, there is uncertainty on several
issues related to market clearing, definitions of market participants, reporting, and capital
requirements. Thus, while many details remain to be addressed in CFTC rulemaking proceedings, at
this time the Company does not anticipate any material impact to its current hedging collateral
strategy. NRGs view is informed by a letter dated June 30, 2010 from Senate Banking Committee
Chairman Dodd and Senate Agriculture Committee Chairman Lincoln clarifying that the legislative
intent of the Dodd-Frank Act is not to impose margin requirements on end users that use swaps to
hedge or mitigate commercial risks.
53
New England On February 22, 2010, ISO-NE filed proposed amendments to its Forward Capacity
Market, or FCM, design with FERC. A number of generators protested the ISO-NE filing, arguing that
FERC should not accept the proposed amendments. On March 23, 2010, an association of generators
filed a complaint alleging that the proposed FCM amendments are not just and reasonable due to
market distortions such as out-of-market contracts, and thus would continue to under-compensate
capacity suppliers in New England. On April 2, 2010, NRG and PSEG jointly filed a second complaint
alleging that the existing FCM market fails to adequately establish zonal prices and thus does not
adequately compensate suppliers for the locational value of their capacity. These complaints are
seeking only prospective relief. Any changes to the FCM market in response to these complaints
could benefit from the Companys existing New England assets in future FCM auctions. On April 23,
2010, FERC issued an order consolidating the proceedings. In its order, FERC accepted some of the
ISO-NEs proposed changes, but also set several of the central issues for hearing and settlement
processes.
California On May 4, 2010, the U.S. Court of Appeals for the D.C. Circuit in Southern
California Edison Company v. FERC vacated FERCs acceptance of station power rules for the CAISO
market, and remanded the case for further proceedings at FERC. As a result of the courts
decision, NRGs power plants may be prevented from netting their station power consumption against
their sales on a monthly basis in the California markets, which could require NRG to purchase
station power at retail rates. Additionally, the precedent announced in this case may affect
station power tariffs in other markets.
Changes in Accounting Standards
See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1
for a discussion of recent accounting developments.
54
Consolidated Results of Operations
The following table provides selected financial information for the Company:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
Change % |
|
2010 |
|
2009 |
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
605 |
|
|
$ |
725 |
|
|
|
(17 |
)% |
|
$ |
1,283 |
|
|
$ |
1,612 |
|
|
|
(20 |
)% |
Capacity revenue |
|
|
206 |
|
|
|
253 |
|
|
|
(19 |
) |
|
|
417 |
|
|
|
513 |
|
|
|
(19 |
) |
Retail revenue |
|
|
1,341 |
|
|
|
1,250 |
|
|
|
7 |
|
|
|
2,586 |
|
|
|
1,250 |
|
|
|
107 |
|
Risk management activities |
|
|
(2 |
) |
|
|
(12 |
) |
|
|
83 |
|
|
|
89 |
|
|
|
425 |
|
|
|
(79 |
) |
Contract amortization |
|
|
(52 |
) |
|
|
(53 |
) |
|
|
2 |
|
|
|
(114 |
) |
|
|
(32 |
) |
|
|
(256 |
) |
Thermal revenue |
|
|
20 |
|
|
|
21 |
|
|
|
(5 |
) |
|
|
48 |
|
|
|
55 |
|
|
|
(13 |
) |
Other revenues |
|
|
15 |
|
|
|
53 |
|
|
|
(72 |
) |
|
|
39 |
|
|
|
72 |
|
|
|
(46 |
) |
|
Total operating revenues |
|
|
2,133 |
|
|
|
2,237 |
|
|
|
(5 |
) |
|
|
4,348 |
|
|
|
3,895 |
|
|
|
12 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
1,129 |
|
|
|
1,175 |
|
|
|
(4 |
) |
|
|
2,318 |
|
|
|
1,628 |
|
|
|
42 |
|
Risk management activities |
|
|
(84 |
) |
|
|
(204 |
) |
|
|
59 |
|
|
|
51 |
|
|
|
(136 |
) |
|
|
138 |
|
Other cost of operations |
|
|
284 |
|
|
|
271 |
|
|
|
5 |
|
|
|
599 |
|
|
|
516 |
|
|
|
16 |
|
|
Total cost of operations |
|
|
1,329 |
|
|
|
1,242 |
|
|
|
7 |
|
|
|
2,968 |
|
|
|
2,008 |
|
|
|
48 |
|
Depreciation and amortization |
|
|
208 |
|
|
|
213 |
|
|
|
(2 |
) |
|
|
410 |
|
|
|
382 |
|
|
|
7 |
|
Selling, general and administrative |
|
|
139 |
|
|
|
131 |
|
|
|
6 |
|
|
|
269 |
|
|
|
214 |
|
|
|
26 |
|
Acquisition-related transaction and
integration costs |
|
|
|
|
|
|
23 |
|
|
|
(100 |
) |
|
|
|
|
|
|
35 |
|
|
|
(100 |
) |
Development costs |
|
|
13 |
|
|
|
9 |
|
|
|
44 |
|
|
|
22 |
|
|
|
22 |
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,689 |
|
|
|
1,618 |
|
|
|
4 |
|
|
|
3,669 |
|
|
|
2,661 |
|
|
|
38 |
|
Gain on sale of assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
444 |
|
|
|
619 |
|
|
|
(28 |
) |
|
|
702 |
|
|
|
1,234 |
|
|
|
(43 |
) |
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated
affiliates |
|
|
11 |
|
|
|
5 |
|
|
|
120 |
|
|
|
25 |
|
|
|
27 |
|
|
|
(7 |
) |
Gain on sale of equity method
investments |
|
|
|
|
|
|
128 |
|
|
|
(100 |
) |
|
|
|
|
|
|
128 |
|
|
|
(100 |
) |
Other income/(expense), net |
|
|
19 |
|
|
|
(11 |
) |
|
|
273 |
|
|
|
23 |
|
|
|
(14 |
) |
|
|
264 |
|
Interest expense |
|
|
(147 |
) |
|
|
(159 |
) |
|
|
(8 |
) |
|
|
(300 |
) |
|
|
(297 |
) |
|
|
1 |
|
|
Total other expense |
|
|
(117 |
) |
|
|
(37 |
) |
|
|
216 |
|
|
|
(252 |
) |
|
|
(156 |
) |
|
|
62 |
|
|
Income before income tax expense |
|
|
327 |
|
|
|
582 |
|
|
|
(44 |
) |
|
|
450 |
|
|
|
1,078 |
|
|
|
(58 |
) |
Income tax expense |
|
|
117 |
|
|
|
150 |
|
|
|
(22 |
) |
|
|
182 |
|
|
|
448 |
|
|
|
(59 |
) |
|
Net Income |
|
|
210 |
|
|
|
432 |
|
|
|
(51 |
) |
|
|
268 |
|
|
|
630 |
|
|
|
(57 |
) |
|
Less: Net loss attributable to
noncontrolling interest |
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
Net income attributable to NRG Energy,
Inc. |
|
$ |
211 |
|
|
$ |
433 |
|
|
|
(51 |
) |
|
$ |
269 |
|
|
$ |
631 |
|
|
|
(57 |
) |
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub
($/MMBtu) |
|
|
4.09 |
|
|
|
3.68 |
|
|
|
11 |
% |
|
|
4.69 |
|
|
|
4.13 |
|
|
|
14 |
% |
|
55
Managements discussion of the results of operations for the three months ended June 30, 2010, and 2009:
The table below represents the results of NRG excluding the impact of Reliant Energy, and
adjusted for intercompany transactions between Reliant Energy and the Texas region, during the
three months ended June 30, 2010, and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
|
|
|
|
Reliant |
|
|
|
|
|
Total excluding |
|
|
|
|
|
Reliant |
|
|
|
|
|
Total excluding |
(In millions) |
|
Consolidated |
|
Energy |
|
Eliminations |
|
Reliant Energy |
|
Consolidated |
|
Energy(a) |
|
Eliminations |
|
Reliant Energy |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
605 |
|
|
$ |
|
|
|
$ |
284 |
|
|
$ |
889 |
|
|
$ |
725 |
|
|
$ |
|
|
|
$ |
54 |
|
|
$ |
779 |
|
Capacity revenue |
|
|
206 |
|
|
|
|
|
|
|
3 |
|
|
|
209 |
|
|
|
253 |
|
|
|
|
|
|
|
11 |
|
|
|
264 |
|
Retail revenue |
|
|
1,341 |
|
|
|
1,341 |
|
|
|
|
|
|
|
|
|
|
|
1,250 |
|
|
|
1,250 |
|
|
|
|
|
|
|
|
|
Risk management
activities |
|
|
(2 |
) |
|
|
|
|
|
|
(19 |
) |
|
|
(21 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
2 |
|
|
|
(10 |
) |
Contract amortization |
|
|
(52 |
) |
|
|
(59 |
) |
|
|
|
|
|
|
7 |
|
|
|
(53 |
) |
|
|
(75 |
) |
|
|
|
|
|
|
22 |
|
Thermal revenue |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
20 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
Other revenues |
|
|
15 |
|
|
|
|
|
|
|
13 |
|
|
|
28 |
|
|
|
53 |
|
|
|
|
|
|
|
2 |
|
|
|
55 |
|
|
Total operating
revenues |
|
|
2,133 |
|
|
|
1,282 |
|
|
|
281 |
|
|
|
1,132 |
|
|
|
2,237 |
|
|
|
1,175 |
|
|
|
69 |
|
|
|
1,131 |
|
Operating Costs and
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
1,129 |
|
|
|
937 |
|
|
|
300 |
|
|
|
492 |
|
|
|
1,175 |
|
|
|
803 |
|
|
|
71 |
|
|
|
443 |
|
Risk management
activities |
|
|
(84 |
) |
|
|
(76 |
) |
|
|
(19 |
) |
|
|
(27 |
) |
|
|
(204 |
) |
|
|
(189 |
) |
|
|
(2 |
) |
|
|
(17 |
) |
Other operating costs |
|
|
284 |
|
|
|
49 |
|
|
|
|
|
|
|
235 |
|
|
|
271 |
|
|
|
41 |
|
|
|
|
|
|
|
230 |
|
|
Total cost of
operations |
|
|
1,329 |
|
|
|
910 |
|
|
|
281 |
|
|
|
700 |
|
|
|
1,242 |
|
|
|
655 |
|
|
|
69 |
|
|
|
656 |
|
Depreciation and
amortization |
|
|
208 |
|
|
|
29 |
|
|
|
|
|
|
|
179 |
|
|
|
213 |
|
|
|
43 |
|
|
|
|
|
|
|
170 |
|
Selling, general and
administrative |
|
|
139 |
|
|
|
64 |
|
|
|
|
|
|
|
75 |
|
|
|
131 |
|
|
|
49 |
|
|
|
|
|
|
|
82 |
|
Acquisition-related
transaction and
integration costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
23 |
|
Development costs |
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
Total operating
costs and
expenses |
|
|
1,689 |
|
|
|
1,003 |
|
|
|
281 |
|
|
|
967 |
|
|
|
1,618 |
|
|
|
747 |
|
|
|
69 |
|
|
|
940 |
|
|
Operating income |
|
$ |
444 |
|
|
$ |
279 |
|
|
$ |
|
|
|
$ |
165 |
|
|
$ |
619 |
|
|
$ |
428 |
|
|
$ |
|
|
|
$ |
191 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
Operating Revenues
Operating revenues, excluding risk management activities, decreased by $114 million during the
three months ended June 30, 2010, compared to the same period in 2009.
|
|
|
Retail revenue increased by $91 million. This increase was driven by $354 million of
revenue for the month of April included in 2010, which was offset by a decrease of $263
million from Mass, C&I and supply management revenues during the two month period ended June
30 2010, as compared to 2009. Mass revenues decreased by $143 million due to 12% lower
revenue rates and 8% lower volumes due to fewer customers. C&I revenues decreased by $86
million due to 17% lower volumes driven by fewer customers. |
|
|
|
|
Energy revenue including intercompany revenue, increased $110 million during the three
months ended June 30, 2010, compared to the same period in 2009: |
|
o |
|
Texas increased by $64 million with $66 million increase driven by higher energy
prices and an increase in margin on megawatt hours sold from market purchases of $12
million, offset by a $13 million decrease driven by reduction in generation. The average
realized energy price increased by 11%, driven by a 14% increase in merchant prices and a
3% increase in contract prices. Intercompany sales to Reliant Energy, which eliminate in
consolidation, were $284 million, an increase of $230 million over the two month period
in 2009. Generation decreased by 2%, driven by an 18% decrease in nuclear plant
generation and a 6% decrease in gas plant generation. The decrease in nuclear plant
generation is due to an STP Unit 2 spring refueling outage in 2010. These decreases were
offset by an increase in wind farm generation as Langford began commercial operation in
December 2009. |
56
|
o |
|
Northeast increased by $36 million, with $32 million driven by higher energy
prices and $4 million driven by 3% higher generation. Merchant energy prices were higher
by an average of 50%. The increase in oil and gas generation is attributable to higher
reliability run hours at the Connecticut plants. |
|
|
o |
|
South Central increased by $15 million due to a $19 million increase in contract
revenue offset by a decrease of $4 million in merchant energy revenues. The increase in
contract energy price was driven by a $6 million increase in fuel cost pass-through from
the cooperatives and a $12 million increase due to a new contract with a regional
municipality. Total megawatt hour sales to the regions contract customers were up 13%
while the average realized price on contract energy sales was $27.77 per MWh in 2010
compared to $22.98 per MWh in 2009. Megawatt hours sold to the merchant market increased
by 26% but lower realized merchant prices resulted in a decrease of $4 million. |
|
|
|
Capacity revenue including intercompany revenue, decreased $55 million during the three
months ended June 30, 2010, compared to the same period in 2009: |
|
o |
|
Texas decreased by $42 million resulting from a lower proportion of baseload
contracts which contain a capacity component. Intercompany sales to Reliant Energy,
which eliminate in consolidation, decreased by $8 million. |
|
|
o |
|
South Central decreased by $7 million primarily due to expiration of a capacity
agreement with a regional utility. |
|
|
|
Contract amortization revenue decreased by $1 million during the three months ended
June 30, 2010, as compared to the same period in 2009. The contract amortization expense
decreased by $16 million at Reliant Energy offset by a $15 million reduction in contract
amortization revenue in the Texas region due to the lower volume of contracted energy. |
|
|
|
Other revenues decreased by $38 million during the three months ended June 30, 2010, as
compared to the same period in 2009, driven by $7 million in lower emissions revenues and a
$31 million non-cash gain related to the settlement of pre-existing in-the-money contracts
with Reliant Energy recognized in 2009. The Texas regions intercompany ancillary sales to
Reliant Energy, which eliminate in consolidation, were $13 million, an increase of $12
million over the two month period in 2009. |
Cost of Operations
Cost of operations, excluding risk management activities, decreased by $33 million during the
three months ended June 30, 2010, compared to the same period in 2009.
|
|
|
Cost of sales including intercompany purchases, decreased $46 million during the three
months ended June 30, 2010, compared to the same period in 2009 due to: |
|
o |
|
Retail increased by $134 million, with $280 million of costs for the month of
April included in 2010. This increase was offset by a $151 million decrease in supply
costs and by a $26 million decrease in transmission and distribution charges for the two
month period ended June 30, 2010, as compared to 2009. Intercompany purchases from the
Texas region, which eliminate in consolidation, were $300 million, an increase of $229
million over the two month period in 2009. |
|
|
o |
|
Texas increased $25 million due to higher coal costs and ancillary services
costs offset by a decrease in natural gas costs and purchased energy. Coal costs
increased $23 million due to higher transportation charges. |
|
|
o |
|
Northeast increased $24 million driven by a $13 million increase in natural gas
and oil costs, an $8 million increase in purchased energy and a $4 million increase in
coal costs. Natural gas and oil costs increased due to 20% higher generation and 37%
higher average natural gas prices. Purchased energy increased due to costs to supply new
load contracts which commenced on June 1, 2010. Coal costs increased due to 52% higher
average prices offset by 1% lower coal generation. |
|
|
|
Other costs of operations increased $13 million during the three months ended June 30,
2010, compared to the same period in 2009. Maintenance expenses in the Texas and South
Central regions increased by $24 million due to planned baseload outages which was offset by
a decrease of $16 million in the Northeast region due to lower property tax expense and lower
operations and maintenance expenses. |
57
Risk Management Activities
Risk management activities include economic hedges that did not qualify for cash flow hedge
accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains
decreased by $110 million during the three months ended June 30, 2010, compared to the same period
in 2009. The breakdown of changes by region are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions |
|
$ |
(88 |
) |
|
$ |
69 |
|
|
$ |
44 |
|
|
$ |
(8 |
) |
|
$ |
1 |
|
|
$ |
2 |
|
|
$ |
|
|
|
$ |
20 |
|
|
Mark-to-market gains/(losses) |
|
|
163 |
|
|
|
(57 |
) |
|
|
(55 |
) |
|
|
10 |
|
|
|
2 |
|
|
|
(1 |
) |
|
|
|
|
|
|
62 |
|
|
Total derivative gains/(losses) included in
revenues and cost of operations |
|
$ |
75 |
|
|
$ |
12 |
|
|
$ |
(11 |
) |
|
$ |
2 |
|
|
$ |
3 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions |
|
$ |
(114 |
) |
|
$ |
101 |
|
|
$ |
95 |
|
|
$ |
(5 |
) |
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
77 |
|
|
Mark-to-market gains/(losses) |
|
|
303 |
|
|
|
(144 |
) |
|
|
(34 |
) |
|
|
(15 |
) |
|
|
7 |
|
|
|
(2 |
) |
|
|
|
|
|
|
115 |
|
|
Total derivative gains/(losses) included in
revenues and cost of operations |
|
$ |
189 |
|
|
$ |
(43 |
) |
|
$ |
61 |
|
|
$ |
(20 |
) |
|
$ |
6 |
|
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
192 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
The breakdown of gains and losses included in revenue and cost of operations by region
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination (a) |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions, or
financial income in revenues |
|
$ |
|
|
|
$ |
70 |
|
|
$ |
44 |
|
|
$ |
(8 |
) |
|
$ |
1 |
|
|
$ |
2 |
|
|
$ |
(28 |
) |
|
$ |
81 |
|
|
Mark-to-market results in revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized
(gains)/losses on settled positions related to
economic hedges |
|
|
|
|
|
|
(16 |
) |
|
|
(34 |
) |
|
|
1 |
|
|
|
|
|
|
|
(1 |
) |
|
|
2 |
|
|
|
(48 |
) |
Reversal of previously recognized unrealized losses
on settled positions related to trading activity |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Net unrealized (losses)/gains on open positions
related to economic hedges |
|
|
|
|
|
|
(66 |
) |
|
|
(28 |
) |
|
|
(4 |
) |
|
|
1 |
|
|
|
|
|
|
|
45 |
|
|
|
(52 |
) |
Net unrealized gains on open positions related to
trading activity |
|
|
|
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
Subtotal mark-to-market results |
|
|
|
|
|
|
(73 |
) |
|
|
(59 |
) |
|
|
1 |
|
|
|
2 |
|
|
|
(1 |
) |
|
|
47 |
|
|
|
(83 |
) |
|
Total derivative (losses)/gains included in revenues |
|
$ |
|
|
|
$ |
(3 |
) |
|
$ |
(15 |
) |
|
$ |
(7 |
) |
|
$ |
3 |
|
|
$ |
1 |
|
|
$ |
19 |
|
|
$ |
(2 |
) |
|
|
|
|
(a) |
|
Represents the elimination of $19 million intercompany loss in the Texas region. The
offsetting intercompany gain is included in cost of operations in the Reliant Energy region. |
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination(b) |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions, or
financial income in revenues |
|
$ |
|
|
|
$ |
105 |
|
|
$ |
96 |
|
|
$ |
(2 |
) |
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
199 |
|
|
Mark-to-market results in revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains
on settled positions related to economic hedges |
|
|
|
|
|
|
(16 |
) |
|
|
(32 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(49 |
) |
Reversal of previously recognized unrealized gains
on settled positions related to trading activity |
|
|
|
|
|
|
(14 |
) |
|
|
(9 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
Net unrealized (losses)/gains on open positions
related to economic hedges |
|
|
|
|
|
|
(119 |
) |
|
|
(9 |
) |
|
|
(4 |
) |
|
|
7 |
|
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(128 |
) |
Net unrealized (losses)/gains on open positions
related to trading activity |
|
|
|
|
|
|
(10 |
) |
|
|
5 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
Subtotal mark-to-market results |
|
|
|
|
|
|
(159 |
) |
|
|
(45 |
) |
|
|
(10 |
) |
|
|
7 |
|
|
|
(2 |
) |
|
|
(2 |
) |
|
|
(211 |
) |
|
Total derivative (losses)/gains included in revenues |
|
$ |
|
|
|
$ |
(54 |
) |
|
$ |
51 |
|
|
$ |
(12 |
) |
|
$ |
6 |
|
|
$ |
(1 |
) |
|
$ |
(2 |
) |
|
$ |
(12 |
) |
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Represents the elimination of $2 million intercompany gain in the Texas region. The
offsetting intercompany loss is included in cost of operations in the
Reliant Energy region. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
Elimination(a) |
|
Total |
|
|
(In millions) |
Net (losses)/gains on settled positions, or financial
expense in cost of operations |
|
$ |
(88 |
) |
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
28 |
|
|
$ |
(61 |
) |
|
Mark-to-market results in cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized (gains)/losses
on settled positions related to economic hedges |
|
|
(17 |
) |
|
|
8 |
|
|
|
4 |
|
|
|
4 |
|
|
|
(2 |
) |
|
|
(3 |
) |
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009 |
|
|
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
60 |
|
Net unrealized gains/(losses) on open positions related to
economic hedges |
|
|
120 |
|
|
|
8 |
|
|
|
|
|
|
|
5 |
|
|
|
(45 |
) |
|
|
88 |
|
|
Subtotal mark-to-market results |
|
|
163 |
|
|
|
16 |
|
|
|
4 |
|
|
|
9 |
|
|
|
(47 |
) |
|
|
145 |
|
|
Total derivative gains/(losses) included in cost of operations |
|
$ |
75 |
|
|
$ |
15 |
|
|
$ |
4 |
|
|
$ |
9 |
|
|
$ |
(19 |
) |
|
$ |
84 |
|
|
|
|
|
(a) |
|
Represents the elimination of $19 million intercompany gains in the Reliant Energy region.
The offsetting intercompany loss is included in revenue in the Texas
region. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
Elimination(b) |
|
Total |
|
|
(In millions) |
Net losses on settled positions, or financial expense in
cost of operations |
|
$ |
(114 |
) |
|
$ |
(4 |
) |
|
$ |
(1 |
) |
|
$ |
(3 |
) |
|
$ |
|
|
|
$ |
(122 |
) |
|
Mark-to-market results in cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized losses on
settled positions related to economic hedges |
|
|
|
|
|
|
12 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
31 |
|
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009 |
|
|
210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210 |
|
Net unrealized gains/(losses) on open positions related to
economic hedges |
|
|
93 |
|
|
|
3 |
|
|
|
(8 |
) |
|
|
(5 |
) |
|
|
2 |
|
|
|
85 |
|
|
Subtotal mark-to-market results |
|
|
303 |
|
|
|
15 |
|
|
|
11 |
|
|
|
(5 |
) |
|
|
2 |
|
|
|
326 |
|
|
Total derivative gains/(losses) included in cost of operations |
|
$ |
189 |
|
|
$ |
11 |
|
|
$ |
10 |
|
|
$ |
(8 |
) |
|
$ |
2 |
|
|
$ |
204 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the
period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Represents the elimination of $2 million intercompany loss in the Reliant Energy region. The
offsetting intercompany gain is included in revenue in the Texas
region. |
59
For the three months ended June 30, 2010, the $52 million loss in revenue from economic
hedge positions is primarily driven by a decrease in value of forward sales of natural gas and
electricity due to an increase in forward power and gas prices. The $88 million gain in cost of
energy from economic hedge positions is primarily driven by an increase in value of forward
purchases of natural gas, electricity and fuel due to an increase in forward power and gas prices.
Reliant Energys $60 million gain from the roll-off of acquired derivatives consists of loss
positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The
roll-off amounts were offset by realized losses at the settled prices and higher costs of physical
power which are reflected in cost of operations during the same period.
For the period ended June 30, 2009, the $128 million mark-to-market loss in revenue related to
a decrease in value in forward sales of electricity and fuel relating to economic hedges due to an
increase in forward power and gas prices. The $85 million mark-to-market gain in expense related
to economic hedges was due to an increase in forward purchases of electricity and natural gas
relating to retail supply, due to an increase in forward power and gas prices.
In accordance with ASC 815, the following table represents the results of the Companys
financial and physical trading of energy commodities for the three months ended June 30, 2010, and
2009. The realized financial trading results and unrealized financial and physical trading results
are included in the risk management activities above, while the realized physical trading results
are included in energy revenue. The Companys trading activities are subject to limits within the
Companys Risk Management Policy.
|
|
|
|
|
|
|
|
|
|
|
Three months |
|
|
ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
Trading gains/(losses)
|
|
|
|
|
|
|
|
|
Realized |
|
$ |
(13 |
) |
|
$ |
26 |
|
Unrealized |
|
|
17 |
|
|
|
(34 |
) |
|
Total trading gains/(losses) |
|
$ |
4 |
|
|
$ |
(8 |
) |
|
Depreciation and Amortization
NRGs depreciation and amortization expense decreased by $5 million for the three months ended
June 30, 2010, compared to the same period in 2009. Depreciation and amortization expense for
Reliant Energy decreased by $14 million mainly due to reduction in amortization of customer
relationships. This decrease was offset by a $9 million increase in depreciation related to
baghouse projects in western New York, Cedar Bayou 4 project which began operations in June 2009
and Langford which began commercial operations in December 2009.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $8 million during the three months
ended June 30, 2010, compared to the same period in 2009. The increase was due to:
|
|
|
Retail selling, general and administrative expense increased by $15 million due to
inclusion of month of April in 2010. |
This increase was offset by:
|
|
|
Consultant costs decreased due to $5 million non-recurring costs related to Exelons
exchange offer and proxy contest efforts incurred in 2009. |
Acquisition-related Transaction and Integration Costs
NRG incurred Reliant Energy acquisition-related transaction and integration costs of $23
million for the three months ended June 30, 2009. These integration efforts were completed by the
end of 2009.
60
Equity in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates increased by $6 million during the three
months ended June 30, 2010, compared to the same period in 2009, primarily from an increase in
equity earnings from Sherbino.
Gain on Sale of Equity Method Investments
NRGs gain on sale of equity method investments in 2009 represents a $128 million gain on the
sale of NRGs 50% ownership interest in MIBRAG.
Other Income/(Expense), Net
NRGs other income/(expense), net increased $30 million during the three months ended June 30,
2010, compared to the same period in 2009. The 2010 amount includes $3 million and $9 million of
unrealized and realized foreign exchange gains, respectively. The 2009 amount includes a $15
million loss on a forward contract for foreign currency executed to hedge the MIBRAG sale proceeds.
Interest Expense
NRGs interest expense decreased by $12 million during the three months ended June 30, 2010,
compared to the same period in 2009. This decrease was due to $7 million related to the settlement
of the CSF Debt in 2009 and early 2010, a $12 million decrease in fees on the CSRA facility, a $4
million decrease due to a lower outstanding principal balance on the Term Loan Facility, and $2
million due to lower interest rates related to the unhedged portion of the Term Loan. These
decreases were offset by a $10 million increase in interest expense related to the issuance of the
2019 Senior Notes in June 2009.
Income Tax Expense
NRGs income tax expense decreased by $33 million during the three months ended June 30, 2010,
compared to the same period in 2009. The decrease in income tax expense was primarily due to a
decrease in income. The effective tax rate was 35.8% and 25.8% for the three months ended June 30,
2010, and 2009, respectively.
For the three months ended June 30, 2010, NRGs overall effective tax rate was different than
the statutory rate of 35% primarily due to state and local income taxes as well as recording
federal and state tax expense and interest for unrecognized tax benefits. For the three months
ended June 30, 2009, NRGs effective tax rate was different than the statutory rate of 35%
primarily due to a net state and local income tax benefit as a result of the Reliant Energy
acquisition, and the sale of the MIBRAG facility.
61
Managements discussion of the results of operations for the six months ended June 30, 2010, and 2009:
The table below represents the results of NRG excluding the impact of Reliant Energy, and
adjusted for intercompany transactions between Reliant Energy and the Texas region, during the six
months ended June 30, 2010 and 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2010 |
|
2009 |
|
|
|
|
|
|
Reliant |
|
|
|
|
|
Total excluding |
|
|
|
|
|
Reliant |
|
|
|
|
|
Total excluding |
(In millions) |
|
Consolidated |
|
Energy |
|
Eliminations |
|
Reliant Energy |
|
Consolidated |
|
Energy(a) |
|
Eliminations |
|
Reliant Energy |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
1,283 |
|
|
$ |
|
|
|
$ |
484 |
|
|
$ |
1,767 |
|
|
$ |
1,612 |
|
|
$ |
|
|
|
$ |
54 |
|
|
$ |
1,666 |
|
Capacity revenue |
|
|
417 |
|
|
|
|
|
|
|
7 |
|
|
|
424 |
|
|
|
513 |
|
|
|
|
|
|
|
11 |
|
|
|
524 |
|
Retail revenue |
|
|
2,586 |
|
|
|
2,586 |
|
|
|
|
|
|
|
|
|
|
|
1,250 |
|
|
|
1,250 |
|
|
|
|
|
|
|
|
|
Risk management
activities |
|
|
89 |
|
|
|
|
|
|
|
125 |
|
|
|
214 |
|
|
|
425 |
|
|
|
|
|
|
|
2 |
|
|
|
427 |
|
Contract amortization |
|
|
(114 |
) |
|
|
(128 |
) |
|
|
|
|
|
|
14 |
|
|
|
(32 |
) |
|
|
(75 |
) |
|
|
|
|
|
|
43 |
|
Thermal revenue |
|
|
48 |
|
|
|
|
|
|
|
|
|
|
|
48 |
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
55 |
|
Other revenues |
|
|
39 |
|
|
|
|
|
|
|
26 |
|
|
|
65 |
|
|
|
72 |
|
|
|
|
|
|
|
2 |
|
|
|
74 |
|
|
Total operating
revenues |
|
|
4,348 |
|
|
|
2,458 |
|
|
|
642 |
|
|
|
2,532 |
|
|
|
3,895 |
|
|
|
1,175 |
|
|
|
69 |
|
|
|
2,789 |
|
Operating Costs and
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales |
|
|
2,318 |
|
|
|
1,843 |
|
|
|
516 |
|
|
|
991 |
|
|
|
1,628 |
|
|
|
803 |
|
|
|
71 |
|
|
|
896 |
|
Risk management
activities |
|
|
51 |
|
|
|
248 |
|
|
|
125 |
|
|
|
(72 |
) |
|
|
(136 |
) |
|
|
(189 |
) |
|
|
(2 |
) |
|
|
51 |
|
Other operating costs |
|
|
599 |
|
|
|
94 |
|
|
|
1 |
|
|
|
506 |
|
|
|
516 |
|
|
|
41 |
|
|
|
|
|
|
|
475 |
|
|
Total cost of
operations |
|
|
2,968 |
|
|
|
2,185 |
|
|
|
642 |
|
|
|
1,425 |
|
|
|
2,008 |
|
|
|
655 |
|
|
|
69 |
|
|
|
1,422 |
|
Depreciation and
amortization |
|
|
410 |
|
|
|
59 |
|
|
|
|
|
|
|
351 |
|
|
|
382 |
|
|
|
43 |
|
|
|
|
|
|
|
339 |
|
Selling, general and
administrative |
|
|
269 |
|
|
|
122 |
|
|
|
|
|
|
|
147 |
|
|
|
214 |
|
|
|
49 |
|
|
|
|
|
|
|
165 |
|
Acquisition-related
transaction and
integration costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
35 |
|
Development costs |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
22 |
|
|
Total operating
costs and expenses |
|
|
3,669 |
|
|
|
2,366 |
|
|
|
642 |
|
|
|
1,945 |
|
|
|
2,661 |
|
|
|
747 |
|
|
|
69 |
|
|
|
1,983 |
|
|
Gain on sale of assets |
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
702 |
|
|
$ |
92 |
|
|
$ |
|
|
|
$ |
610 |
|
|
$ |
1,234 |
|
|
$ |
428 |
|
|
$ |
|
|
|
$ |
806 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
Operating Revenues
Operating revenues, excluding risk management activities, increased $789 million during the
six months ended June 30, 2010, compared to the same period in 2009.
|
|
|
Retail revenue for the six months ended June 30, 2010, were $2.6 billion consisting of
$1.5 billion in Mass revenues and $991 million in C&I revenues. Retail revenues for the two
months ended 2009 were $1.3 billion consisting of $761 million in Mass revenues and $437
million in C&I revenues. |
|
|
|
|
Energy revenue including intercompany revenue, increased $101 million during the six
months ended June 30, 2010, compared to the same period in
2009: |
|
o |
|
Texas increased by $98 million, with $56 million driven by higher energy prices,
$10 million driven by margin on megawatt hours sold from market purchases and $31 million
driven by an increase in generation. The average realized energy price increased by 5%,
driven by a 1% increase in merchant prices and a 3% increase in contract prices.
Intercompany sales to Reliant Energy, which eliminate in consolidation, were $484
million, an increase of $430 million over the two month period in 2009. Generation
increased by 3%, driven by a 17% increase in gas plant generation and an increase in wind
farm generation. Wind farm generation increased due to Langford, which began commercial
operations in December 2009, and leased wind farm generation, which increased due to four
additional months included in 2010. These increases were offset by a 13% decrease in
nuclear plant generation due to planned outages. |
62
|
o |
|
Northeast decreased by $24 million, with $7 million driven by lower energy
prices, $13 million driven by a reduction in generation, and $12 million of margin on a
load contract which expired in May 2009, offset by an $8 million increase driven by new
load-serving contracts, which commenced June 1, 2010. Merchant energy prices were lower
by an average of 4%. Generation decreased by 5%, with a 19% decrease in oil and gas
generation and a 2% decrease in coal generation. The decline in oil and gas generation
is attributable to both planned and forced outages at Arthur Kill, Middletown and Oswego
in 2010, offset by an increase due to higher reliability run hours at the Connecticut
plants. |
|
|
o |
|
South Central increased by $25 million due to a $31 million increase in contract
revenue offset by a $6 million decrease in merchant energy revenues. Of the $31 million
increase, $18 million is attributable to the regions cooperative customers. Also
contributing to the increase in contract revenue was $12 million due to a new contract
with a regional municipality. Average realized price on contract energy sales was down
$1.75 per MWh in 2010 compared to 2009. Megawatt hours sold to the merchant market
decreased by 5%. |
|
|
|
Capacity revenue including intercompany revenue, decreased $100 million during the six
months ended June 30, 2010, compared to the same period in
2009: |
|
o |
|
Texas decreased by $82 million due to a lower proportion of baseload contracts
which contain a capacity component. Intercompany sales to Reliant Energy, which eliminate
in consolidation, decreased by $4 million. |
|
|
o |
|
Northeast increased by $8 million, due to a $21 million increase in capacity
revenue in the NYISO and PJM markets driven by higher prices offset by a $13 million
decrease in NEPOOL capacity driven by the expiration of RMR contracts for Montville,
Middletown and Norwalk in 2010. |
|
|
o |
|
South Central decreased by $18 million due to the expiration of a capacity
agreement with a regional utility. |
|
|
o |
|
West decreased by $7 million due to reduced resource adequacy and call option
contract sales at El Segundo in 2010 compared to 2009. |
|
|
|
Contract amortization revenue decreased by $82 million during the six months ended June
30, 2010, as compared to the same period in 2009. The decrease includes $52 million of
amortization revenue for net in-market C&I contracts related to the Reliant Energy
acquisition in May 2009 and a reduction of $28 million in amortization revenue in the Texas
region due to the lower volume of contracted energy. |
|
|
|
|
Other revenues decreased by $33 million during the six months ended June 30, 2010, as
compared to the same period in 2009. The decrease was driven by $14 million in lower
emissions revenues in 2010 and a $31 million non-cash gain related to the settlement of
pre-existing in-the-money contracts with Reliant Energy recognized in 2009. These decreases
were offset by a $9 million increase in ancillary revenue. The Texas regions intercompany
ancillary sales to Reliant Energy, which eliminate in consolidation, were $25 million, an
increase of $24 million over the two month period in 2009. |
Cost of Operations
Cost of operations, excluding risk management activities, increased $773 million during the
six months ended June 30, 2010, compared to the same period in 2009.
|
|
|
Cost of sales including intercompany purchases, increased $690 million during the six
months ended June 30, 2010, compared to the same period in 2009
due to: |
|
o |
|
Retail Cost of energy for the six months ended June 30, 2010, was $1.8 billion
consisting of $1.2 billion in supply costs and $634 million in transmission and
distribution charges. Cost of energy for the two months ended June 30, 2009 was $803
million consisting of $550 million in supply costs and $267 million in transmission and
distribution charges. Intercompany purchases from the Texas region, which eliminate in
consolidation, were $516 million, an increase of $445 million over the two month period
in 2009. |
63
|
o |
|
Texas increased $98 million due to higher coal and natural gas costs, ancillary
services costs and purchased energy. Coal costs increased by $40 million due to a $30
million increase in transportation cost, and a $15 million due to higher prices offset by
a $9 million decrease due to reduced generation. Natural gas costs increased $22
million, reflecting a 23% increase in average natural gas per MMBtu prices and a 17%
increase in gas-fired generation. Ancillary service costs increased by $18 million due
to an increase in purchased ancillary costs incurred to meet contract obligations.
Purchased energy increased by $14 million due to a higher average price and a greater
number of megawatt hours purchased to meet obligations when baseload plants are not
available. |
|
|
o |
|
South Central increased by $10 million due to an $11 million increase in
purchased energy offset by $4 million decrease in coal costs due to a 1% reduction in
coal generation. |
|
|
|
Other costs of operations increased $83 million during the six months ended June 30,
2010, compared to the same period in 2009. Other costs of operations for Reliant Energy
increased by $53 million due to the additional four months included in 2010. Also,
maintenance expenses in the Texas and South Central regions increased by $42 million due to
planned baseload outages offset by a $17 million decrease in the Northeast region mainly due
to lower spending at the Indian River and Arthur Kill plants, which completed a major outage
project in the second quarter of 2009. |
Risk Management Activities
Risk management activities include economic hedges that did not qualify for cash flow hedge
accounting, ineffectiveness on cash flow hedges, and trading activities. Total derivative gains
decreased by $523 million during the six months ended June 30, 2010, compared to the same period in
2009. The breakdown of changes by region follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination |
|
Total |
|
|
(In millions) |
Net (losses)/gains on settled positions |
|
$ |
(123 |
) |
|
$ |
77 |
|
|
$ |
77 |
|
|
$ |
(21 |
) |
|
$ |
1 |
|
|
$ |
3 |
|
|
$ |
|
|
|
$ |
14 |
|
Mark-to-market (losses)/gains |
|
|
(125 |
) |
|
|
170 |
|
|
|
(30 |
) |
|
|
8 |
|
|
|
3 |
|
|
|
(2 |
) |
|
|
|
|
|
|
24 |
|
|
Total derivative (losses)/gains included in
revenues and cost of operations |
|
$ |
(248 |
) |
|
$ |
247 |
|
|
$ |
47 |
|
|
$ |
(13 |
) |
|
$ |
4 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination |
|
Total |
|
|
(In millions) |
Net (losses)/gains on settled positions |
|
$ |
(114 |
) |
|
$ |
130 |
|
|
$ |
151 |
|
|
$ |
5 |
|
|
$ |
(3 |
) |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
171 |
|
Mark-to-market gains/(losses) |
|
|
303 |
|
|
|
25 |
|
|
|
97 |
|
|
|
(40 |
) |
|
|
6 |
|
|
|
(1 |
) |
|
|
|
|
|
|
390 |
|
|
Total derivative gains/(losses) included in
revenues and cost of operations |
|
$ |
189 |
|
|
$ |
155 |
|
|
$ |
248 |
|
|
$ |
(35 |
) |
|
$ |
3 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
561 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the period May 1, 2009, to June 30, 2009. |
64
The breakdown of gains and losses included in revenue and cost of operations by region
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination(a) |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions, or
financial income in revenues |
|
$ |
|
|
|
$ |
79 |
|
|
$ |
77 |
|
|
$ |
(20 |
) |
|
$ |
1 |
|
|
$ |
3 |
|
|
$ |
(37 |
) |
|
$ |
103 |
|
|
Mark-to-market results in revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized
(gains)/losses on settled positions related to
economic hedges |
|
|
|
|
|
|
(53 |
) |
|
|
(58 |
) |
|
|
1 |
|
|
|
|
|
|
|
(2 |
) |
|
|
(9 |
) |
|
|
(121 |
) |
Reversal of previously recognized unrealized losses
on settled positions related to trading activity |
|
|
|
|
|
|
20 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Net unrealized gains/(losses) on open positions
related to economic hedges |
|
|
|
|
|
|
156 |
|
|
|
2 |
|
|
|
(22 |
) |
|
|
1 |
|
|
|
|
|
|
|
(79 |
) |
|
|
58 |
|
Net unrealized gains on open positions related to
trading activity |
|
|
|
|
|
|
7 |
|
|
|
8 |
|
|
|
6 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
Subtotal mark-to-market results |
|
|
|
|
|
|
130 |
|
|
|
(45 |
) |
|
|
(12 |
) |
|
|
3 |
|
|
|
(2 |
) |
|
|
(88 |
) |
|
|
(14 |
) |
|
Total derivative gains/(losses) included in revenues |
|
$ |
|
|
|
$ |
209 |
|
|
$ |
32 |
|
|
$ |
(32 |
) |
|
$ |
4 |
|
|
$ |
1 |
|
|
$ |
(125 |
) |
|
$ |
89 |
|
|
|
|
|
(a) |
|
Represents the elimination of $125 million intercompany gain in the Texas region. The
offsetting intercompany loss is included in cost of operations in the
Reliant Energy region. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
Thermal |
|
Elimination(b) |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions, or
financial income in revenues |
|
$ |
|
|
|
$ |
143 |
|
|
$ |
156 |
|
|
$ |
11 |
|
|
$ |
(3 |
) |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
309 |
|
|
Mark-to-market results in revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains
on settled positions related to economic hedges |
|
|
|
|
|
|
(37 |
) |
|
|
(63 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
(102 |
) |
Reversal of previously recognized unrealized gains
on settled positions related to trading activity |
|
|
|
|
|
|
(43 |
) |
|
|
(23 |
) |
|
|
(38 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(104 |
) |
Net unrealized gains/(losses) on open positions
related to economic hedges |
|
|
|
|
|
|
154 |
|
|
|
159 |
|
|
|
(4 |
) |
|
|
6 |
|
|
|
1 |
|
|
|
(2 |
) |
|
|
314 |
|
Net unrealized gains/(losses) on open positions
related to trading activity |
|
|
|
|
|
|
(8 |
) |
|
|
4 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
Subtotal mark-to-market results |
|
|
|
|
|
|
66 |
|
|
|
77 |
|
|
|
(30 |
) |
|
|
6 |
|
|
|
(1 |
) |
|
|
(2 |
) |
|
|
116 |
|
|
Total derivative gains/(losses) included in revenues |
|
$ |
|
|
|
$ |
209 |
|
|
$ |
233 |
|
|
$ |
(19 |
) |
|
$ |
3 |
|
|
$ |
1 |
|
|
$ |
(2 |
) |
|
$ |
425 |
|
|
|
|
|
(a) |
|
Reliant Energy results
are for the period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Represents the elimination of $2 million intercompany gain in the Texas region. The
offsetting intercompany loss is included in cost of operations in the
Reliant Energy region. |
65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2010 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Energy |
|
Texas |
|
Northeast |
|
Central |
|
Elimination(a) |
|
Total |
|
|
(In millions) |
Net gains/(losses) on settled positions, or financial
expense in cost of operations |
|
$ |
(123 |
) |
|
$ |
(2 |
) |
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
37 |
|
|
$ |
(89 |
) |
|
Mark-to-market results in cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized (gains)/losses
on settled positions related to economic hedges |
|
|
(20 |
) |
|
|
23 |
|
|
|
9 |
|
|
|
9 |
|
|
|
9 |
|
|
|
30 |
|
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009 |
|
|
150 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
150 |
|
Net unrealized gains/(losses) on open positions related to
economic hedges |
|
|
(255 |
) |
|
|
17 |
|
|
|
6 |
|
|
|
11 |
|
|
|
79 |
|
|
|
(142 |
) |
|
Subtotal mark-to-market results |
|
|
(125 |
) |
|
|
40 |
|
|
|
15 |
|
|
|
20 |
|
|
|
88 |
|
|
|
38 |
|
|
Total derivative (losses)/gains included in cost of operations |
|
$ |
(248 |
) |
|
$ |
38 |
|
|
$ |
15 |
|
|
$ |
19 |
|
|
$ |
125 |
|
|
$ |
(51 |
) |
|
|
|
|
(a) |
|
Represents the elimination of $125 million intercompany loss in the Reliant Energy region.
The offsetting intercompany gain is included in revenue in the Texas region. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Energy(a) |
|
Texas |
|
Northeast |
|
Central |
|
Elimination(b) |
|
Total |
|
|
(In millions) |
Net losses on settled positions, or financial expense in
cost of operations |
|
$ |
(114 |
) |
|
$ |
(13 |
) |
|
$ |
(5 |
) |
|
$ |
(6 |
) |
|
$ |
|
|
|
$ |
(138 |
) |
|
Mark-to-market results in cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized losses on
settled positions related to economic hedges |
|
|
|
|
|
|
25 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
68 |
|
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009 |
|
|
210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
210 |
|
Net unrealized gains/(losses) on open positions related to
economic hedges |
|
|
93 |
|
|
|
(66 |
) |
|
|
(23 |
) |
|
|
(10 |
) |
|
|
2 |
|
|
|
(4 |
) |
|
Subtotal mark-to-market results |
|
|
303 |
|
|
|
(41 |
) |
|
|
20 |
|
|
|
(10 |
) |
|
|
2 |
|
|
|
274 |
|
|
Total derivative gains/(losses) included in cost of operations |
|
$ |
189 |
|
|
$ |
(54 |
) |
|
$ |
15 |
|
|
$ |
(16 |
) |
|
$ |
2 |
|
|
$ |
136 |
|
|
|
|
|
(a) |
|
Reliant Energy results are for the
period May 1, 2009, to June 30, 2009. |
|
(b) |
|
Represents the elimination of $2 million intercompany loss in the Reliant Energy region. The
offsetting intercompany gain is included in revenue in the Texas region.
|
For the six months ended June 30, 2010, the $58 million gain in revenue from economic
hedge positions is primarily driven by an increase in value of forward sales of natural gas and
electricity due to a decrease in forward power and gas prices. The $142 million loss in cost of
energy from economic hedge positions is primarily driven by a decrease in value of forward
purchases of natural gas, electricity and fuel due to a decrease in forward power and gas prices.
Reliant Energys $150 million gain from the roll-off of acquired derivatives consists of loss
positions that were acquired as of May 1, 2009, and valued using forward prices on that date. The
roll-off amounts were offset by realized losses at the settled prices and higher costs of physical
power which are reflected in cost of operations during the same period.
In accordance with ASC 815, the following table represents the results of the Companys
financial and physical trading of energy commodities for the six months ended June 30, 2010, and
2009. The realized financial trading results and unrealized financial and physical trading results
are included in the risk management activities above, while the realized physical trading results
are included in energy revenue. The Companys trading activities are subject to limits within the
Companys Risk Management Policy.
|
|
|
|
|
|
|
|
|
|
|
Six months |
|
|
ended June 30, |
(In millions) |
|
2010 |
|
2009 |
|
Trading gains/(losses)
|
|
|
|
|
|
|
|
|
Realized |
|
$ |
(24 |
) |
|
$ |
96 |
|
Unrealized |
|
|
49 |
|
|
|
(96 |
) |
|
Total trading gains/(losses) |
|
$ |
25 |
|
|
$ |
|
|
|
66
Depreciation and Amortization
NRGs depreciation and amortization expense increased by $28 million during the six months
ended June 30, 2010, compared to the same period in 2009. Reliant Energys depreciation and
amortization expense for the six month period increased by $16 million due to the inclusion of four
additional months in 2010. The balance of the increase was due to depreciation on the baghouse
projects in western New York, Cedar Bayou 4, which began commercial operation in June 2009, and
Langford, which began commercial operation in December 2009.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $55 million during the six months
ended June 30, 2010, compared to the same period in 2009. The increase was due to:
|
|
|
Retail selling, general and administrative expense increased by $73 million due to the
inclusion of four additional months in 2010. |
These increases were offset by
|
|
|
Labor costs
decreased by $15 million offset by higher contractor expense
of $5 million. |
|
|
|
|
Consultant costs decreased by $9 million due to non-recurring costs related to Exelons
exchange offer and proxy contest efforts incurred in 2009. |
Acquisition-related Transaction and Integration Costs
NRG incurred Reliant Energy acquisition-related transaction and integration costs of $35
million for 2009.
Gain on Sale of Assets
On January 11, 2010, NRG sold Padoma to Enel, recognizing a gain on sale of $23 million.
Equity in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates decreased by $2 million during the six
months ended June 30, 2010, compared to the same period in 2009. In 2009, NRG recognized $15
million from MIBRAG, which was sold in June 2009. This decrease was partially offset by a $13
million increase from Sherbino in 2010.
Gain on Sale of Equity Method Investments
NRGs gain on sale of equity method investments in 2009 represents a $128 million gain on the
sale of NRGs 50% ownership interest in MIBRAG.
Other Income/(Expense), Net
NRGs other income/(expense), net increased $37 million during the six months ended June 30,
2010, compared to the same period in 2009. The 2010 amount includes $3 million and $9 million of
unrealized and realized foreign exchange gains, respectively. The 2009 amount includes a $24
million loss on a forward contract for foreign currency executed to hedge the MIBRAG sale proceeds.
67
Interest Expense
NRGs interest expense increased $3 million during the six months ended June 30, 2010,
compared to the same period in 2009. This increase was due to $25 million related to the issuance
of the 2019 Senior Notes in June 2009. This increase was offset by a $14 million decrease due to
the settlement of the CSF Debt in 2009 and early 2010 and a $7 million decrease due to a lower
outstanding principal balance on the Term Loan Facility and a $2 million decrease due to lower
interest rates related to the unhedged portion of the Term Loan.
Income Tax Expense
NRGs income tax expense decreased by $266 million during the six months ended June 30, 2010,
compared to the same period in 2009. The decrease in income tax expense was primarily due to a
decrease in income. The effective tax rate was 40.4% and 41.5% for the six months ended June 30,
2010, and 2009, respectively.
For the six months ended June 30, 2010, NRGs overall effective tax rate was different than
the statutory rate of 35% primarily due to state and local income taxes as well as recording
federal and state tax expense and interest for unrecognized tax benefits. For the six months ended
June 30, 2009, NRGs overall effective tax rate was different than the statutory rate of 35%
primarily due to an increase in valuation allowance as a result of capital losses generated in the
six month period for which there are no projected capital gains or available tax planning
strategies. Furthermore, the effective tax rate is decreased by the sale of the MIBRAG facility as
well as a net state and local income tax benefit as a result of the Reliant Energy acquisition.
68
Results of Operations Regional Discussions
The following is a detailed discussion of the results of operations of NRGs retail business
segment.
Reliant Energy
Quarterly Results
For a discussion of the business profile of the Companys Reliant Energy operations, see pages
94-96 of NRG Energy, Inc.s 2009 Annual Report on Form 10-K.
Selected Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months |
|
|
|
|
|
Two months |
|
Two months |
|
|
|
|
ended |
|
One month ended |
|
ended |
|
ended |
|
|
(In millions except otherwise noted) |
|
June 30, 2010 |
|
April 30, 2010 |
|
June 30, 2010 |
|
June 30, 2009(c) |
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mass revenues |
|
$ |
808 |
|
|
$ |
190 |
|
|
$ |
618 |
|
|
$ |
761 |
|
|
|
(19 |
)% |
Commercial and Industrial revenues |
|
|
502 |
|
|
|
151 |
|
|
|
351 |
|
|
|
437 |
|
|
|
(20 |
) |
Supply management revenues |
|
|
31 |
|
|
|
13 |
|
|
|
18 |
|
|
|
52 |
|
|
|
(65 |
) |
Contract amortization |
|
|
(59 |
) |
|
|
(22 |
) |
|
|
(37 |
) |
|
|
(75 |
) |
|
|
51 |
|
|
Total operating revenues |
|
|
1,282 |
|
|
|
332 |
|
|
|
950 |
|
|
|
1,175 |
|
|
|
(19 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management
activities) |
|
|
861 |
|
|
|
239 |
|
|
|
622 |
|
|
|
614 |
|
|
|
1 |
|
Other operating expenses |
|
|
113 |
|
|
|
37 |
|
|
|
76 |
|
|
|
90 |
|
|
|
(16 |
) |
Depreciation and amortization |
|
|
29 |
|
|
|
9 |
|
|
|
20 |
|
|
|
43 |
|
|
|
(53 |
) |
|
Operating Income |
|
$ |
279 |
|
|
$ |
47 |
|
|
$ |
232 |
|
|
$ |
428 |
|
|
|
(46 |
) |
Electricity sales volume GWh |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mass |
|
|
5,732 |
|
|
|
1,275 |
|
|
|
4,457 |
|
|
|
4,851 |
|
|
|
(8 |
) |
Commercial and Industrial (a) |
|
|
6,683 |
|
|
|
2,059 |
|
|
|
4,624 |
|
|
|
5,580 |
|
|
|
(17 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average retail customer count (in
thousands, metered locations) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mass |
|
|
1,503 |
|
|
|
1,513 |
|
|
|
1,499 |
|
|
|
1,601 |
|
|
|
(6 |
) |
Commercial and Industrial (a) |
|
|
63 |
|
|
|
63 |
|
|
|
63 |
|
|
|
71 |
|
|
|
(11 |
) |
Retail customer count (in thousands,
metered locations) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mass |
|
|
1,488 |
|
|
|
1,513 |
|
|
|
1,488 |
|
|
|
1,589 |
|
|
|
(6 |
) |
Commercial and Industrial (a) |
|
|
63 |
|
|
|
63 |
|
|
|
63 |
|
|
|
68 |
|
|
|
(7 |
) |
Cooling Degree Days, or CDDs (b) |
|
|
1,163 |
|
|
|
149 |
|
|
|
1,014 |
|
|
|
971 |
|
|
|
4 |
% |
Heating Degree Days, or HDDs (b) |
|
|
26 |
|
|
|
25 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
(a) |
|
Includes customers of the Texas General Land Office, for whom the Company provides
services. |
|
(b) |
|
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. The
CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT
market in which Reliant Energy serves its customer base. |
|
(c) |
|
For the period May 1, 2009, to June 30, 2009. |
69
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months |
|
One month |
|
Two months |
|
Two months |
|
|
|
|
ended |
|
ended |
|
ended |
|
ended |
|
|
(In millions except otherwise noted) |
|
June 30, 2010 |
|
April 30, 2010 |
|
June 30, 2010 |
|
June 30, 2009(b) |
|
Change % |
|
Reliant Energy Operating Income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mass revenues |
|
$ |
808 |
|
|
$ |
190 |
|
|
$ |
618 |
|
|
$ |
761 |
|
|
|
(19 |
)% |
Commercial and Industrial revenues |
|
|
502 |
|
|
|
151 |
|
|
|
351 |
|
|
|
437 |
|
|
|
(20 |
) |
Supply management revenues |
|
|
31 |
|
|
|
13 |
|
|
|
18 |
|
|
|
52 |
|
|
|
(65 |
) |
|
Total retail operating revenues (a) |
|
|
1,341 |
|
|
|
354 |
|
|
|
987 |
|
|
|
1,250 |
|
|
|
(21 |
) |
|
Retail cost of sales (a) |
|
|
1,033 |
|
|
|
280 |
|
|
|
753 |
|
|
|
930 |
|
|
|
(19 |
) |
|
Total retail gross margin |
|
|
308 |
|
|
|
74 |
|
|
|
234 |
|
|
|
320 |
|
|
|
(27 |
) |
Mark-to-market results on energy supply
derivatives |
|
|
163 |
|
|
|
39 |
|
|
|
124 |
|
|
|
303 |
|
|
|
(59 |
) |
Contract amortization, net |
|
|
(50 |
) |
|
|
(20 |
) |
|
|
(30 |
) |
|
|
(62 |
) |
|
|
(52 |
) |
Other operating expenses |
|
|
(113 |
) |
|
|
(37 |
) |
|
|
(76 |
) |
|
|
(90 |
) |
|
|
(16 |
) |
Depreciation and amortization |
|
|
(29 |
) |
|
|
(9 |
) |
|
|
(20 |
) |
|
|
(43 |
) |
|
|
(53 |
) |
|
Operating Income |
|
$ |
279 |
|
|
$ |
47 |
|
|
$ |
232 |
|
|
$ |
428 |
|
|
|
(46 |
)% |
|
|
|
|
(a) |
|
Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract
amortization. |
|
(b) |
|
For the period May 1, 2009, to June 30, 2009. |
|
|
|
Gross margin excluding April 2010 gross margin of $74 million, Reliant Energys
gross margin decreased by $86 million for May and June. This decrease was primarily due to
22% lower Mass margins driven by price reductions for certain customer classes and lower
unit margins on acquisitions, renewals, and conversions from month-to-month to fixed priced
contracts. In addition, Mass volumes sold were 8% lower due to fewer customers.
Competition, lower unit margins on acquisitions and renewals and supply costs based on
forward market prices, could drive lower gross margin in the
future. |
Operating Income
For the three months ended June 30, 2010 as compared to two months ended June 30, 2009,
operating income decreased by $149 million, or $196 million excluding the one month ended April 30,
2010, due to:
Operating Revenues
Total operating revenues increased by $107 million during the three months ended June 30,
2010, as compared to the two months ended June 30, 2009, or decreased by $225 million excluding the
one month ended April 30, 2010, due to:
|
|
|
Mass revenues excluding April 2010 revenues of $190 million, Mass revenues decreased
by $143 million for May and June. This decrease was primarily due to 12% lower revenue
rates driven by Reliant Energy price reductions for certain customer classes and lower
revenue pricing on acquisitions, renewals, and conversions from month-to-month to fixed
priced contracts consistent with competitive offers. Reliant Energy also experienced 8%
lower volumes due to fewer customers driven by 0.6% monthly net attrition between July 2009
and June 2010 from increased competition. Favorable weather in both periods resulted in 11%
higher customer usage in 2010 and 9% in 2009 when compared to
ten-year normal weather. |
|
|
|
|
Commercial and Industrial revenue excluding April 2010 revenues of $151 million, C&I
revenues decreased by $86 million for May and June. This decrease was due to 17% lower
volumes primarily driven by fewer customers due to lower renewals and acquisitions and 4%
lower revenue rates primarily driven by lower prices on fixed priced renewals due to lower
natural gas prices at the time of the renewals. |
70
Cost of Energy
Cost of energy increased by $247 million for the three months ended June 30, 2010, as compared
to the two months ended June 30, 2009, or $8 million excluding the one month ended April 30, 2010,
due to:
|
|
|
Supply costs excluding April 2010 supply costs of $187 million, supply costs decreased
by $151 million for May and June due to 12% lower volumes in 2010 versus 2009 primarily
driven by fewer customers. Supply rates also decreased by 12% due to lower unit prices of
purchased power at the time of procurement and favorable impacts of $14 million for out of
market supply contracts terminated in the fourth quarter of 2009 in conjunction with the
CSRA unwind. The terminated contract value for April 2010 was
$7 million. |
|
|
|
|
Transmission and distribution charges excluding April 2010 transmission and
distribution charges of $93 million, transmission and distribution charges decreased by $26
million for May and June due to lower volumes transported and sold to customers in 2010
versus 2009. The lower volumes were primarily driven by fewer
customers in 2010. |
|
|
|
|
Risk management activities decreased $114 million as $75 million of gains were
recorded for the three months ended June 30, 2010 compared to $189 million of gains recorded
in the same period in 2009. The $75 million of gains in 2010 consisted of unrealized gains
of $163 million, offset by $88 million of realized losses on settled transactions, compared
to $303 million of unrealized gains offset by $114 million of realized losses on settled
transactions in the same period in 2009. Please refer to the Consolidated Results of
Operations to this Form 10-Q for a more complete description of movements in risk management
activities. |
Other Operating Expenses
Other operating expenses increased by $23 million for the three months ended June 30, 2010, as
compared to the two months ended June 30, 2009. Excluding April 2010 expense of $37 million, other
operating expenses decreased by $14 million primarily due to lower labor and related costs of $8
million, lower advertising and marketing costs of $5 million, and lower gross receipts taxes of $3
million, offset by other cost increases of $2 million.
71
Year to date Results
Selected Income Statement Data
|
|
|
|
|
|
|
Six months ended |
(In millions except otherwise noted) |
|
June 30, 2010 |
|
Operating Revenues |
|
|
|
|
Mass revenues |
|
$ |
1,521 |
|
Commercial and Industrial revenues |
|
|
991 |
|
Supply management revenues |
|
|
74 |
|
Contract amortization |
|
|
(128 |
) |
|
Total operating revenues |
|
|
2,458 |
|
Operating Costs and Expenses |
|
|
|
|
Cost of energy (including risk management activities) |
|
|
2,091 |
|
Other operating expenses |
|
|
216 |
|
Depreciation and amortization |
|
|
59 |
|
|
Operating Income |
|
$ |
92 |
|
Electricity sales volume GWh |
|
|
|
|
Mass |
|
|
10,546 |
|
Commercial and Industrial (a) |
|
|
12,892 |
|
Business Metrics |
|
|
|
|
Weighted average retail customers count (in thousands, metered locations) |
|
|
|
|
Mass |
|
|
1,512 |
|
Commercial and Industrial (a) |
|
|
64 |
|
Retail customers count (in thousands, metered locations) |
|
|
|
|
Mass |
|
|
1,488 |
|
Commercial and Industrial (a) |
|
|
63 |
|
Cooling Degree Days, or CDDs (b) |
|
|
1,180 |
|
Heating Degree Days, or HDDs (b) |
|
|
1,268 |
|
|
|
|
|
(a) |
|
Includes customers of the Texas General Land Office, for whom the Company provides
services. |
|
(b) |
|
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. The
CDDs/HDDs amounts are representative of the Coast and North Central Zones within the ERCOT
market in which Reliant Energy serves its customer base. |
72
|
|
|
|
|
|
|
Six months ended |
(In millions) |
|
June 30, 2010 |
|
Reliant Energy Operating Income: |
|
|
|
|
Mass revenues |
|
$ |
1,521 |
|
Commercial and industrial revenues |
|
|
991 |
|
Supply management revenues |
|
|
74 |
|
|
Total retail operating revenues (a) |
|
|
2,586 |
|
|
Retail cost of sales (a) |
|
|
1,985 |
|
|
Total retail gross margin |
|
|
601 |
|
Mark-to-market results on energy supply derivatives |
|
|
(125 |
) |
Contract amortization, net |
|
|
(109 |
) |
Other operating expenses |
|
|
(216 |
) |
Depreciation and amortization |
|
|
(59 |
) |
|
Operating Income |
|
$ |
92 |
|
|
|
|
|
(a) |
|
Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract
amortization. |
|
|
|
Gross margin Reliant Energys gross margin totaled $601 million for the six
months ended June 30, 2010. Higher Mass volumes were driven by favorable weather partially
offset a reduction in volumes due to fewer customers driven by 0.4% monthly net attrition
between January 2010 and June 2010. In addition, Mass unit margins decreased during the
period due to lower margins on acquisitions and renewals driven by competition. A
continuation of these factors could drive lower gross margin in the
future. |
Operating Income
Operating income for the six months ended June 30, 2010, was $92 million, which consisted of the
following:
Operating Revenues
Total operating revenues for the six months ended June 30, 2010, were $2.6 billion and
consisted of the following:
|
|
|
Mass revenues totaled $1.5 billion for the period from retail electric sales to
approximately 1.5 million end use customers in the Texas market. Favorable weather, when
compared to ten-year normal weather, resulted in 11% higher usage per customer. However,
customer counts declined by 2% during the period. The average Mass revenue rate declined
during the period due to lower revenue pricing on acquisitions, renewals and conversions
from month-to-month to fixed price contracts consistent with competitive offers. |
|
|
|
|
Commercial and Industrial revenue totaled $991 million for the period on volume sales
of approximately 12,892 GWh. Variable rate contracts tied to the market price of natural
gas accounted for approximately 45% of the contracted volumes as of June 30, 2010. |
Cost of Energy
Cost of energy for the six months ended June 30, 2010, was $2.1 billion and consisted of the
following:
|
|
|
Supply costs and financial costs of energy totaled $1.4 billion for the period.
Energy is procured for fixed price term contracts at the time the sales contracts are
executed. For month-to-month customers, the power is purchased at current market prices.
Favorable weather caused an increase in purchased supply volumes during the period. The
supply costs were favorably impacted by $48 million of out-of-market supply contracts
terminated in the fourth quarter of 2009 in conjunction with the CSRA unwind. |
|
|
|
|
Transmission and distribution charges totaled $634 million for the period for the cost
to transport power from the generation sources to the end use customers. |
73
|
|
|
Risk management activities decreased $437 million as losses of $248 million were
reported for the six months ended June 30, 2010 compared to $189 million of gains during the
same period in 2009. The $248 million of losses in 2010 consisted of $125 million of
mark-to-market losses and $123 million of realized losses on settled transactions, compared
to $303 million of mark-to-market gains offset by $114 million of realized losses on settled
transactions in the same period in 2009. Please refer to the Consolidated Results of
Operations to this Form 10-Q for a more complete description of movements in risk management
activities. |
Other Operating Expenses
Other operating expenses for the six months ended June 30, 2010, were $216 million, or 9% of
Reliant Energys total operating revenues. Other operating expenses consisted of the following:
|
|
|
Selling, general and administrative expenses totaled $100 million for the period.
Total direct costs were $86 million, which primarily consisted of the costs of labor and
external costs associated with advertising and other marketing activities, as well as human
resources, community activities, legal, procurement, regulatory, accounting, internal audit,
and management, as well as facilities leases and other office expenses. Indirect costs
related to corporate allocations were $14 million. |
|
|
|
|
Operations and maintenance expenses totaled $61 million for the six months ended June
30, 2010. These expenses primarily consisted of the labor and external costs associated
with customer activities, including the call center, billing, remittance processing, and
credit and collections, as well as the information technology costs associated with those
activities. |
|
|
|
|
Gross receipts tax totaled $33 million for the period or 1.3% of Mass and C&I
revenues. |
|
|
|
|
Bad debt expense totaled $22 million for the period or 0.9% of Mass and C&I revenues.
During the period, Reliant Energy experienced improved customer
payment behavior. |
74
Results of Operations for Wholesale Power Generation Regions
The following is a detailed discussion of the results of operations of NRGs major wholesale
power generation business segments.
Texas Region
For a discussion of the business profile of the Companys Texas operations, see pages 97-101
of NRG Energy, Inc.s 2009 Annual Report on Form 10-K.
Selected Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
Change % |
|
2010 |
|
2009 |
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
664 |
|
|
$ |
600 |
|
|
|
11 |
% |
|
$ |
1,292 |
|
|
$ |
1,194 |
|
|
|
8 |
% |
Capacity revenue |
|
|
5 |
|
|
|
47 |
|
|
|
(89 |
) |
|
|
12 |
|
|
|
94 |
|
|
|
(87 |
) |
Risk management activities |
|
|
(3 |
) |
|
|
(54 |
) |
|
|
94 |
|
|
|
209 |
|
|
|
209 |
|
|
|
|
|
Contract amortization |
|
|
2 |
|
|
|
17 |
|
|
|
(88 |
) |
|
|
4 |
|
|
|
32 |
|
|
|
(88 |
) |
Other revenues |
|
|
24 |
|
|
|
9 |
|
|
|
167 |
|
|
|
45 |
|
|
|
15 |
|
|
|
200 |
|
|
Total operating revenues |
|
|
692 |
|
|
|
619 |
|
|
|
12 |
|
|
|
1,562 |
|
|
|
1,544 |
|
|
|
1 |
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk
management activities) |
|
|
260 |
|
|
|
236 |
|
|
|
10 |
|
|
|
480 |
|
|
|
474 |
|
|
|
1 |
|
Other operating expenses |
|
|
168 |
|
|
|
154 |
|
|
|
9 |
|
|
|
350 |
|
|
|
322 |
|
|
|
9 |
|
Depreciation and amortization |
|
|
124 |
|
|
|
117 |
|
|
|
6 |
|
|
|
241 |
|
|
|
234 |
|
|
|
3 |
|
|
Operating Income |
|
$ |
140 |
|
|
$ |
112 |
|
|
|
25 |
|
|
$ |
491 |
|
|
$ |
514 |
|
|
|
(4 |
) |
MWh sold (in thousands) |
|
|
11,963 |
|
|
|
12,333 |
|
|
|
(3 |
) |
|
|
22,842 |
|
|
|
22,506 |
|
|
|
1 |
|
MWh generated (in thousands) |
|
|
11,444 |
|
|
|
11,919 |
|
|
|
(4 |
) |
|
|
21,870 |
|
|
|
21,992 |
|
|
|
(1 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power
prices ($/MWh) |
|
|
39.30 |
|
|
|
38.55 |
|
|
|
2 |
|
|
|
40.58 |
|
|
|
35.57 |
|
|
|
14 |
|
Cooling Degree Days, or CDDs
(a) |
|
|
1,004 |
|
|
|
982 |
|
|
|
2 |
|
|
|
1,026 |
|
|
|
1,108 |
|
|
|
(7 |
) |
CDDs 30 year average |
|
|
854 |
|
|
|
854 |
|
|
|
|
|
|
|
948 |
|
|
|
948 |
|
|
|
|
|
Heating Degree Days, or HDDs
(a) |
|
|
79 |
|
|
|
100 |
|
|
|
(21 |
)% |
|
|
1,464 |
|
|
|
1,003 |
|
|
|
46 |
% |
HDDs 30 year average |
|
|
83 |
|
|
|
83 |
|
|
|
|
|
|
|
1,205 |
|
|
|
1,205 |
|
|
|
|
|
|
|
|
|
(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 $28 million for the three months ended June 30, 2010, compared
to the same period in 2009, primarily due to an increase in net risk management activities of $55
million and an increase of $22 million driven by higher energy revenues and offset by an increase
in the cost of energy of $26 million driven by increased coal costs.
75
Operating Revenues
Total operating revenues increased by $73 million during the three months ended June 30, 2010,
compared to the same period in 2009, due to:
|
|
|
Risk management activities decreased $51 million as losses of $3 million were reported
for the three months ended June 30, 2010, compared to losses of $54 million in the same
period in 2009. The $3 million of losses in 2010 included $73 million of unrealized
mark-to-market losses and $70 million in settled gains, or financial income, compared to $159
million in unrealized derivative losses and $105 million of settled financial gains in the
same period in 2009. Please refer to the Consolidated Results of Operations to this Form
10-Q for a more complete description of movements in risk management
activities. |
|
|
|
|
Energy revenues increased
$64 million due to: |
|
o |
|
Energy prices increased by $66 million for the three months ended June 30, 2010
compared to the same period 2009. The average realized energy price increased by 11%,
driven by a 14% increase in merchant prices and a 3% increase in
contract prices. |
|
|
o |
|
Generation decreased by 2% resulting in a $13 million decrease in sales volume.
This decrease was driven by a 1% decrease in coal plant generation due to increased
planned maintenance hours in 2010, an 18% decrease in nuclear plant generation due to a
planned maintenance outage on Unit 2, and a 6% decrease in gas plant generation. These
decreases were offset by an increase in owned and leased wind farm generation, as
Langford began commercial operations in December 2009. |
|
|
o |
|
Margin on MWh sold from market purchases increased by $12 million for the three
months ended June 30, 2010. |
|
|
|
Capacity revenue decreased by $42 million due to a lower proportion of baseload
contracts which contain a capacity component. |
|
|
|
|
Contract amortization revenue decreased by $15 million due to the reduced volume of
contracted energy in 2010 as compared to 2009. |
|
|
|
|
Other revenue increased by $15 million primarily due to higher ancillary services
revenue of $17 million offset by a decrease of $2 million in physical sales of natural gas
and coal. |
Cost of Energy
Cost of energy increased by $24 million during the three months ended June 30, 2010, compared
to the same period in 2009, due to:
|
|
|
Coal costs increased by
$23 million due to higher cost of transportation. |
|
|
|
|
Ancillary services costs increased by $6 million due to an increase in purchased
ancillary services costs incurred to meet obligations. |
|
|
These increases were offset by: |
|
|
|
|
Natural gas costs decreased by $2 million due to a 6% decrease in gas-fired generation
offset by a 26% increase in average natural gas prices. |
|
|
|
|
Purchased energy decreased $2 million due to lower cost of purchases per MWh to meet
obligations when baseload plants are unavailable, including a decrease of $8 million from
ERCOT congestion and out-of-merit purchases offset by bilateral and toll energy purchases of
$6 million. |
76
|
|
|
Fuel risk management activities increased $4 million as gains of $15 million were
recorded for the three months ending June 30, 2010, compared to gains of $11 million during
the same period in 2009. The gains of $15 million in 2010 included $16 million of unrealized
mark-to-market gains offset by $1 million of losses on settled transactions, compared to $15
million of unrealized mark-to-market gains offset by $4 million in losses on settled
transactions, or financial cost of energy, in the same period in 2009. Please refer to the
Consolidated Results of Operations to this Form 10-Q for a more complete description of
movements in risk management activities. |
Other Operating Expenses
Other operating expenses increased by $14 million during the three months ended June 30, 2010,
compared to the same period in 2009, driven by increases in operations and maintenance expense of
$11 million due to baseload outages, general and administrative expense of $2 million, and
development costs of $1 million.
Year to date results
Operating Income
Operating income decreased by $23 million for the six months ended June 30, 2010, compared to
the same period in 2009, primarily due to an increase in the cost of energy of $98 million driven
by higher fuel and purchased energy costs and higher operations and maintenance costs of $26
million due to baseload outages, offset by an increase in net risk management activities of $92
million.
Operating Revenues
Total operating revenues increased by $18 million during the six months ended June 30, 2010,
compared to the same period in 2009, due to:
|
|
|
Energy revenues
increased $98 million due to: |
|
o |
|
Energy prices increased by $56 million for the six months ended June 30, 2010
compared to the same period 2009. The average realized energy price increased by 5%,
driven by a 1% increase in merchant prices and a 3% increase in
contract prices. |
|
|
o |
|
Generation increased by 3% resulting in a $31 million increase in sales volume.
This increase was driven by a 17% increase in gas plant generation and an increase in
owned and leased wind farm generation, offset by a 13% decrease in nuclear plant
generation due to planned and maintenance outages. Wind farm generation increased due to
Langford, which began commercial operations in
December 2009. |
|
|
o |
|
Margin on MWh sold from market purchases increased by $10 million for the
period. |
|
|
|
Capacity revenue decreased by $82 million due to a lower proportion of baseload
contracts which contain a capacity component. |
|
|
|
|
Contract amortization revenue decreased by $28 million due to the reduced volume of
contracted energy in 2010 as compared to 2009. |
|
|
|
|
Other revenue increased by $30 million due to higher ancillary services revenue of $33
million, higher maintenance services revenue of $3 million, and an increase of $2 million in
physical sales of natural gas and coal. This increase was offset by $8 million lower
emissions credit revenue. |
77
Cost of Energy
Cost of energy increased by $6 million during the six months ended June 30, 2010, compared to
the same period in 2009, due to:
|
|
|
Coal costs increased by $40 million due to higher cost of transportation for WA Parish
of $30 million, higher Limestone coal and lignite costs of $12 million, and increased lignite
royalty and other costs of $3 million. These increases were offset by reduced generation of
$9 million. |
|
|
|
|
Natural gas costs increased by $22 million due to a 17% increase in gas-fired
generation and a 23% increase in average natural gas prices. |
|
|
|
|
Ancillary services costs increased by $18 million due to an increase in purchased
ancillary services costs incurred to meet obligations. |
|
|
|
|
Purchased energy increased $14 million due to $15 million higher volume and cost of
purchases per MWh to meet obligations when baseload plants are unavailable, including a
decrease of $9 million from ERCOT congestion and out-of-merit purchases offset by bilateral
and toll energy purchases of $8 million. |
|
|
|
|
Emissions amortization amortization of emissions credits increased $6 million due to
the increased number of
SO2
credits required by federal rules. |
|
|
|
|
ERCOT nodal fees increased $4 million due to an increase in the per MWh nodal fee by
ERCOT. |
These increases were offset by:
|
|
|
Fuel risk management activities decreased $92 million due to gains of $38 million
recorded for the six months ended June 30, 2010, compared to losses of $54 million during the
same period in 2009. The $38 million of gains in 2010 consisted of $40 million of
mark-to-market gains offset by $2 million of losses on settled transactions, compared to $41
million of unrealized mark-to-market losses and $13 million in losses on settled transactions
in the same period in 2009. Please refer to the Consolidated Results of Operations to this
Form 10-Q for a more complete description of movements in risk
management activities. |
Other Operating Expenses
Other operating expenses increased by $28 million during the six months ended June 30, 2010,
compared to the same period in 2009, driven by increased operations and maintenance expense of $26
million due to baseload outages, and general and administrative
expense of $2 million.
78
Northeast Region
For a discussion of the business profile of the Northeast region, see pages 101-105 of NRG
Energy, Inc.s 2009 Annual Report on
Form 10-K.
Selected Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
Change % |
|
2010 |
|
2009 |
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
115 |
|
|
$ |
79 |
|
|
|
46 |
% |
|
$ |
236 |
|
|
$ |
260 |
|
|
|
(9 |
)% |
Capacity revenue |
|
|
100 |
|
|
|
100 |
|
|
|
|
|
|
|
204 |
|
|
|
196 |
|
|
|
4 |
|
Risk management activities |
|
|
(15 |
) |
|
|
51 |
|
|
|
(129 |
) |
|
|
32 |
|
|
|
233 |
|
|
|
(86 |
) |
Other revenues |
|
|
5 |
|
|
|
7 |
|
|
|
(29 |
) |
|
|
12 |
|
|
|
12 |
|
|
|
|
|
|
Total operating revenues |
|
|
205 |
|
|
|
237 |
|
|
|
(14 |
) |
|
|
484 |
|
|
|
701 |
|
|
|
(31 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management
activities) |
|
|
89 |
|
|
|
58 |
|
|
|
53 |
|
|
|
176 |
|
|
|
175 |
|
|
|
1 |
|
Other operating expenses |
|
|
73 |
|
|
|
94 |
|
|
|
(22 |
) |
|
|
169 |
|
|
|
188 |
|
|
|
(10 |
) |
Depreciation and amortization |
|
|
31 |
|
|
|
30 |
|
|
|
3 |
|
|
|
63 |
|
|
|
59 |
|
|
|
7 |
|
|
Operating Income/(Loss) |
|
$ |
12 |
|
|
$ |
55 |
|
|
|
(78 |
) |
|
$ |
76 |
|
|
$ |
279 |
|
|
|
(73 |
) |
MWh sold (in thousands) |
|
|
1,688 |
|
|
|
1,634 |
|
|
|
3 |
|
|
|
4,077 |
|
|
|
4,272 |
|
|
|
(5 |
) |
MWh generated (in thousands) |
|
|
1,688 |
|
|
|
1,634 |
|
|
|
3 |
|
|
|
4,077 |
|
|
|
4,272 |
|
|
|
(5 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices
($/MWh) (a) |
|
|
54.05 |
|
|
|
39.68 |
|
|
|
36 |
|
|
|
53.46 |
|
|
|
48.99 |
|
|
|
9 |
|
Cooling Degree Days, or CDDs(b) |
|
|
215 |
|
|
|
77 |
|
|
|
179 |
|
|
|
215 |
|
|
|
77 |
|
|
|
179 |
|
CDDs 30 year average |
|
|
105 |
|
|
|
105 |
|
|
|
|
|
|
|
105 |
|
|
|
105 |
|
|
|
|
|
Heating Degree Days, or HDDs(b) |
|
|
594 |
|
|
|
789 |
|
|
|
(25 |
)% |
|
|
3,447 |
|
|
|
3,997 |
|
|
|
(14 |
)% |
HDDs 30 year average |
|
|
841 |
|
|
|
841 |
|
|
|
|
|
|
|
3,935 |
|
|
|
3,935 |
|
|
|
|
|
|
|
|
|
(a) |
|
MWh sold are shown net of
MWh purchased to satisfy certain load contracts in the
region. |
|
(b) |
|
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 decreased by $43 million for the three months ended June 30, 2010, compared
to the same period in 2009 due primarily to a decrease in net risk management activities of $72
million offset by a decrease in other operating expenses of $21 million. Generation activities
were relatively flat as increases in energy revenues were mostly offset by increases in cost of
energy.
Operating Revenues
Operating revenues decreased by $32 million for the three months ended June 30, 2010, compared
to the same period in 2009, due to:
|
|
|
Risk management activities decreased $66 million as losses of $15 million were recorded
for the three months ending June 30, 2010, compared to gains of $51 million during the same
period in 2009. The $15 million loss in 2010 included $59 million of unrealized
mark-to-market losses and $44 million in gains on settled transactions, or financial income,
compared to $45 million in unrealized mark-to-market losses and $96 million in financial
gains during the same period in 2009. Please refer to the Consolidated Results of Operations
to this Form 10-Q for a more complete description of movements in
risk management activities. |
79
These decreases were offset by:
|
|
|
Energy revenues
increased by $36 million due to: |
|
o |
|
Energy prices increased by $32 million reflecting an average 50% increase in
merchant energy prices. |
|
|
o |
|
Generation increased by $4 million due to a 3% increase in generation in 2010
compared to 2009, which is comprised of a 20% increase in oil and gas generation and a 1%
decrease in coal generation. The increase in oil and gas generation is attributable to
higher reliability run hours at the Connecticut plants. |
|
|
o |
|
Margin on MWh sold from market purchases decreased by $8 million due to the
expiration of load contracts. |
|
|
o |
|
Contract revenues increased by $8 million due to revenues from new load-serving
contracts which commenced June 1, 2010. |
|
|
|
Capacity revenues remained flat, however reflected higher capacity prices in New York
City, offset by a decrease in capacity revenues in New England due to the expiration of the
RMR contracts for Montville, Middletown and Norwalk on May 31,
2010. |
Cost of Energy
Cost of energy increased by $31 million for the three months ended June 30, 2010, compared to
the same period in 2009, due to:
|
|
|
Natural gas and oil costs increased by $13 million, or 47%, due to 37% higher average
prices and 20% higher generation. |
|
|
|
|
Coal costs increased by $4 million, or 11%, due to 52% higher average prices offset by
a 1% decrease in coal generation as discussed in energy revenues
above. |
|
|
|
|
Fuel risk management activities increased $6 million as gains of $4 million were
recorded for the three months ending June 30, 2010, related primarily to mark-to-market gains
as compared to gains of $10 million in 2009, consisting of $11 million in mark-to-market
gains and $1 million in losses on settled transactions, or financial cost of energy. Please
refer to the Consolidated Results of Operations to this Form 10-Q for a more complete
description of movements in risk management activities. |
|
|
|
|
Purchased energy increased by $8 million due to costs to supply new load contracts
which commenced June 1, 2010. |
Other Operating Expenses
Other operating expenses decreased by $21 million for the three months ended June 30,
2010, compared to the same period in 2009, due to:
|
|
|
Property tax expense decreased by $12 million due to increased credits related to the
New York Empire Zone program for 2010 and by a $6 million charge in June 2009 to reflect
changes in Empire Zone regulations that eliminated the Oswego plants ability to continue
participation in the Empire Zone program. |
|
|
|
|
General & administrative expense decreased $4 million due primarily to a reduction in
corporate allocations. |
|
|
|
|
Operations and maintenance expense decreased $4 million due primarily to lower spending
at the Arthur Kill plant, which completed a major outage project in the second quarter of
2009. |
80
Year-to-Date Results
Operating Income
Operating income decreased by $203 million for the six months ended June 30, 2010, compared to
the same period in 2009 due primarily to the impact of net risk management activities, which
decreased by $201 million. In addition, there were decreases in energy revenues of $24 million
that were offset by an increase in capacity revenues of $8 million and a decrease in other
operating expenses of $19 million.
Operating Revenues
Operating revenues decreased by $217 million for the six months ended June 30, 2010, compared
to the same period in 2009, due to:
|
|
|
Energy revenues
decreased by $24 million due to: |
|
o |
|
Energy prices decreased by $7 million reflecting an average 4% decline in
merchant energy prices. |
|
|
o |
|
Generation decreased by $13 million due to a 5% decrease in generation in 2010
compared to 2009, driven by a 2% decrease in coal generation and a 19% decrease in oil
and gas generation. The decrease in oil and gas generation is attributable to a
combination of planned and forced outages as well as reserve shutdowns primarily at
Arthur Kill, Middletown and Oswego in the first quarter 2010, offset in part by higher
reliability run hours at the Connecticut plants. |
|
|
o |
|
Margin on MWh sold from market purchases decreased by $12 million due to the
expiration of a load contract in May 2009. |
|
|
o |
|
Contract revenues increased by $8 million due to revenues from new load-serving
contracts which commenced June 1, 2010. |
|
|
|
Risk management activities decreased $201 million as gains of $32 million were recorded
for the six months ending June 30, 2010, compared to gains of $233 million during the same
period in 2009. The $32 million gain in 2010 included $45 million of unrealized
mark-to-market losses and $77 million in gains on settled transactions, or financial income,
compared to $77 million in unrealized mark-to-market gains and $156 million in financial
income during the same period in 2009. Please refer to the Consolidated Results of
Operations to this Form 10-Q for a more complete description of movements in risk management
activities. |
This
increase was offset by:
|
|
|
Capacity revenues
increased by $8 million due to: |
|
o |
|
NYISO capacity revenues increased by $15 million due to higher capacity prices
in New York City driven in part by the retirement of the Poletti facility in January
2010. |
|
|
o |
|
PJM capacity
revenues increased by $6 million due to higher capacity
prices. |
|
|
o |
|
NEPOOL capacity revenues decreased by $13 million due to the expiration of the
RMR contracts for Montville, Middletown and Norwalk on May 31, 2010. These plants now
operate as fully merchant facilities. |
81
Cost of Energy
Cost of energy increased by $1 million for the six months ended June 30, 2010, compared to the
same period in 2009, due to:
|
|
|
Purchased energy increased by $8 million due to costs to supply new load contracts,
which commenced June 1, 2010. |
|
|
|
|
Fuel risk management activities remained flat as gains of $15 million were recorded for
the six months ending June 30, 2010, related to mark-to-market gains, as compared to gains of
$15 million in 2009, consisting of $20 million in mark-to-market gains and $5 million in
losses on settled transactions, or financial cost of energy. Please refer to the
Consolidated Results of Operations to this Form 10-Q for a more complete description of
movements in risk management activities. |
These increases were offset by:
|
|
|
Natural gas and oil costs decreased by $5 million, or 7%, due to 19% lower generation
offset by 17% higher average prices. |
Other Operating Expenses
Other operating expenses decreased by $19 million for the six months ended June 30, 2010,
compared to the same period in 2009, due to:
|
|
|
Property taxes decreased by $11 million due to increased credits related to the New
York Empire Zone program for 2010 and by a $6 million charge in June 2009 to reflect changes
in Empire Zone regulations that eliminated the Oswego plants ability to continue
participation in the Empire Zone program. |
|
|
|
|
ARO accretion expense decreased $4 million due to a change in estimate for an ARO
liability at the Huntley and Dunkirk plants. |
|
|
|
|
General and administrative expense decreased $10 million due primarily to a reduction
in corporate allocations. |
These decreases were offset by:
|
|
|
Operations and maintenance expense increased $6 million due primarily to $12 million in
charges relating to the write-off of previously capitalized costs on the Indian River Unit 3
back end controls project together with associated cancellation penalties and write-offs for
other asset retirements of $8 million. In addition, 2009 includes credits of $4 million
booked to reflect resolution of certain station service liabilities. These increases were
offset by decreases in normal and major maintenance of $17 million mainly due to lower
spending at the Indian River and Arthur Kill plants, which completed a major outage project
in the second quarter of 2009. |
82
South Central Region
For a discussion of the business profile of the South Central region, see pages 106-109 of NRG
Energy, Inc.s 2009 Annual Report on Form 10-K.
Selected Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
Change% |
|
2010 |
|
2009 |
|
Change% |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
96 |
|
|
$ |
81 |
|
|
|
19 |
% |
|
$ |
202 |
|
|
$ |
177 |
|
|
|
14 |
% |
Capacity revenue |
|
|
58 |
|
|
|
65 |
|
|
|
(11 |
) |
|
|
115 |
|
|
|
133 |
|
|
|
(14 |
) |
Risk management activities |
|
|
(7 |
) |
|
|
(12 |
) |
|
|
42 |
|
|
|
(32 |
) |
|
|
(19 |
) |
|
|
(68 |
) |
Contract amortization |
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
10 |
|
|
|
11 |
|
|
|
(9 |
) |
Other revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
100 |
|
|
Total operating revenues |
|
|
152 |
|
|
|
139 |
|
|
|
9 |
|
|
|
295 |
|
|
|
301 |
|
|
|
(2 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk
management activities) |
|
|
80 |
|
|
|
92 |
|
|
|
(13 |
) |
|
|
177 |
|
|
|
202 |
|
|
|
(12 |
) |
Other operating expenses |
|
|
41 |
|
|
|
27 |
|
|
|
52 |
|
|
|
63 |
|
|
|
49 |
|
|
|
29 |
|
Depreciation and amortization |
|
|
16 |
|
|
|
17 |
|
|
|
(6 |
) |
|
|
32 |
|
|
|
34 |
|
|
|
(6 |
) |
|
Operating Income |
|
$ |
15 |
|
|
$ |
3 |
|
|
|
400 |
|
|
$ |
23 |
|
|
$ |
16 |
|
|
|
44 |
|
MWh sold (in thousands) |
|
|
3,221 |
|
|
|
2,792 |
|
|
|
15 |
|
|
|
6,399 |
|
|
|
5,961 |
|
|
|
7 |
|
MWh generated (in thousands) |
|
|
2,366 |
|
|
|
2,386 |
|
|
|
(1 |
) |
|
|
5,008 |
|
|
|
5,093 |
|
|
|
(2 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power
prices ($/MWh) |
|
|
38.96 |
|
|
|
32.21 |
|
|
|
21 |
|
|
|
41.13 |
|
|
|
34.75 |
|
|
|
18 |
|
Cooling Degree Days, or
CDDs(a) |
|
|
689 |
|
|
|
582 |
|
|
|
18 |
|
|
|
689 |
|
|
|
588 |
|
|
|
17 |
|
CDDs 30 year average |
|
|
458 |
|
|
|
458 |
|
|
|
|
|
|
|
489 |
|
|
|
489 |
|
|
|
|
|
Heating Degree Days, or
HDDs(a) |
|
|
182 |
|
|
|
289 |
|
|
|
(37 |
)% |
|
|
2,423 |
|
|
|
2,094 |
|
|
|
16 |
% |
HDDs 30 year average |
|
|
299 |
|
|
|
299 |
|
|
|
|
|
|
|
2,194 |
|
|
|
2,194 |
|
|
|
|
|
|
|
|
|
(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 increased by $12 million for the three months ended June 30, 2010, due to the
favorable impact of $22 million in net risk management activities offset by $14 million of higher
operating expenses.
Operating Revenues
Operating revenues increased by $13 million for the three months ended June 30, 2010, compared
to the same period in 2009, due to:
|
|
|
Energy revenues increased by $15 million due to a $19 million rise in contract revenue
offset by a decline of $4 million in merchant energy revenues. Total megawatt hours sold to
the regions contract customers increased 13% reflecting the impact of a new contract with a
regional municipality and higher sales to cooperative customers. The new contract added an
additional $12 million and a fuel pass-through to the cooperative customers increased $6
million. The average realized price on contract energy sales was $27.77 per MWh in 2010
compared to $22.98 per MWh in 2009. Megawatt hours sold to the merchant market increased by
26% but lower realized merchant prices resulted in a drop of $4 million. |
83
|
|
|
Risk management activities increased $5 million as losses of $7 million were recorded
for the three months ended June 30, 2010 compared to losses of $12 million during the same
period in 2009. The $7 million loss in 2010 included $1 million in unrealized gains and $8
million in realized losses compared to $10 million in unrealized losses and $2 million in
realized losses for the same period in 2009. Please refer to the Consolidated Results of
Operations to this Form 10-Q for a more complete description of movements in risk management
activities. |
|
|
|
|
Capacity revenues capacity revenue decreased by $7 million due to an $8 million
decrease resulting from the expiration of a capacity agreement offset by higher capacity
revenue associated with the regions contract customers. |
Cost of Energy
Cost of energy decreased by $12 million for the three months ended June 30, 2010, compared to
the same period in 2009, due to:
|
|
|
Fuel risk management activities
decreased $17 million as gains of $9 million were
recorded for the three months ended June 30, 2010, related to mark-to-market gains, as
compared to a loss of $8 million recorded in 2009, consisting of $5 million in unrealized
losses and $3 million in realized losses. Please refer to the Consolidated Results of
Operations to this Form 10-Q for a more complete description of movements in risk management
activities. |
This decrease was offset by:
|
|
|
Purchased energy Total purchased power increased by $5 million as increased load
requirements were met with market purchases. |
Other Operating Expenses
Other operating expense increased by $14 million for the three months ended June 30, 2010,
compared to the same period in 2009. The scope of work and duration of the 2010 outage at the
regions coal facility was greater than the outage work performed in 2009. Outage work is performed
in accordance with the regions long-term maintenance plan.
Year-to-Date Results
Operating income increased by $7 million for the six months ended June 30, 2010, due to the
favorable impact of $22 million in net risk management activities offset by $14 million of higher
operating expenses.
Operating Revenues
Operating revenues decreased by $6 million for the six months ended June 30, 2010
compared to the same period in 2009 due to:
|
|
|
Energy revenues increased by $25 million due to a $31 million increase in contract
revenue offset by a $6 million decrease in merchant energy revenues. The increase is
attributable to the regions cooperative customers from fuel cost pass-through which
contributed $12 million and increased volume $6 million. The new contract with a regional
municipality added an additional $12 million. Merchant megawatt hour sales fell by 5% and
average realized prices were down by $1.75 MWh. |
|
|
|
|
Capacity revenues decreased by $18 million due to the expiration of a capacity
agreement with a regional utility. |
|
|
|
|
Risk management activities
decreased by $13 million as losses of $32 million were
recorded for the six months ended June 30, 2010 compared to losses of $19 million recognized
during the same period in 2009. The $32 million loss in 2010 included $12 million in
unrealized losses and $20 million of realized losses, compared to $30 million in unrealized
losses offset by $11 million in realized gains for the same period in 2009. Please refer to
the Consolidated Results of Operations to this Form 10-Q for a more complete description of
movements in risk management activities. |
84
Cost of Energy
Cost of energy decreased by $25 million for the six months ended June 30, 2010, compared to
the same period in 2009, due to:
|
|
|
Fuel risk management activities
decreased $35 million as gains of $19 million were
recorded for the six months ended June 30, 2010, compared to losses of $16 million during
the same period in 2009. The $19 million of gains in 2010 included $20 million of
unrealized gains offset by $1 million of realized losses, compared to $10 million in
unrealized losses and $6 million in realized losses for the same period in 2009. Please
refer to the Consolidated Results of Operations to this Form 10-Q for a more complete
description of movements in risk management activities. |
|
|
|
|
Coal costs dropped by $4 million due to a 1% reduction in coal generation. |
These decreases were offset by:
|
|
|
Purchased energy increased by $11 million as increased load requirements were met with
market purchases. |
Other Operating Expenses
Other operating expense increased by $14 million for the six months ended June 30, 2010,
compared to the same period in 2009. The scope of work and duration of the 2010 outage at the
regions coal facility was greater than the outage work performed in 2009. Outage work is performed
in accordance with the regions long-term maintenance plan.
85
West Region
For a discussion of the business profile of the West region, see pages 110-112 of NRG Energy,
Inc.s 2009 Annual Report on Form 10-K.
Selected Income Statement Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2010 |
|
2009 |
|
Change% |
|
2010 |
|
2009 |
|
Change% |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
2 |
|
|
$ |
5 |
|
|
|
(60 |
)% |
|
$ |
10 |
|
|
$ |
7 |
|
|
|
43 |
% |
Capacity revenue |
|
|
27 |
|
|
|
31 |
|
|
|
(13 |
) |
|
|
53 |
|
|
|
60 |
|
|
|
(12 |
) |
Risk management activities |
|
|
3 |
|
|
|
6 |
|
|
|
(50 |
) |
|
|
4 |
|
|
|
3 |
|
|
|
33 |
|
|
Total operating revenues |
|
|
32 |
|
|
|
42 |
|
|
|
(24 |
) |
|
|
67 |
|
|
|
70 |
|
|
|
(4 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk
management activities) |
|
|
1 |
|
|
|
3 |
|
|
|
(67 |
) |
|
|
6 |
|
|
|
7 |
|
|
|
(14 |
) |
Other operating expenses |
|
|
20 |
|
|
|
21 |
|
|
|
(5 |
) |
|
|
41 |
|
|
|
46 |
|
|
|
(11 |
) |
Depreciation and amortization |
|
|
3 |
|
|
|
2 |
|
|
|
50 |
|
|
|
6 |
|
|
|
4 |
|
|
|
50 |
|
|
Operating Income |
|
$ |
8 |
|
|
$ |
16 |
|
|
|
(50 |
) |
|
$ |
14 |
|
|
$ |
13 |
|
|
|
8 |
|
MWh sold (in thousands) |
|
|
28 |
|
|
|
62 |
|
|
|
(55 |
) |
|
|
97 |
|
|
|
76 |
|
|
|
28 |
|
MWh generated (in thousands) |
|
|
28 |
|
|
|
62 |
|
|
|
(55 |
) |
|
|
97 |
|
|
|
76 |
|
|
|
28 |
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power
prices ($/MWh) |
|
|
35.40 |
|
|
|
33.14 |
|
|
|
7 |
|
|
|
41.64 |
|
|
|
36.80 |
|
|
|
13 |
|
Cooling Degree Days, or
CDDs(a) |
|
|
75 |
|
|
|
144 |
|
|
|
(48 |
) |
|
|
75 |
|
|
|
144 |
|
|
|
(48 |
) |
CDDs 30 year average |
|
|
150 |
|
|
|
150 |
|
|
|
|
|
|
|
157 |
|
|
|
157 |
|
|
|
|
|
Heating Degree Days, or
HDDs(a) |
|
|
674 |
|
|
|
470 |
|
|
|
43 |
% |
|
|
2,004 |
|
|
|
1,880 |
|
|
|
7 |
% |
HDDs 30 year average |
|
|
556 |
|
|
|
556 |
|
|
|
|
|
|
|
1,975 |
|
|
|
1,975 |
|
|
|
|
|
|
|
|
|
(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 decreased by $8 million for the three months ended June 30, 2010, compared to
the same period in 2009.
Operating Revenues
Operating revenues decreased by $10 million for the three months ended June 30, 2010, compared
to the same period in 2009, due to:
|
|
|
Energy revenues decreased by $3 million primarily due to a 55% decrease in generation
and an 11% decline in merchant energy prices in 2010 compared to 2009. This increase
includes $2 million in energy revenue related to Blythe Solar, which began commercial
operation in December 2009. |
|
|
|
|
Capacity revenues decreased by $4 million due to a reduction in resource adequacy and
call option contract sales at El Segundo in 2010 compared to 2009. |
86
|
|
|
Risk management activities decreased $3 million as gains of $3 million were recorded
for the three months ended June 30, 2010, compared to gains of $6 million during the same
period in 2009. The $3 million of gains in 2010 included $2 million of unrealized
mark-to-market gains and $1 million in gains on settled transactions, or financial income,
compared to $7 million in unrealized mark-to-market gains and $1 million in financial losses
during the same period in 2009. Please refer to the Consolidated Results of Operations to
this Form 10-Q for a more complete description of movements in risk
management activities. |
Cost of Energy
Cost of energy decreased by $2 million for the three months ended June 30, 2010, compared to
the same period in 2009, due to a 77% decrease in natural gas consumption due to lower generation.
This decrease was partially offset by a 44% increase in average natural gas prices per MMBtu.
Year-to-Date Results
Operating income increased by $1 million for the six months ended June 30, 2010, compared to
the same period in 2009.
Operating Revenues
Operating revenues decreased by $3 million for the six months ended June 30, 2010, compared to
the same period in 2009, due to:
|
|
|
Capacity revenues decreased by $7 million primarily due to reduced resource adequacy
and call option contract sales at El Segundo in 2010 compared to
2009. |
|
|
|
|
Energy revenues increased by $3 million primarily due to incremental revenue from the
commencement of operations at Blythe Solar. The region experienced a 28% increase in
generation and a 3% increase in merchant energy prices in 2010
compared to 2009. |
Cost of Energy and Other Operating Expenses
Cost of energy and other operating expenses decreased by $6 million for the six months ended
June 30, 2010, compared to the same period in 2009, due to:
|
|
|
Cost of energy decreased by $1 million due to $3 million of expense in 2009
resulting from a write-down to market of fuel oil inventory no longer used in the production
of energy. This decrease was offset by a $2 million increase in natural gas expense due to
a 47% increase in average natural gas prices per MMBtu and a 12% decrease in natural gas
consumption. |
|
|
|
|
Other operating expenses decreased by $5 million due to lower major maintenance
expense associated with a major overhaul at El Segundo in 2009. |
87
Liquidity and Capital Resources
Liquidity Position
As of June 30, 2010, and December 31, 2009, NRGs liquidity, excluding collateral received,
was approximately $3.5 billion and $3.8 billion, respectively, comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(In millions) |
|
2010 |
|
2009 |
|
Cash and cash equivalents |
|
$ |
2,168 |
|
|
$ |
2,304 |
|
Funds deposited by counterparties |
|
|
310 |
|
|
|
177 |
|
Restricted cash |
|
|
13 |
|
|
|
2 |
|
|
Total cash |
|
|
2,491 |
|
|
|
2,483 |
|
Funded Letter of Credit Facility availability |
|
|
480 |
|
|
|
583 |
|
Revolving Credit Facility availability |
|
|
839 |
|
|
|
905 |
|
|
Total liquidity |
|
|
3,810 |
|
|
|
3,971 |
|
Less: Funds deposited as collateral by hedge counterparties |
|
|
(310 |
) |
|
|
(177 |
) |
|
Total liquidity, excluding collateral received |
|
$ |
3,500 |
|
|
$ |
3,794 |
|
|
For the six months ended June 30, 2010, total liquidity, excluding collateral received,
decreased by $294 million due to lower cash and cash equivalent balances of $136 million, decreased
availability of the Funded Letter of Credit Facility of $103 million, and decreased availability of
$66 million in the Revolving Credit Facility. The Revolving Credit Facility availability decrease
was due to a decrease in capacity of $125 million as a result of the refinancing of the Senior
Credit Facility, offset by an increase of $59 million due to the cancellation in February 2010 of
the letter of credit issued in support of the Dunkirk bonds, as described below and further in Note
8, Long-Term Debt. Changes in cash and cash equivalent balances are further discussed below under
the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties
at June 30, 2010, were predominantly held in money market funds invested in treasury securities,
treasury repurchase agreements or government agency debt.
The line item Funds deposited by counterparties represents the amounts that are held by NRG
as a result of collateral posting obligations from the Companys counterparties due to positions in
the Companys hedging program. These amounts are segregated into separate accounts that are not
contractually restricted but, based on the Companys intention, are not available for the payment
of NRGs general corporate obligations. Depending on market fluctuation and the settlement of the
underlying contracts, the Company will refund this collateral to the counterparties pursuant to the
terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and
the Company cannot predict if any collateral will be held for more than twelve months, the funds
deposited by counterparties are classified as a current asset on the Companys balance sheet, with
an offsetting liability for this cash collateral received within current liabilities.
Management believes that the Companys liquidity position and cash flows from operations will
be adequate to finance operating and maintenance capital expenditures 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%.
88
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, existing cash on hand and cash
flows from operations.
Financing Arrangements
Senior Credit Facility
On June 30, 2010, NRG completed an amendment and extension, or the Amendment, of its Senior
Credit Facility. NRGs Senior Credit Facility is comprised of the Term Loan Facility, the Funded
Letter of Credit Facility and the Revolving Credit Facility. As a result of the Amendment, NRG
extended the maturity date for approximately $1.0 billion of the $2.0 billion outstanding Term Loan
Facility to August 31, 2015, and the remaining amount is due on the original maturity date of
February 1, 2013. In addition, borrowing capacity under the Revolving Credit Facility was reduced
from $1.0 billion to $875 million and its maturity was extended to August 31, 2015. Finally, the
Synthetic Letter of Credit Facility was converted into a term loan-backed Funded Letter of Credit
Facility (on an on-balance sheet basis), with term loans in an amount of $800 million
maturing on August 31, 2015, and $500 million maturing on the original maturity date of February 1,
2013. As of June 30, 2010, NRG had issued $820 million of letters of credit under the Funded
Letter of Credit Facility, leaving $480 million available for future issuances. Under the
Revolving Credit Facility as of June 30, 2010, NRG had issued a letter of credit of $36 million,
leaving $839 million available.
TANE Facility
On February 24, 2009, NINA executed an Engineering, Procurement and Construction, or EPC,
agreement with TANE, which specifies the terms under which STP Units 3 and 4 will be constructed.
Concurrent with the execution of the EPC agreement, NINA and TANE entered into the TANE Facility,
wherein TANE has committed up to $500 million to finance purchases of long-lead materials and
equipment for the construction of STP Units 3 and 4. The TANE Facility matures on February 24,
2012, subject to two renewal periods, and provides for customary events of default, which include,
among others: nonpayment of principal or interest; default under other indebtedness; the rendering
of judgments; and certain events of bankruptcy or insolvency. Outstanding borrowings will accrue
interest at LIBOR plus 3%, subject to a ratings grid, and are secured by substantially all of the
assets of and membership interests in NINA and its subsidiaries. As of June 30, 2010, $3 million
has been borrowed under the TANE Facility.
NRG Non-Recourse Project Financings
During the second quarter 2010, three of the Companys subsidiaries completed the following
project level financings which are non-recourse to NRG. See Note 8, Long-Term Debt, to this Form
10-Q for a more complete description of these project financings.
|
|
|
|
|
|
|
As of |
(in millions) |
|
June 30, 2010 |
|
NRG Solar Blythe LLC, term loan due 2028 |
|
$ |
30 |
|
South Trent Wind LLC, term loan due 2020 |
|
$ |
79 |
|
NRG Energy Center Minneapolis LLC, senior secured notes due 2025 |
|
$ |
100 |
|
|
GenConn Energy LLC related financings
NRG Connecticut Peaking Development LLC made funding requests under the EBL during the
quarter. The EBL is backed by a letter of credit issued by NRG under its Funded Letter of Credit
Facility equal to 104% of the amount outstanding. The proceeds of the EBL received through June
30, 2010, were $115 million and the remaining amounts will be drawn as necessary to fund interest
on the EBL as the maximum amount permitted to be drawn for project costs for both projects has been
met. Of the $115 million, $55 million was drawn to fund Devon project costs and will become due
and payable upon COD of the Devon project, which is expected to occur in the third quarter of 2010.
89
In April 2009, GenConn secured financing for 50% of the Devon and Middletown project
construction costs through a seven-year term loan facility, and also entered into a five-year
revolving working capital loan and letter of credit facility, which collectively with the term loan
is referred to as the GenConn Facility. The aggregate credit amount secured under the GenConn
Facility, which is non-recourse to NRG, is $291 million, including $48 million for the revolving
facility. In August 2009, GenConn began to draw under the GenConn Facility to cover costs related
to the Devon project, and in June 2010 began to draw to cover costs related to the Middletown
project. As of June 30, 2010, $109 million had been drawn.
First and Second Lien Structure
NRG has granted first and second liens to certain counterparties on substantially all of the
Companys assets. NRG uses the first and 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-money hedge agreements for forward sales of power or MWh
equivalents. To the extent that the underlying hedge positions for a counterparty are in-the-money
to NRG, the counterparty would have no claim under the lien program. The lien program limits the
volume that can be hedged, not the value of underlying out-of-money positions. The first lien
program does not require NRG to post collateral above any threshold amount of exposure. Within the
first and second lien structure, the Company can hedge up to 80% of its baseload capacity and 10%
of its non-baseload assets with these counterparties for the first 60 months and then declining
thereafter. Net exposure to a counterparty on all trades must be positively correlated to the
price of the relevant commodity for the first lien to be available to that counterparty. The first
and second lien structure is not subject to unwind or termination upon a ratings downgrade of a
counterparty or NRG and has no stated maturity date.
The Companys lien counterparties may have a claim on its assets to the extent market prices
exceed the hedged price. As of June 30, 2010, all hedges under the first and second liens were
in-the-money on a counterparty aggregate basis.
The following table summarizes the amount of MWs hedged against the Companys baseload assets
and as a percentage relative to the Companys baseload capacity under the first and second lien
structure as of June 30, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales Secured by First and Second Lien Structure(a) |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
In MW(b) |
|
|
2,793 |
|
|
|
2,222 |
|
|
|
1,439 |
|
|
|
736 |
|
As a percentage of total net baseload capacity(c) |
|
|
41 |
% |
|
|
33 |
% |
|
|
21 |
% |
|
|
11 |
% |
|
|
|
|
(a) |
|
Equivalent Net Sales include natural gas swaps converted using a weighted average heat
rate by region. |
|
(b) |
|
2010 MW value consists of July through December positions only. |
|
(c) |
|
Net baseload capacity under the first and second lien structure represents 80% of the
Companys total baseload assets. |
90
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 June 30, 2010, commercial operations
had total cash collateral outstanding of $391 million, and $537 million outstanding in letters of
credit to third parties primarily to support its economic hedging activities for both wholesale and
retail transactions (includes a $60 million letter of credit relating to deposits at the PUCT that
covers outstanding customer deposits and residential advance payments). As of June 30, 2010, total
collateral held from counterparties was $310 million and $11 million of letters of credit.
Future liquidity requirements may change based on the Companys hedging activities and
structures, fuel purchases, and future market conditions, including forward prices for energy and
fuel and market volatility. In addition, liquidity requirements are dependent on NRGs credit
ratings and the general perception of its creditworthiness.
Debt Service Obligations
NRG must annually offer a portion of its excess cash flow, as defined in the Senior Credit
Facility, to its first lien lenders under the Term Loan Facility. The percentage of excess cash
flow offered to these lenders is dependent upon the Companys consolidated leverage ratio, as
defined in the Senior Credit Facility, at the end of the preceding year. Of the amount offered,
the first lien lenders must accept 50% while the remaining 50% may either be accepted or rejected
at the lenders option. In March 2010, NRG made and the lenders accepted a repayment of
approximately $229 million for the mandatory annual offer relating to 2009.
Debt Related to Capital Allocation Program
On March 3, 2010, the Company completed the early unwinding of the CSF I Debt by remitting a
cash payment to CS of $242 million to settle the outstanding principal and interest, as compared to
$249 million that would have been due at maturity in June 2010. The Company has now settled all
obligations related to the CSF I and II Debt entered into in 2006, as amended from time to time, as
well as the SLA entered into in February 2009.
Acquisitions
During the second quarter 2010, the Company completed the acquisitions of Northwind Phoenix
and South Trent, for combined consideration totaling $211 million. See Note 4, Business
Acquisitions and Dispositions, to this Form 10-Q for a more complete description of these
acquisitions.
2010 Capital Allocation Plan
In the second quarter 2010, as part of the Companys 2010 Capital Allocation Plan, the Company
repurchased $50 million of its common stock. NRG intends to complete the remainder of its $180
million of share repurchases by the end of 2010, subject to market prices, financial restrictions
under the Companys debt facilities and as permitted by securities laws.
91
Capital Expenditures
The following table summarizes the Companys capital expenditures, including accruals, for the
six months ended June 30, 2010, and the estimated capital expenditure and repowering investments
forecast for the remainder of 2010. As discussed below, the Repowering expenditures include
amounts anticipated to be funded from sources other than NRG.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Maintenance |
|
Environmental |
|
Repowering |
|
Total |
|
Northeast |
|
$ |
5 |
|
|
$ |
83 |
|
|
$ |
1 |
|
|
$ |
89 |
|
Texas |
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
41 |
|
South Central |
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
West |
|
|
2 |
|
|
|
|
|
|
|
7 |
|
|
|
9 |
|
Reliant Energy |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Nuclear development |
|
|
|
|
|
|
|
|
|
|
279 |
|
|
|
279 |
|
Other |
|
|
22 |
|
|
|
|
|
|
|
5 |
|
|
|
27 |
|
|
Total for the six months ended June 30, 2010 |
|
$ |
80 |
|
|
$ |
83 |
|
|
$ |
292 |
|
|
$ |
455 |
|
|
Estimated capital expenditures for the remainder of 2010 |
|
$ |
166 |
|
|
$ |
111 |
|
|
$ |
194 |
|
|
$ |
471 |
|
|
RepoweringNRG capital expenditures RepoweringNRG project capital expenditures consisted of
approximately $279 million related to the development of STP Units 3 and 4 in Texas.
NRGs net expenditures for STP Units 3 and 4 for 2010, funded from operating activities, are
anticipated to be approximately $286 million. In addition, NINA anticipates net funding of
approximately $170 million of 2010 capital expenditures from sources other than NRG, including
draws on the TANE long-lead material facility, Toshiba equity contributions, and TEPCO equity
contributions upon NINAs acceptance of a U.S. DOE loan guarantee commitment. NINA is also
exploring additional funding alternatives with existing project constituents in the event a U.S.
DOE loan guarantee is not received in a timely fashion. In early 2010, NRG announced that if this
project did not receive a loan guarantee from the U.S. DOE in a timely fashion, it was the
intention of the Company both to reduce substantially its commitment to fund on-going project
expenditures as well as to reduce development spending on the project overall while the outcome of
the loan guarantee was uncertain. See Note 15, Commitments and Contingencies, to this Form 10-Q
for further discussion.
Major maintenance and environmental capital expenditures The Companys maintenance capital
expenditures were $80 million, of which $41 million was related to the Texas regions assets,
including approximately $15 million in nuclear fuel expenditures related to STP Units 1 and 2. The
Companys environmental capital expenditures were $83 million, of which $73 million was due to a
project to install selective catalytic reduction systems, scrubbers and fabric filters on Indian
River Unit 4 with an expected in service date of year end 2011.
Loans to affiliates The equity portion of construction costs for GenConn is funded through
the EBLs of NRG Connecticut Peaking and The United Illuminating Company, or United Illuminating.
These funds are made available to GenConn through interest bearing promissory notes that convert to
equity upon repayment of the EBL loans by NRG Connecticut Peaking and United Illuminating. As of
June 30, 2010, there was $116 million outstanding under the loan from NRG Connecticut Peaking.
92
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that environmental capital
expenditures from 2010 through 2014 to meet NRGs environmental commitments will be approximately
$0.9 billion. These capital expenditures, in general, are related to installation of particulate,
SO2, NOx, and mercury controls to comply with federal and state air quality
rules and consent orders, as well as installation of Best Technology Available under the Phase II
316(b) Rule. NRG continues to explore cost effective alternatives that can achieve desired
results. While this estimate reflects schedules and controls to meet anticipated reduction
requirements, the full impact on the scope and timing of environmental retrofits cannot be
determined until issuance of final rules by the U.S. EPA.
This estimate reflects the recent announcement to retrofit only Unit 4 at the Indian River
Generating Station and shifts in the timing of other projects to reflect anticipated issuance dates
for revised regulations.
NRGs current contracts with the Companys rural electrical customers in the South Central
region allow for recovery of a portion of the regions capital costs once in operation, along with
a capital return incurred by complying with new laws, including interest over the asset life of the
required expenditures. The actual recoveries will depend, among other things, on the timing of the
completion of the capital project and the remaining duration of the contracts.
Preferred Stock Dividend Payments
For the six months ended June 30, 2010, NRG paid approximately $5 million in dividends to
holders of the Companys 3.625% Preferred Stock.
Reliant Energy Customer Deposits
Revisions in the PUCT rules required that NRG keep a segregated account, or that the Company
post a fully collateralized letter of credit on or before May 21, 2010, to cover outstanding
customer deposits and residential advance payments. The Company filed an amendment to its Retail
Electric Provider certificate in the first quarter of 2010, which was approved by the PUCT, and
posted a letter of credit to satisfy the rule changes. The amount of deposits subject to
segregation as of June 30, 2010, was approximately $54 million.
93
Cash Flow Discussion
The following table reflects the changes in cash flows for the comparative years; all cash
flow categories include the cash flows from both continuing operations and discontinued operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
Six months ended June 30, |
|
2010 |
|
2009 |
|
Change |
|
Net cash provided by operating activities |
|
$ |
605 |
|
|
$ |
722 |
|
|
$ |
(117 |
) |
Net cash used by investing activities |
|
|
(385 |
) |
|
|
(500 |
) |
|
|
115 |
|
Net cash (used)/provided by financing activities |
|
|
(347 |
) |
|
|
565 |
|
|
|
(912 |
) |
|
Net Cash Provided By Operating Activities
For the six months ended June 30, 2010, net cash provided by operating activities decreased by
$117 million compared to the same period in 2009, due to:
|
|
|
Lower cash flows from Wholesale Power Generation The Companys cash flow from
operating activities excluding Reliant Energy was lower by $370 million, mainly due to a
$381 million decrease in operating income adjusted for non-cash charges, offset by a $6
million increase in net collateral deposits paid and option premiums paid and collected, as
well as a $5 million increase in working capital for 2010 as compared to the same period in
2009. |
|
|
|
|
Cash generated by Reliant Energy Reliant Energy contributed approximately $442 million
to the Companys consolidated cash flow from operating activities for the first six months
of 2010, compared with $189 million for the two months ended June 30, 2009. |
Net Cash Used By Investing Activities
For the six months ended June 30, 2010, net cash used by investing activities decreased by
$115 million compared to the same period in 2009, due to:
|
|
|
Cash for Acquisitions During 2010, the Company paid $141 million, primarily for the
acquisitions of Northwind Phoenix and South Trent. During 2009, the Company paid $345
million for the acquisition of Reliant Energy. |
|
|
|
|
Proceeds from renewable energy grants During 2010, the Company received $102 million
of federal cash grants for the Blythe solar and Langford wind facilities. |
|
|
|
|
Capital expenditures and loans to affiliates NRGs capital expenditures decreased by
$44 million due to decreased spending on maintenance, RepoweringNRG, and environmental
projects. Loans to affiliates reflects a net increase in cash of $26 million in 2010 as
compared to 2009. |
|
|
|
|
Proceeds from sale of assets Net proceeds increased by $24 million in 2010 as compared
to 2009 due to the sale of Padoma in January 2010. |
|
|
|
|
Proceeds from sale of equity method investment Proceeds from investing activities
decreased in 2010 as compared to 2009 due to the sale of MIBRAG in June 2009 for net
proceeds of $284 million. |
94
Net Cash Used By Financing Activities
For the six months ended June 30, 2010, net cash used by financing activities was $347
million, compared with net cash provided by financing activities of $565 million for the same
period in 2009, a net cash decrease of $912 million, due to:
|
|
|
Lower issuance of debt During 2010, the Company issued $130 million under new debt
facilities and $14 million under existing debt facilities. The new debt facilities consist
of $100 million by NRG Thermal and $30 million by Blythe. During 2009, the Company received
$25 million from the initial draw under the Reliant Energy working capital facility, $34
million from the Dunkirk bonds, $70 million in GenConn financings and $688 million in gross
proceeds from the 2019 Senior Notes. |
|
|
|
|
Increase in term loan and other facility payments In 2010, the Company paid down $240
million of its Term Loan Facility, including the payment of excess cash flow, as discussed
above under Debt Service Obligations. In addition, NINA paid $20 million under its
revolving credit facility. In 2009, the Company paid down $213 million of its Term Loan
Facility. |
|
|
|
|
Repayment of CSF I Debt During 2010, the Company paid $190 million in principal to
early settle the CSF I Debt. |
|
|
|
|
Share repurchases During 2010, the Company repurchased $50 million of NRG common
stock. |
|
|
|
|
Net receipt from acquired derivatives that include financing elements In 2010, the
Company received a net of $27 million for the settlement of gas swaps compared with a
payment of $22 million for 2009 for the settlement of gas swaps related to Reliant Energy
and Texas Genco. |
|
|
|
|
Increase in deferred financing costs During 2010, deferred financing costs primarily
consist of fees paid as a result of the amendment and extension of the Senior Credit
Facility. During 2009, the Company paid lower deferred financing costs related to the
Reliant Energy CSRA, the 2019 Senior Notes, the Dunkirk bonds and the Reliant Energy working
capital facility. |
|
|
|
|
Decrease in preferred stock dividends During 2010, dividend payments on preferred
stock decreased by $16 million as compared to the same period in 2009 due to the conversion
of the 5.75% Preferred Stock in 2009 and the conversion of the 4% Preferred Stock, which was
completed in January 2010. |
NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC-740, Income Taxes, or ASC 740
As of June 30, 2010, the Company had generated total domestic pre-tax book income of $410
million and foreign pre-tax book income of $40 million. The Company has net operating losses for
tax return purposes available to offset taxable income in the current period. In addition, NRG has
cumulative foreign NOL carryforwards of $240 million, of which $71 million will expire starting in
2011 through 2017 and of which $169 million do not have an expiration date.
In addition to these amounts, the Company has $635 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 statement purposes and for which a full
valuation allowance has been established. As a result of the Companys tax position, and based on
current forecasts, NRG anticipates income tax payments, primarily due to foreign, state and local
jurisdictions, of up to $75 million in 2010.
However, as the position remains uncertain for the $635 million of tax effected unrecognized
tax benefits, the Company has recorded a non-current tax liability of $512 million and may accrue
the remaining balance as an increase to non-current liabilities until final resolution with the
related taxing authority. The $512 million non-current tax liability for unrecognized tax benefits
is primarily due to taxable earnings for which there are no NOLs available to offset for financial
statement purposes.
The Company is under examination by the Internal Revenue Service for years 2004 through 2006,
as well as various state jurisdictions for multiple years.
95
New and On-going Company Initiatives, Development Projects and Acquisitions
FORNRG Update
Beginning in January 2009, the Company transitioned to FORNRG 2.0 to target an incremental 100
basis point improvement to the Companys ROIC by 2012. The initial targets for FORNRG 2.0 were
based upon improvements in the Companys ROIC as measured by increased cash flow. The economic
goals of FORNRG 2.0 will focus on: (i) revenue enhancement; (ii) cost savings; and (iii) asset
optimization, including reducing excess working capital and other assets. The FORNRG 2.0 program
will measure its progress towards the FORNRG 2.0 goals by using the Companys 2008 financial
results as a baseline, while plant performance calculations will be based upon the appropriate
historic baselines.
The 2010 FORNRG goal is 65 basis points improvement, which corresponds to approximately $98
million in cash flows. The goal is inclusive of benefits created in 2009 and new project benefits
reported in 2010. As of the second quarter 2010, the Company has delivered a 33 basis point
improvement in ROIC, which is equivalent to approximately $49 million in cash flows to the FORNRG
program. During 2010, the Company expects to progress further toward the program goal of 100 basis
point ROIC improvement by 2012.
RepoweringNRG Update
NRG has several projects in varying stages of development. The Companys development projects
are generally subject to certain conditions, milestones, or other factors that may result in the
Companys decision to no longer pursue the development of these projects. Projects that have
achieved a significant milestone, financing, or other material developments are more fully
described in the Companys 2009 Annual Report on Form 10-K and this Quarterly Report on Form 10-Q.
Air permitting litigation unrelated to the El Segundo project has delayed receipt of certain
required permits, including an air permit, which will prevent the El Segundo project from meeting
its original completion date of June 2011. However, legislation enacted on January 1, 2010, has
allowed the affected air district to issue air permits like El Segundos. A revised draft air
permit was issued in April 2010 by the South Coast Air Quality Management District, or SCAQMD,
allowing the project permitting to proceed. On June 30, 2010, the California Energy Commission
approved the construction permit, and the Company is now awaiting the issuance of the final air
permit by SCAQMD. The Company is working with the power purchaser to consider certain PPA
modifications including a revised commercial operations date, currently expected to be the summer
of 2013.
On March 9, 2010, NRG was selected by the U.S. DOE to negotiate to receive up to $167 million,
including funding from the American Recovery and Reinvestment Act, to build a 60 MW post-combustion
carbon capture demonstration unit at NRGs WA Parish plant southwest of Houston with use of the
captured carbon in enhanced oil recovery in adjacent oil fields. The proposed project was
submitted under the Clean Coal Power Initiative Program, or CCPI, a cost-shared collaboration
between the federal government and private industry to demonstrate carbon capture and storage
technologies in existing coal-based, power generation. On May 7, 2010, the Company executed a
cooperative agreement with the U.S. DOE which defines the basis for cost sharing in the development
and initial operations of the facility. The project currently is in the design engineering phase.
Construction would begin in late 2012 with commercial operations anticipated in the fourth quarter
2014.
The following is a summary of the 2010 repowering projects that are currently under
construction. In addition, NRG continues to participate in active bids in response to requests for
proposals in markets in which it operates.
96
Plants under Construction
GenConn Energy LLC GenConn Energy, a 50/50 joint venture of NRG and The United Illuminating
Company, or United Illuminating, formed to construct, own and operate peaking generation facilities
in Connecticut, is in the construction phase of two, 200 MW peaking facilities at NRGs Devon and
Middletown sites. Each of these facilities is being constructed pursuant to 30-year contracts for
differences with The Connecticut Light & Power Company. Three of the four units at the GenConn
Devon facility were released to the ISO-NE during June 2010 and the last unit was released to
ISO-NE in mid July 2010. The Middletown project, which is fully permitted, is in the early stages
of construction, with a target commercial operation date of June 1, 2011.
GenConn was directed by the Connecticut Department of Public Utility Control to bid the full
capacity of the GenConn Devon facility into the ISO-NE locational forward reserve auction for the
summer 2010 period (June 1, 2010 September 30, 2010). Because the units were not available to
the ISO-NE by June 1, 2010 and GenConn did not have or procure replacement capacity to meet its
full reserve obligation, GenConn was assessed ISO-NE penalties for the difference between the
cleared GenConn Devon capacity and the facilitys available capacity. NRGs share of such
penalties was not material.
In April 2009, GenConn Energy closed on $534 million of project financing related to these
projects. The project financing includes a seven-year project backed term loan and a five-year
working capital facility which together total $291 million. In addition, NRG and United
Illuminating have each closed an equity bridge loan of $121.5 million, which together total $243
million. NRG is funding its share of costs related to these projects via draw downs on the equity
bridge loan totaling $115 million as of June 30, 2010. GenConn began to draw on the project
financing facility to cover costs related to the Devon project in August 2009 and the Middletown
project in June 2010. As of June 30, 2010, $109 million had been drawn.
Retail Development
In 2009, NRG began development of a network operations business to support the large scale
deployment of electric vehicles in Houston and elsewhere in the ERCOT market. By 2011, and in
coordination with the introduction of multiple plug-in vehicles by the automotive industry, NRG
plans to offer a range of integrated products and services that enable both public and home
charging of electric vehicles. In conjunction with this effort, NRG announced in November 2009
that it will work with Nissan Motor Co. to make the City of Houston a launch city for the broader
use of electric vehicles. In November 2009, NRG announced a joint project with the City of Houston
to add plug-in fleet vehicles as well as public charging stations to support them. In March 2010,
NRG invested in Aptera Motors, Inc., a privately held electric vehicle, or EV, manufacturer
expected to launch a production EV in 2011.
In Mass, Reliant is continuing its development efforts in smart energy by enhancing the
products and services that provide energy usage insights, choices and control, and increasing the
scale at which we can offer these services. In addition, during the second quarter of 2010,
Reliant expanded its product offerings to include non-commodity value added services to both Mass
and C&I customers.
97
Nuclear Innovation North America
NINA, NRGs majority-owned subsidiary, is 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 Project. TANE, a wholly-owned subsidiary of Toshiba
Corporation, is the minority owner of NINA. Based on its current NRC schedule, the Company expects
to achieve commercial operation for Unit 3 in 2016 and commercial operation for Unit 4
approximately 12 months thereafter. The total rated capacity of STP Units 3 and 4 is expected to
be approximately 3,000 MW, subject to NRC approval.
The U.S. DOE has confirmed that the STP Units 3 and 4 Project is one of four projects selected
for further due diligence and negotiation leading to a conditional commitment under the U.S. DOE
loan guarantee program. NINA is currently in discussions with the U.S. DOE on the specific terms
and amount to be loaned for the project. NRG believes U.S. DOE loan guarantee support is critical
to new nuclear development projects. In addition to U.S. loan guarantees, NINA is seeking to
augment potential financial support from the U.S. DOE by actively pursuing additional loan
guarantees through the Japanese government.
The likelihood of NINA receiving a loan guarantee is largely dependent upon additional
appropriations for nuclear development by Congress or other means of properly securing the
necessary funding for additional nuclear loan guarantee volume. See Note 15, Commitments and
Contingencies, to this Form 10-Q for further discussion.
On March 1, 2010, an agreement was reached with CPS for NINA to acquire a controlling interest
in the STP Units 3 and 4 Project through a settlement of the litigation between the parties. See
Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.
On April 8, 2010, NINA announced an agreement for the Building and Construction Trades
Department, or BCTD, of the AFL-CIO to provide skilled union labor to construct STP Units 3 and 4.
The BCTD is an alliance of 13 national and international unions that collectively represent over
two million skilled craft professionals in the U.S. and Canada.
On May 10, 2010, NINA and TEPCO Nuclear Energy America LLC, or TNEA, a wholly-owned subsidiary
of The Tokyo Electric Power Company of Japan, Inc., signed an Investment and Option Agreement
whereby TNEA agreed to acquire up to a 20% interest in NINA Investments Holdings LLC, or Holdings.
See Note 15, Commitments and Contingencies, to this Form 10-Q for further discussion.
Thermal Acquisition
Northwind Phoenix, LLC On June 22, 2010, NRG, through its wholly-owned subsidiary NRG
Thermal LLC, or NRG Thermal, acquired Northwind Phoenix, LLC, or Northwind Phoenix. Northwind
Phoenix owns and operates one of the newest district cooling systems in the United States,
providing chilled water to commercial buildings in the Phoenix central business district. In
addition to the local business district, Northwind Phoenix also maintains and operates Combined
Heat and Power, or CHP, plants that provide chilled water, steam and electricity to portions of
Arizona State University campuses in Tempe and Mesa, and in metropolitan Tucson, including that
citys convention center.
Renewable Development and Acquisitions
As part of its core strategy, NRG intends to invest significantly in the development and
acquisition of renewable energy projects, including wind, solar and biomass. NRGs renewable
strategy is intended to capitalize on first mover advantage in a high growth segment of our
business, the Companys existing regional presence in regions with attractive renewable resources
and the prevalence, in the Companys core markets, of state-mandated renewable portfolio standards.
The Companys renewable projects tend to be smaller and more numerous than its conventional
utility-sized projects. As a result, a brief description of the Companys development efforts in
respect of each renewable technology follows.
98
Solar
NRG is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar
thermal technologies. Specifically, NRG has projects that have entered into off-take arrangements
with Southern California Edison, Pacific Gas & Electric, El Paso Electric, and Tucson Electric
Power, each of which will utilize either PV, or solar thermal. While each of these projects has a
PPA in place, the development of these projects is subject to certain regulatory approvals,
conditions and milestones which may affect the Companys decision to pursue further development of
one or more of these projects.
Consistent with its business strategy, NRG is currently focused on early stage development
efforts in a number of markets as well as conducting due diligence with respect to various equity
investment opportunities for solar projects utilizing solar technologies that range from
concentrated solar thermal to PV. In June 2010, NRG acquired a 450 MW pipeline of solar
development projects from US Solar Ventures, an affiliate of Arclight Capital Partners, LLC. These
development projects, which range in size from 20 MW to 99 MW, and have the potential to be
operational between 2011 and 2013, do not at present have PPAs but they have site control and
interconnection rights which NRG deems to be very valuable. This acquisition increases NRGs solar
projects under development to 1,150 MW.
NRGs efforts to date have focused on larger (by renewable standards) utility sized solar
projects. However, the Company does intend to be involved, to at least some degree, in smaller
scale distributed solar in one or more of its core domestic markets.
Wind
Terrestrial Wind
On June 14, 2010, NRG acquired South Trent Wind LLC, owner of the South Trent wind farm, or
South Trent, a 101 MW wind farm near Sweetwater, Texas. South Trent commenced operations in
January 2009 and consists of 44 turbines producing up to 2.3 MW of power each. The project has a
20-year PPA which commenced in January 2009 for all generation from the site.
Offshore Wind
On April 26, 2010, the U.S. Department of Interior through its newly created Bureau of Ocean
Energy Management, Regulation and Enforcement issued a request for interest, or RFI, in obtaining
one or more commercial leases for the construction of a wind energy project on the Outer
Continental Shelf off the coast of Delaware. The RFI process will determine if there is
competitive interest in building on an ocean tract starting 7.5 miles due east of Rehoboth Beach,
Delaware. NRG Bluewater Holdings LLC, or NRG Bluewater, plans to build the Mid-Atlantic Wind Park
in an area inside this zone 13 miles from shore, running to more than 20 miles from shore for the
farthest turbine. On June 25, 2010, NRG Bluewater, through its subsidiary Bluewater Wind Delaware
LLC filed a response to the RFI.
Biomass
In April 2010, the Company was awarded a 10-year contract from the New York State Energy
Research and Development Authority for power generated using renewable biomass fuel at its Dunkirk
Generating Station in western New York. The project will produce up to 15 MW of the stations
total output by co-firing with clean wood biomass. The award was part of a competitive
solicitation to award contracts for projects that deliver renewable energy to the New York
wholesale power market and which will help the state reach its RPS goal to increase the proportion
of renewable electricity sold in New York from 25 percent to 30 percent by 2015.
In addition to the Dunkirk project, NRG has a biomass project under development at its
Montville Generating Station. The project would involve the repowering one of the facilitys
existing units to produce up to 40 MW of electricity from locally sourced biomass. The project has
received approval from the Connecticut Siting Council, and in April 2010 was awarded an air permit
from the Connecticut Department of Environmental Protection. The Company is pursuing opportunities
to sell the power on the New England power grid which will also help the state toward reaching its
goal of 20 percent of electricity in the state generated by a Class-1 fuel source.
99
Off-Balance Sheet Arrangements
Obligations under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of
business to facilitate commercial transactions with third parties. These arrangements include
financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. See Note 26, Guarantees, to the Companys 2009 Form 10-K for additional
discussion.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an
unconsolidated entity.
Derivative Instrument Obligations
The Companys 3.625% Preferred Stock includes a feature which is considered an embedded
derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from
derivative accounting as it is excluded from the scope pursuant to ASC 815. As of June 30, 2010,
based on the Companys stock price, the embedded derivative was out-of-the-money and had no
redemption value.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable Interest in Equity Investments As of June 30, 2010, 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. Two of these investments, GenConn Energy LLC
and Sherbino, are variable interest entities for which NRG is not the primary beneficiary.
NRGs pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately
$126 million as of June 30, 2010. This indebtedness may restrict the ability of these subsidiaries
to issue dividends or distributions to NRG.
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 Annual Report on Form 10-K for the year ended December 31, 2009. Also
see Note 15, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments
and contingencies that also include contractual obligations and commercial commitments that
occurred during the six months ended June 30, 2010.
100
Critical Accounting Policies and Estimates
NRGs discussion and analysis of the financial condition and results of operations are based
upon the consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States. The preparation of these financial statements
and related disclosures in compliance with generally accepted accounting principles, or GAAP,
requires the application of appropriate technical accounting rules and guidance as well as the use
of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosures of contingent assets and liabilities. The application of these
policies necessarily involves judgments regarding future events, including the likelihood of
success of particular projects and legal and regulatory challenges. These judgments, in and of
themselves, could materially affect the financial statements and disclosures based on varying
assumptions, which may be appropriate to use. In addition, the financial and operating environment
may also have a significant effect, not only on the operation of the business, but on the results
reported through the application of accounting measures used in preparing the financial statements
and related disclosures, even if the nature of the accounting policies have not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience,
consultation with experts and other methods the Company considers reasonable. In any event, actual
results may differ substantially from the Companys estimates. Any effects on the Companys
business, financial position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision become known.
Critical accounting policies and estimates 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
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, contingencies and accounting for unbilled revenues.
As described in Critical Accounting Policies and Estimates Goodwill and Other Intangible
Assets, in the Companys Annual Report on Form 10-K for the year ended December 31, 2009, the
Company believes that assumptions about future power prices most significantly impact the fair
value of its Texas reporting unit. The price of natural gas plays an important role in setting the
price of electricity in many of the regions where NRG operates power plants, and forward natural
gas prices have continued to decline since year-end 2009. At December 31, 2009, the Company
estimated the fair value of NRG Texas invested capital to exceed its carrying value by
approximately 25%. Assuming all other factors held constant, a hypothetical $1 drop in the
Companys long-term natural gas price view used in that estimate would not have caused the fair
value of NRG Texas to fall below its carrying value, but would have significantly reduced the
excess fair value over carrying value. If long-term natural gas prices remain depressed or
continue to drop for an extended period of time, the Companys goodwill may become impaired in the
future, which would result in a charge against earnings.
101
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,
liquidity risk, credit 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,
volatilities, and correlations between various commodities, such as natural gas, electricity, coal,
oil, and emissions credits. A number of factors influence the level and volatility of prices for
energy commodities and related derivative products. These factors include:
|
|
|
Seasonal, daily and hourly changes in demand; |
|
|
|
|
Extreme peak demands due to weather conditions; |
|
|
|
|
Available supply resources; |
|
|
|
|
Transportation availability and reliability within and between regions; and |
|
|
|
|
Changes in the nature and extent of federal and state regulations. |
NRGs portfolio consists of generation assets and wholesale transactions load serving
obligations. NRG manages the commodity price risk of the Companys merchant generation operations
and load serving obligations by entering into various derivative or non-derivative instruments to
hedge the variability in future cash flows from forecasted sales and purchases of electricity and
fuel. These instruments include forwards, futures, swaps, and option contracts traded on various
exchanges, such as New York Mercantile Exchange, or NYMEX, and Intercontinental Exchange, or ICE,
as well as over-the-counter financial markets. The portion of forecasted transactions hedged may
vary based upon managements assessment of market, weather, the projected operations of the
Companys generation assets 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 those derivative contracts. However, it is
likely that future market prices could vary from those used in recording mark-to-market derivative
instrument valuation, and such variations could be material.
NRG measures the risk of the Companys portfolio using several analytical methods, including
sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. VaR
is a statistical model that attempts to predict risk of loss based on market price and volatility.
Currently, the company estimates VaR using a Monte Carlo simulation based methodology.
102
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.
As of June 30, 2010, 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 for the three and six
months ended June 30, 2010, and 2009:
|
|
|
|
|
|
|
|
|
(In millions) |
|
2010 |
|
2009 |
|
VaR as of June 30 |
|
$ |
51 |
|
|
$ |
49 |
|
|
Three months ended June 30: |
|
|
|
|
|
|
|
|
Average |
|
$ |
58 |
|
|
$ |
35 |
|
Maximum |
|
|
70 |
|
|
|
54 |
|
Minimum |
|
|
46 |
|
|
|
28 |
|
|
Six months ended June 30: |
|
|
|
|
|
|
|
|
Average |
|
$ |
53 |
|
|
$ |
38 |
|
Maximum |
|
|
70 |
|
|
|
54 |
|
Minimum |
|
|
37 |
|
|
|
28 |
|
|
Due to the inherent limitations of statistical measures such as VaR, the evolving nature of
the competitive markets for electricity and related derivatives, and the seasonality of changes in
market prices, the VaR calculation may not capture the full extent of commodity price exposure. As
a result, actual changes in the fair value of mark-to-market energy assets and liabilities could
differ from the calculated VaR, and such changes could have a material impact on the Companys
financial results.
In order to provide additional information for comparative purposes to NRGs peers, the
Company also uses VaR to estimate the potential loss of derivative financial instruments that are
subject to mark-to-market accounting. These derivative instruments include transactions that were
entered into for both asset management and trading purposes. The VaR for the derivative financial
instruments calculated using the diversified VaR model as of June 30, 2010, for the entire term of
these instruments entered into for both asset management and trading, was approximately $21 million
primarily driven by asset-backed transactions.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through the Companys issuance of fixed rate
and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into
derivative instruments known as interest rate swaps, caps, collars and put or call options. These
contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt
obligations when taking into account the combination of the variable rate debt and the interest
rate derivative instrument. NRGs risk management policies allow the Company to reduce interest
rate exposure from variable rate debt obligations.
In May 2009, NRG entered into a series of forward-starting interest rate swaps. These
interest rate swaps become effective on April 1, 2011, and are intended to hedge the risks
associated with floating interest rates. For each of the interest rate swaps, the Company will pay
its counterparty the equivalent of a fixed interest payment on a predetermined notional value, and
NRG receives the monthly equivalent of a floating interest payment based on a 1-month LIBOR
calculated on the same notional value. All interest rate swap payments by NRG and its
counterparties are made monthly and the LIBOR is determined in advance of each interest period.
The total notional amount of these swaps is $900 million. The swaps mature on February 1, 2013.
In June 2010, in connection with the Blythe and South Trent financing transactions (see Note
8, Long-Term Debt), the Company entered into a series of current and forward-starting interest rate
swaps, intended to hedge the risks associated with floating interest rates. These swaps, which
have a combined notional value of $103 million, mature on various dates through 2028.
103
As of June 30, 2010, the Company had various interest rate swap agreements with notional
amounts totaling approximately $3.2 billion. If the swaps had been discontinued on June 30, 2010,
the Company would have owed the counterparties approximately $110 million. Based on the investment
grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance
by counterparties to its hedge contracts to be immaterial.
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 June 30, 2010, a 1% change in
interest rates would result in a $12 million change in interest expense on a rolling twelve month
basis.
As of June 30, 2010, the Companys long-term debt fair value was $8 billion and the carrying
amount was $8.1 billion. NRG estimates that a 1% decrease in market interest rates would have
increased the fair value of the Companys long-term debt by $419 million.
Liquidity Risk
Liquidity risk arises from the general funding needs of NRGs activities and in the management
of the Companys assets and liabilities. NRGs liquidity management framework is intended to
maximize liquidity access and minimize funding costs. Through active liquidity management, the
Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the
Company to replace maturing obligations when due and fund assets at appropriate maturities and
rates. To accomplish this task, management uses a variety of liquidity risk measures that take
into consideration market conditions, prevailing interest rates, liquidity needs, and the desired
maturity profile of liabilities. The Company is currently exposed to additional collateral posting
if natural gas prices decline primarily due to the long natural gas equivalent position at various
exchanges used to hedge NRGs retail supply load obligations.
Based on a sensitivity analysis for power and gas positions under marginable contracts, a $1
per MMBtu change in natural gas prices across the term of the marginable contracts would cause a
change in margin collateral posted of approximately $155 million as of June 30, 2010, and a 0.25
MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin
collateral posted of approximately $28 million as of June 30, 2010. This analysis uses simplified
assumptions and is calculated based on portfolio composition and margin-related contract provisions
as of June 30, 2010.
Under the second lien, NRG is required to post certain letters of credit as credit support for
changes in commodity prices. As of June 30, 2010, no letters of credit are outstanding to second
lien counterparties. With changes in commodity prices, the letters of credit could grow to $64
million, the cap under the agreements.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by
counterparties pursuant to the terms of their contractual obligations. NRG is exposed to
counterparty credit risk through various activities including wholesale sales, fuel purchases and
retail supply and retail customer credit risk through its retail load activities.
Counterparty Credit Risk
The Company monitors and manages counterparty 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 credit risk with a diversified portfolio of counterparties.
The Company also has credit protection within various agreements to call on additional collateral
support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk
of the counterparty until positions settle.
As of June 30, 2010, total counterparty credit exposure to substantially all counterparties
was $1.5 billion and NRG held cash collateral against those positions of $310 million resulting in
a net exposure of $1.2 billion. Total counterparty credit exposure is discounted at the risk free
rate.
104
The following table highlights the credit quality and the net counterparty credit exposure by
industry sector. Net counterparty credit exposure is defined as the aggregate net asset position
for NRG with counterparties where netting is permitted under the enabling agreement and includes
all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net
of collateral held, includes amounts net of receivables or payables.
|
|
|
|
|
|
|
Net Exposure(a) |
Category |
|
(% of Total) |
|
Financial institutions |
|
|
59 |
% |
Utilities, energy, merchants, marketers and other |
|
|
31 |
|
Coal suppliers |
|
|
4 |
|
ISOs |
|
|
6 |
|
|
Total as of June 30, 2010 |
|
|
100 |
% |
|
|
|
|
|
|
|
|
Net Exposure(a) |
Category |
|
(% of Total) |
|
Investment grade |
|
|
88 |
% |
Non-Investment grade |
|
|
2 |
|
Non-rated |
|
|
10 |
|
|
Total as of June 30, 2010 |
|
|
100 |
% |
|
|
|
|
(a) |
|
Counterparty credit exposure excludes California tolling, Northeast load obligations,
certain cooperative load contracts, and Texas Westmoreland coal contracts. The aforementioned
exposures were excluded for various reasons including regulatory support or liens held against
the contracts which serve to reduce the risk of loss. NRG also excludes uranium and coal
transportation contracts from counterparty credit exposure because of the illiquidity of the
reference markets. Credit exposure also excludes any exposure NRG has to counterparties of
non-recourse subsidiaries. |
NRG has counterparty credit risk exposure to certain counterparties representing more
than 10% of total net exposure and the aggregate of such counterparties was $409 million.
Approximately 89% of NRGs positions relating to credit risk roll-off by the end of 2012. Changes
in hedge positions and market prices will affect credit exposure and counterparty concentration.
Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not
anticipate a material impact on the Companys financial results from nonperformance by any of NRGs
counterparties.
Retail Customer Credit Risk
NRG is exposed to retail credit risk through the Companys competitive electricity supply
business, which serves C&I customers and the Mass market in Texas. Retail credit risk results when
a customer fails to pay for services rendered. The losses could be incurred from nonpayment of
customer accounts receivable and any in-the-money forward value. NRG manages retail credit risk
through the use of established credit policies that include monitoring of the portfolio, and the
use of credit mitigation measures such as deposits or prepayment arrangements.
As of June 30, 2010, the Companys retail customer credit exposure to C&I customers was
diversified across many customers and various industries, with a significant portion of the
exposure with government entities.
NRG is also exposed to retail customer credit risk relating to its Mass customers, which may
result in a write-off of bad debt. During 2010, the Company continued to experience improved
customer payment behavior, but current economic conditions may affect the Companys customers
ability to pay bills in a timely manner, which could increase customer delinquencies and may lead
to an increase in bad debt expense.
Credit Risk Contingent Features
Certain of the Companys hedging agreements contain provisions that require the Company to
post additional collateral if the counterparty determines that there has been deterioration in
credit quality, generally termed adequate assurance under the agreements or require the Company
to post additional collateral if there was a one notch downgrade in the Companys credit rating.
The collateral required for contracts that have adequate assurance clauses that are in a net
liability position as of June 30, 2010, was $63 million. The collateral required for contracts
with credit rating contingent features that are in a net liability position as of June 30, 2010,
was $11 million. The Company is also a party to certain marginable agreements where NRG has a net
liability position but the counterparty has not called for the collateral due, which is
approximately $15 million as of June 30, 2010.
105
Fair Value of Derivative Instruments
NRG may enter into long-term power purchase and sales contracts, fuel purchase contracts and
other energy-related financial instruments to mitigate variability in earnings due to fluctuations
in spot market prices and to hedge fuel requirements at generation facilities. 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 are subject to limits within 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.
The tables below disclose the activities that include both exchange and non-exchange traded
contracts accounted for at fair value in accordance with ASC-820, Fair Value Measurements and
Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes
in fair value; disaggregate estimated fair values at June 30, 2010, based on their level within the
fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2010.
|
|
|
|
|
Derivative Activity Gains/(Losses) |
|
(In millions) |
|
Fair value of contracts as of December 31, 2009 |
|
$ |
459 |
|
Contracts realized or otherwise settled during the period |
|
|
(149 |
) |
Changes in fair value |
|
|
483 |
|
|
Fair value of contracts as of June 30, 2010 |
|
$ |
793 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of June 30, 2010 |
|
|
Maturity |
|
|
|
|
|
|
|
|
|
Maturity |
|
|
(In millions) |
|
Less Than |
|
Maturity |
|
Maturity |
|
in Excess |
|
Total Fair |
Fair value hierarchy gains/(losses) |
|
1 Year |
|
1-3 Years |
|
4-5 Years |
|
4-5 Years |
|
Value |
|
Level 1 |
|
$ |
14 |
|
|
$ |
(46 |
) |
|
$ |
(20 |
) |
|
$ |
|
|
|
$ |
(52 |
) |
Level 2 |
|
|
386 |
|
|
|
499 |
|
|
|
76 |
|
|
|
(40 |
) |
|
|
921 |
|
Level 3 |
|
|
(84 |
) |
|
|
(3 |
) |
|
|
11 |
|
|
|
|
|
|
|
(76 |
) |
|
Total |
|
$ |
316 |
|
|
$ |
450 |
|
|
$ |
67 |
|
|
$ |
(40 |
) |
|
$ |
793 |
|
|
A small portion of NRGs contracts are exchange-traded contracts with readily available quoted
market prices. The majority of NRGs contracts are non-exchange-traded contracts valued using
prices provided by external sources, primarily price quotations available through brokers or
over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives
quotes from multiple sources. To the extent that NRG receives multiple quotes, the Companys
prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG
believes provide the most liquid market for the commodity. If the Company receives one quote then
the mid point of the bid-ask spread for that quote is used. The terms for which such price
information is available vary by commodity, region and product. A significant portion of the fair
value of the Companys derivative portfolio is based on price quotes from brokers in active markets
who regularly facilitate the Companys transactions and the Company believes such price quotes are
executable. The Company does not use third party sources that derive price based on proprietary
models or market surveys. The remainder of the assets and liabilities represents 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 10% 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 after cash collateral paid/received under a specific master agreement is an
asset, the Company calculates credit reserve applying the counterpartys default swap rate. If the
net exposure after cash collateral paid/received under a specific master agreement is a liability,
the Company calculates credit reserve applying NRGs default swap rate. The credit reserve is
added to the discounted fair value to reflect the exit price that a market participant would be
willing to receive to assume NRGs liabilities or that a market participant would be willing to pay
for NRGs assets. As of June 30, 2010, the credit reserve resulted in a $11 million decrease in
fair value which is composed of a $6 million loss in OCI and a $5 million loss in derivative
revenue and cost of operations.
106
The fair values in each category reflect the level of forward prices and volatility factors as
of June 30, 2010, 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.
The Company has elected to disclose derivative assets and liabilities on a trade-by-trade
basis and does not offset amounts at the counterparty master agreement level. Also, collateral
received or paid on the Companys derivative assets or liabilities are recorded on a separate line
item on the balance sheet. Consequently, the magnitude of the changes in individual current and
non-current derivative assets or liabilities is higher than the underlying credit and market risk
of the Companys portfolio. As discussed in Item 6A Quantitative and Qualitative Disclosures
about Market Risk, Commodity Price Risk in the Companys Annual Report on Form 10-K for the fiscal
year ended December 31, 2009, 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. As the Companys trade-by-trade
derivative accounting results in a gross-up of the Companys derivative assets and liabilities, the
net derivative assets and liability position is a better indicator of NRGs hedging activity. As
of June 30, 2010, NRGs net derivative asset was $793 million, an increase to total fair value of
$334 million as compared to December 31, 2009. This increase was primarily driven by the decreases
in gas and power prices and the roll-off of trades that settled during the period.
Based on a sensitivity analysis, the impact of a $1 per MMBtu increase or decrease in natural
gas prices across the term of the derivative contracts would cause a change of approximately $299
million in the net value of derivatives as of June 30, 2010.
Currency Exchange Risk
NRG may be subject to foreign currency exchange 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. As of June 30, 2010, there were no foreign currency options or forward contracts
outstanding for purchase commitments. As a result of the Companys limited foreign currency
exposure to date, the effect of foreign currency fluctuations has not been material to the
Companys results of operations, financial position and cash flows as of and for the six months
ended June 30, 2010.
107
ITEM 4 CONTROLS AND PROCEDURES
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of NRGs management, including its principal
executive officer, principal financial officer and principal accounting officer, NRG conducted an
evaluation of the effectiveness of the design and operation of its disclosure controls and
procedures, as such term is defined in Rules 13a-15(e) 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 were no changes in the Companys internal controls over financial reporting (as such
term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the second quarter of
2010 that 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.
108
PART II OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through June 30,
2010, see Note 15, Commitments and Contingencies, to the condensed consolidated financial
statements of this Form 10-Q.
ITEM 1A RISK FACTORS
Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG
Energy, Inc. in NRG Energy, Inc.s Annual Report on Form 10-K for the fiscal year ended December
31, 2009.
ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
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Dollar value of |
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Total number of shares |
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shares that may be |
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purchased as part of |
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purchased under the |
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Total number of |
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Average price |
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publicly announced |
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2010 Capital Allocation |
For the period ended June 30, 2010 |
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shares purchased |
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paid per share |
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plans or programs |
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Plan |
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First quarter 2010 |
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$ |
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|
|
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$ |
180,000,000 |
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April 1 April 30 |
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|
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180,000,000 |
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May 1 May 31 |
|
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800,500 |
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|
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21.17 |
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|
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800,500 |
|
|
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162,244,791 |
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June 1 June 30 |
|
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1,413,500 |
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|
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22.80 |
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|
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1,413,500 |
|
|
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130,002,304 |
|
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Second quarter 2010 Total |
|
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2,214,000 |
|
|
|
22.57 |
|
|
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2,214,000 |
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|
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130,002,304 |
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Year-to-date |
|
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2,214,000 |
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$ |
22.57 |
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|
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2,214,000 |
|
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$ |
130,002,304 |
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|
On February 23, 2010, the Company announced a plan to repurchase $180 million of common stock
under the Companys 2010 Capital Allocation Plan. The Company repurchased $50 million of common
stock during the period ended June 30, 2010. NRG intends to complete its $180 million of share
repurchases by the end of 2010, subject to market prices, financial restrictions under the
Companys debt facilities and as permitted by securities laws.
ITEM 3 DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 (REMOVED AND RESERVED)
ITEM 5 OTHER INFORMATION
None.
109
ITEM 6 EXHIBITS
Exhibits
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4.1
|
|
Twenty-Eighth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
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4.2
|
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Twenty-Ninth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
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4.3
|
|
Thirtieth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.4
|
|
Thirty-First Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.5
|
|
Thirty-Second Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
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4.6
|
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Thirty-Third Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
|
4.7
|
|
Thirty-Fourth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
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4.8
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Thirty-Fifth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
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10.1
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Chief Financial Officer Compensation Table for 2010. (3) |
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10.2
|
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2009 Executive Change-in-Control and General Severance Plan. (3) |
|
|
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10.3*
|
|
Investment and Option Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America
Investments Holdings LLC and TEPCO Nuclear Energy America LLC, dated as of May 10, 2010, filed herewith. |
|
|
|
10.4*
|
|
Parent Company Agreement by and among NRG Energy, Inc., Nuclear Innovation North America LLC, TEPCO and TEPCO
Nuclear Energy America LLC, dated as of May 10, 2010, filed herewith. |
|
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10.5
|
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Third Amended and Restated Credit Agreement, dated as of June 30, 2010. (4) |
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10.6(a)
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Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010. (4) |
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10.6(b)
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Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010. (4) |
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31.1
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Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
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31.2
|
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Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
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31.3
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Certification of Chief Accounting Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
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32
|
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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. |
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(1) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on
April 21, 2010. |
|
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on June
29, 2010. |
|
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on
April 1, 2010. |
|
(4) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on July
1, 2010. |
|
* |
|
Portions of this exhibit have been redacted and are subject to a confidential treatment request filed with the Securities and Exchange Commission pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. |
110
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.
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NRG ENERGY, INC.
(Registrant)
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/s/ DAVID W. CRANE
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David W. Crane |
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Chief Executive Officer
(Principal Executive Officer) |
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/s/ CHRISTIAN S. SCHADE
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Christian S. Schade |
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Chief Financial Officer
(Principal Financial Officer) |
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/s/ JAMES J. INGOLDSBY
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James J. Ingoldsby |
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Date: August 2, 2010 |
Chief Accounting Officer
(Principal Accounting Officer) |
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111
EXHIBIT INDEX
Exhibits
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|
|
4.1
|
|
Twenty-Eighth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.2
|
|
Twenty-Ninth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.3
|
|
Thirtieth Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.4
|
|
Thirty-First Supplemental Indenture, dated as of April 16, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.5
|
|
Thirty-Second Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
|
4.6
|
|
Thirty-Third Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
|
4.7
|
|
Thirty-Fourth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
|
4.8
|
|
Thirty-Fifth Supplemental Indenture, dated as of June 23, 2010, among NRG Energy, Inc., the existing guarantors
named therein, the guaranteeing subsidiaries named therein and Law Debenture Trust Company of New York. (2) |
|
|
|
10.1
|
|
Chief Financial Officer Compensation Table for 2010. (3) |
|
|
|
10.2
|
|
2009 Executive Change-in-Control and General Severance Plan. (3) |
|
|
|
10.3*
|
|
Investment and Option Agreement by and among Nuclear Innovation North America LLC, Nuclear Innovation North America
Investments Holdings LLC and TEPCO Nuclear Energy America LLC, dated as of May 10, 2010, filed herewith. |
|
|
|
10.4*
|
|
Parent Company Agreement by and among NRG Energy, Inc., Nuclear Innovation North America LLC, TEPCO and TEPCO
Nuclear Energy America LLC, dated as of May 10, 2010, filed herewith. |
|
|
|
10.5
|
|
Third Amended and Restated Credit Agreement, dated as of June 30, 2010. (4) |
|
|
|
10.6(a)
|
|
Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010. (4) |
|
|
|
10.6(b)
|
|
Letter of Credit and Reimbursement Agreement, dated as of June 30, 2010. (4) |
|
|
|
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. |
|
|
|
(1) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on
April 21, 2010. |
|
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on June
29, 2010. |
|
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on
April 1, 2010. |
|
(4) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on July
1, 2010. |
|
* |
|
Portions of this exhibit have been redacted and are subject
to a confidential treatment request filed with the Securities and
Exchange Commission pursuant to Rule 24b-2 under the Securities
Exchange Act of 1934, as amended. |
112