e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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o |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended: June 30, 2009
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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41-1724239
(I.R.S. Employer
Identification No.) |
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211 Carnegie Center Princeton, New Jersey
(Address of principal executive offices)
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08540
(Zip Code) |
(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 o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the
Exchange Act. (Check one):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
Indicate by check mark whether the registrant has filed all documents and reports required to
be filed by 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 28, 2009, there were 265,276,841 shares of common stock outstanding, par value
$0.01 per share.
TABLE OF CONTENTS
Index
2
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, 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, 2008 and
Risk Factors in Part II, Item 1A, of this Quarterly Report on Form 10-Q, 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 achieve its strategy of regularly returning capital to shareholders;
and |
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NRGs ability to successfully integrate and manage any acquired companies. |
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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APB
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Accounting Principles Board |
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Baseload capacity
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Electric power generation capacity normally expected to serve loads on an
around-the-clock basis throughout the calendar year |
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BTA
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Best Technology Available |
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BTU
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British Thermal Unit |
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CAA
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Clean Air Act |
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CAIR
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Clean Air Interstate Rule |
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CAISO
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California Independent System Operator |
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Capital Allocation Plan
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Share repurchase program |
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Capital Allocation Program
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NRGs plan of allocating capital between debt reduction, reinvestment in the
business, and share repurchases through the Capital Allocation Plan |
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CDWR
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California Department of Water Resources |
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C&I
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Commercial, industrial and governmental/institutions |
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CL&P
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The Connecticut Light & Power Company |
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CO2
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Carbon dioxide |
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CS
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Credit Suisse Group |
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CSF I
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NRG Common Stock Finance I LLC |
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CSF II
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NRG Common Stock Finance II LLC |
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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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DNREC
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Delaware Department of Natural Resources and Environmental Control |
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DPUC
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Department of Public Utility Control |
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EITF
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Emerging Issues Task Force |
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EITF 07-5
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EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is
Indexed to an Entitys Own Stock |
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EITF 08-5
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EITF No. 08-5, Issuers Accounting for Liabilities Measured at Fair Value with
a Third-Party Credit Enhancement |
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EITF 08-6
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EITF No. 08-6, Equity Method Investment Accounting Considerations |
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EITF 09-1
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EITF No. 09-1, Accounting for Own-Share Lending Arrangements in Contemplation
of Convertible Debt Issuance or Other Financing |
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EPC
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Engineering, Procurement and Construction |
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ERCOT
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Electric Reliability Council of Texas, the Independent System Operator and the
Regional Reliability Coordinator of the various electricity systems within Texas |
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ESPP
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Employee Stock Purchase Plan |
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Exchange Act
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The Securities Exchange Act of 1934, as amended |
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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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FIN
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FASB Interpretation |
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FIN 46R
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FIN No. 46(R), Consolidation of Variable Interest Entities (revised 2003)an
interpretation of ARB No. 51 |
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FIN 48
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FIN No. 48, Accounting for Uncertainty in Income Taxes |
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Fresh Start
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Reporting requirements as defined by SOP 90-7 |
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FSP
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FASB Staff Position |
4
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GLOSSARY OF TERMS (continued) |
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FSP FAS 107-1 and APB 28-1
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FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of
Financial Instruments |
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FSP FAS 115-2 and FAS 124-2
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FSP No. FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments |
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FSP FAS 132R-1
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FSP No. FAS 132(R)-1, Employers Disclosures about Postretirement Benefit Plan
Assets |
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FSP FAS 141R-1
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FSP No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in
a Business Combination That Arise from Contingencies |
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FSP FAS 142-3
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FSP No. FAS 142-3, Determination of the Useful Life of Intangible Asset |
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FSP FAS 157-2
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FSP No. FAS 157-2, Effective Date of FASB Statement No. 157 |
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FSP FAS 157-4
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FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity
for the Asset or Liability Have Significantly Decreased and Identifying
Transactions That Are Not Orderly |
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GHG
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Greenhouse Gases |
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Gross Generation
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The total amount of electric energy produced by generating units and measured at
the generating terminal in kWhs or MWhs |
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Heat Rate
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A measure of thermal efficiency computed by dividing the total BTU content of
the fuel burned by the resulting kWhs generated. Heat rates can be expressed as
either gross or net heat rates, depending whether the electricity output
measured is gross or net generation and is generally expressed as BTU per net
kWh. |
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IGCC
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Integrated Gasification Combined Cycle |
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IRS
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Internal Revenue Service |
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ISO
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Independent System Operator, also referred to as Regional Transmission
Organizations, or RTO |
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ISO-NE
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ISO New England Inc. |
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ITISA
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Itiquira Energetica S.A. |
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kV
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Kilovolts |
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kW
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Kilowatts |
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kWh
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Kilowatt-hours |
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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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Market usage adjustments
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The revenues and the related energy supply costs in the Reliant Energy segment
includes the Companys estimates of customer usage based on initial usage
information provided by the independent system operators and the distribution
companies. The Company revises these estimates and records any changes in the
period as additional settlement information becomes available. |
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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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MRTU
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Market Redesign and Technology Upgrade |
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MVA
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Megavolt-ampere |
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MW
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Megawatts |
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MWh
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Saleable megawatt hours net of internal/parasitic load megawatt-hours |
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MWt
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Megawatts Thermal |
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NAAQS
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National Ambient Air Quality Standards |
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NEPOOL
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New England Power Pool |
5
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GLOSSARY OF TERMS (continued) |
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Net Capacity Factor
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The net amount of electricity that a generating unit produces over a period of time
divided by the net amount of electricity it could have produced if it had run at full
power over that time period. The net amount of electricity produced is the total amount of
electricity generated minus the amount of electricity used during generation. |
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Net Exposure
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Counterparty credit exposure to NRG, net of collateral |
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Net Generation
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The net amount of electricity produced, expressed in kWhs or MWhs, that is the total
amount of electricity generated (gross) minus the amount of electricity used during
generation. |
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NINA
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Nuclear Innovation North America LLC |
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NOx
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Nitrogen oxide |
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NOL
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Net Operating Loss |
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NOV
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Notice of Violation |
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NPNS
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Normal Purchase Normal Sale |
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NRC
|
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United States Nuclear Regulatory Commission |
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NSR
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New Source Review |
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NYISO
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New York Independent System Operator |
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OCI
|
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Other Comprehensive Income |
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Padoma
|
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Padoma Wind Power LLC |
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Phase II 316(b) Rule
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A section of the Clean Water Act regulating cooling water intake structures |
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PJM
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PJM Interconnection, LLC |
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PJM market
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The wholesale and retail electric market operated by PJM primarily in all or parts of
Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio, Pennsylvania,
Virginia and West Virginia |
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PMI
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NRG Power Marketing, LLC, a wholly-owned subsidiary of NRG which procures transportation
and fuel for the Companys generation facilities, sells the power from these facilities,
and manages all commodity trading and hedging for NRG |
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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
|
|
NRGs retail business in Texas purchased on May 1, 2009 from Reliant Energy, Inc. which is
now known as RRI Energy, Inc. |
|
Repowering
|
|
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 |
|
RepoweringNRG
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NRGs program designed to develop, finance, construct and operate new, highly efficient,
environmentally responsible capacity over the next decade |
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Revolving Credit Facility
|
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NRGs $1 billion senior secured revolving credit facility which matures on February 2, 2011 |
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RGGI
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|
Regional Greenhouse Gas Initiative |
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ROIC
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Return on Invested Capital |
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RPM
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Reliability Pricing Model term for capacity market in PJM market |
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RTO
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Regional Transmission Organization, also referred to as an Independent System Operator, or
ISO |
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S&P
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Standard & Poors, a credit rating agency |
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Sarbanes-Oxley
|
|
Sarbanes-Oxley Act of 2002 (as amended) |
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SEC
|
|
United States Securities and Exchange Commission |
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Securities Act
|
|
The Securities Act of 1933, as amended |
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Senior Credit Facility
|
|
NRGs senior secured facility, which is comprised of a Term Loan Facility and a $1.3
billion Synthetic Letter of Credit Facility which mature on February 1, 2013, and a $1
billion Revolving Credit Facility, which matures on February 2, 2011 |
6
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|
GLOSSARY OF TERMS (continued) |
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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 |
|
SFAS
|
|
Statement of Financial Accounting Standards issued by the FASB |
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SFAS 133
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SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities as amended |
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SFAS 141R
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SFAS No. 141 (revised 2007), Business Combinations |
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SFAS 157
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SFAS No. 157, Fair Value Measurement |
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SFAS 160
|
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SFAS No. 160, Noncontrolling Interest in Consolidated Financial Statements |
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SFAS 161
|
|
SFAS No. 161, Disclosure about Derivative Instruments and Hedging Activities an
amendment of FASB Statement No. 133 |
|
SFAS 165
|
|
SFAS No. 165, Subsequent Events |
|
SFAS 167
|
|
SFAS No. 167, Amendments to FASB Interpretation No. 46(R) |
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SFAS 168
|
|
SFAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of
Generally Accepted Accounting Principles |
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Sherbino
|
|
Sherbino I Wind Farm LLC |
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SO2
|
|
Sulfur dioxide |
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SOP
|
|
Statement of Position issued by the American Institute of Certified Public Accountants |
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SOP 90-7
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Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under
the Bankruptcy Code |
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STP
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South Texas Project nuclear generating facility located near Bay City, Texas in
which NRG owns a 44% Interest |
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STPNOC
|
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South Texas Project Nuclear Operating Company |
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Synthetic Letter of Credit Facility
|
|
NRGs $1.3 billion senior secured synthetic letter of credit facility which matures on
February 1, 2013 |
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TANE
|
|
Toshiba American Nuclear Energy Corporation |
|
TANE Facility
|
|
NINAs $500 million credit facility with TANE which matures on February 24, 2012 |
|
Term Loan Facility
|
|
A senior first priority secured term loan which matures on February 1, 2013, and is
included as part of NRGs Senior Credit Facility |
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Texas Genco
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Texas Genco LLC, now referred to as the Companys Texas Region |
|
Tonnes
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Metric tonnes, which are units of mass or weight in the metric system each equal to
2,205 lbs and are the global measurement for GHG |
|
Uprate
|
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A sustainable increase in the electrical rating of a generating facility |
|
U.S.
|
|
United States of America |
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U.S. EPA
|
|
United States Environmental Protection Agency |
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U.S. GAAP
|
|
Accounting principles generally accepted in the United States |
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VaR
|
|
Value at Risk |
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WCP
|
|
WCP (Generation) Holdings, Inc. |
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) |
|
2009 |
|
|
2008 |
|
|
|
2009 |
|
|
2008 |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Total operating revenues |
|
$ |
2,237 |
|
|
$ |
1,316 |
|
|
|
$ |
3,895 |
|
|
$ |
2,618 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
1,242 |
|
|
|
1,011 |
|
|
|
|
2,008 |
|
|
|
1,815 |
|
Depreciation and amortization |
|
|
213 |
|
|
|
161 |
|
|
|
|
382 |
|
|
|
322 |
|
Selling, general and administrative |
|
|
131 |
|
|
|
83 |
|
|
|
|
214 |
|
|
|
158 |
|
Acquisition-related transaction and integration costs |
|
|
23 |
|
|
|
|
|
|
|
|
35 |
|
|
|
|
|
Development costs |
|
|
9 |
|
|
|
4 |
|
|
|
|
22 |
|
|
|
16 |
|
|
Total operating costs and expenses |
|
|
1,618 |
|
|
|
1,259 |
|
|
|
|
2,661 |
|
|
|
2,311 |
|
Operating Income |
|
|
619 |
|
|
|
57 |
|
|
|
|
1,234 |
|
|
|
307 |
|
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings/(losses) of unconsolidated affiliates |
|
|
5 |
|
|
|
(19 |
) |
|
|
|
27 |
|
|
|
(23 |
) |
Gain on sale of equity method investment |
|
|
128 |
|
|
|
|
|
|
|
|
128 |
|
|
|
|
|
Other (loss)/income, net |
|
|
(11 |
) |
|
|
12 |
|
|
|
|
(14 |
) |
|
|
21 |
|
Interest expense |
|
|
(159 |
) |
|
|
(144 |
) |
|
|
|
(297 |
) |
|
|
(300 |
) |
|
Total other expense |
|
|
(37 |
) |
|
|
(151 |
) |
|
|
|
(156 |
) |
|
|
(302 |
) |
|
Income/(Losses) From Continuing Operations Before Income Taxes |
|
|
582 |
|
|
|
(94 |
) |
|
|
|
1,078 |
|
|
|
5 |
|
Income tax expense/(benefit) |
|
|
150 |
|
|
|
(53 |
) |
|
|
|
448 |
|
|
|
1 |
|
|
Income/(Losses) From Continuing Operations |
|
|
432 |
|
|
|
(41 |
) |
|
|
|
630 |
|
|
|
4 |
|
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
|
172 |
|
|
Net Income |
|
|
432 |
|
|
|
127 |
|
|
|
|
630 |
|
|
|
176 |
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
Net income attributable to NRG Energy, Inc. |
|
|
433 |
|
|
|
127 |
|
|
|
|
631 |
|
|
|
176 |
|
|
Dividends for preferred shares |
|
|
7 |
|
|
|
14 |
|
|
|
|
21 |
|
|
|
28 |
|
|
Income Available for NRG Energy, Inc. Common Stockholders |
|
$ |
426 |
|
|
$ |
113 |
|
|
|
$ |
610 |
|
|
$ |
148 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share attributable to NRG Energy, Inc. Common Stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding basic |
|
|
253 |
|
|
|
236 |
|
|
|
|
245 |
|
|
|
236 |
|
Income/(losses) from continuing operations per weighted average common share
basic |
|
$ |
1.68 |
|
|
$ |
(0.23 |
) |
|
|
$ |
2.49 |
|
|
$ |
(0.10 |
) |
Income from discontinued operations per weighted average common share basic |
|
|
|
|
|
|
0.71 |
|
|
|
|
|
|
|
|
0.73 |
|
|
Net Income per Weighted Average Common Share Basic |
|
$ |
1.68 |
|
|
$ |
0.48 |
|
|
|
$ |
2.49 |
|
|
$ |
0.63 |
|
|
Weighted average number of common shares outstanding diluted |
|
|
275 |
|
|
|
236 |
|
|
|
|
275 |
|
|
|
236 |
|
Income/(losses) from continuing operations
per weighted average common share diluted |
|
$ |
1.56 |
|
|
$ |
(0.23 |
) |
|
|
$ |
2.27 |
|
|
$ |
(0.10 |
) |
Income from discontinued operations per weighted average common share diluted |
|
|
|
|
|
|
0.71 |
|
|
|
|
|
|
|
|
0.73 |
|
|
Net Income per Weighted Average Common Share Diluted |
|
$ |
1.56 |
|
|
$ |
0.48 |
|
|
|
$ |
2.27 |
|
|
$ |
0.63 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts attributable to NRG Energy, Inc.: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(losses) from continuing operations, net of income taxes |
|
$ |
433 |
|
|
$ |
(41 |
) |
|
|
$ |
631 |
|
|
$ |
4 |
|
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
|
172 |
|
|
Net Income |
|
$ |
433 |
|
|
$ |
127 |
|
|
|
$ |
631 |
|
|
$ |
176 |
|
|
See notes to condensed consolidated financial statements.
8
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
|
December 31, 2008 |
|
(In millions, except shares) |
|
(unaudited) |
|
|
|
|
|
|
|
ASSETS |
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
2,282 |
|
|
|
$ |
1,494 |
|
Funds deposited by counterparties |
|
|
468 |
|
|
|
|
754 |
|
Restricted cash |
|
|
19 |
|
|
|
|
16 |
|
Accounts receivable, less allowance for doubtful accounts of $12 and $3, respectively |
|
|
1,186 |
|
|
|
|
464 |
|
Inventory |
|
|
530 |
|
|
|
|
455 |
|
Derivative instruments valuation |
|
|
4,394 |
|
|
|
|
4,600 |
|
Cash collateral paid in support of energy risk management activities |
|
|
243 |
|
|
|
|
494 |
|
Prepayments and other current assets |
|
|
210 |
|
|
|
|
215 |
|
|
Total current assets |
|
|
9,332 |
|
|
|
|
8,492 |
|
|
Property, plant and equipment, net of accumulated depreciation of $2,689 and $2,343,
respectively |
|
|
11,609 |
|
|
|
|
11,545 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
Equity investments in affiliates |
|
|
363 |
|
|
|
|
490 |
|
Capital leases and note receivable, less current portion |
|
|
483 |
|
|
|
|
435 |
|
Goodwill |
|
|
1,718 |
|
|
|
|
1,718 |
|
Intangible assets, net of accumulated amortization of $327 and $335, respectively |
|
|
2,111 |
|
|
|
|
815 |
|
Nuclear decommissioning trust fund |
|
|
316 |
|
|
|
|
303 |
|
Derivative instruments valuation |
|
|
1,188 |
|
|
|
|
885 |
|
Other non-current assets |
|
|
185 |
|
|
|
|
125 |
|
|
Total other assets |
|
|
6,364 |
|
|
|
|
4,771 |
|
|
Total Assets |
|
$ |
27,305 |
|
|
|
$ |
24,808 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases |
|
$ |
453 |
|
|
|
$ |
464 |
|
Accounts payable |
|
|
857 |
|
|
|
|
451 |
|
Derivative instruments valuation |
|
|
4,196 |
|
|
|
|
3,981 |
|
Deferred income taxes |
|
|
46 |
|
|
|
|
201 |
|
Cash collateral received in support of energy risk management activities |
|
|
468 |
|
|
|
|
760 |
|
Accrued expenses and other current liabilities |
|
|
618 |
|
|
|
|
724 |
|
|
Total current liabilities |
|
|
6,638 |
|
|
|
|
6,581 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
8,294 |
|
|
|
|
7,697 |
|
Nuclear decommissioning reserve |
|
|
292 |
|
|
|
|
284 |
|
Nuclear decommissioning trust liability |
|
|
217 |
|
|
|
|
218 |
|
Deferred income taxes |
|
|
1,564 |
|
|
|
|
1,190 |
|
Derivative instruments valuation |
|
|
906 |
|
|
|
|
508 |
|
Out-of-market contracts |
|
|
378 |
|
|
|
|
291 |
|
Other non-current liabilities |
|
|
914 |
|
|
|
|
669 |
|
|
Total non-current liabilities |
|
|
12,565 |
|
|
|
|
10,857 |
|
|
Total Liabilities |
|
|
19,203 |
|
|
|
|
17,438 |
|
|
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs) |
|
|
247 |
|
|
|
|
247 |
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
|
Preferred stock (at liquidation value, net of issuance costs) |
|
|
406 |
|
|
|
|
853 |
|
Common stock |
|
|
3 |
|
|
|
|
3 |
|
Additional paid-in capital |
|
|
4,561 |
|
|
|
|
4,350 |
|
Retained earnings |
|
|
3,033 |
|
|
|
|
2,423 |
|
Less treasury stock, at cost 17,200,777 and 29,242,483 shares, respectively |
|
|
(532 |
) |
|
|
|
(823 |
) |
Accumulated other comprehensive income |
|
|
372 |
|
|
|
|
310 |
|
Noncontrolling interest |
|
|
12 |
|
|
|
|
7 |
|
|
Total Stockholders Equity |
|
|
7,855 |
|
|
|
|
7,123 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
27,305 |
|
|
|
$ |
24,808 |
|
|
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, |
|
2009 |
|
|
2008 |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
631 |
|
|
$ |
176 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Distributions and equity in (earnings)/losses of unconsolidated affiliates |
|
|
(27 |
) |
|
|
32 |
|
Depreciation and amortization |
|
|
382 |
|
|
|
322 |
|
Provision for bad debts |
|
|
9 |
|
|
|
|
|
Amortization of nuclear fuel |
|
|
19 |
|
|
|
30 |
|
Amortization of financing costs and debt discount/premiums |
|
|
21 |
|
|
|
19 |
|
Amortization of intangibles and out-of-market contracts |
|
|
15 |
|
|
|
(147 |
) |
Changes in deferred income taxes and liability for unrecognized tax benefits |
|
|
445 |
|
|
|
96 |
|
Changes in nuclear decommissioning trust liability |
|
|
15 |
|
|
|
17 |
|
Changes in derivatives |
|
|
(368 |
) |
|
|
669 |
|
Changes in collateral deposits supporting energy risk management activities |
|
|
245 |
|
|
|
(328 |
) |
(Gain)/loss on sale of assets |
|
|
(1 |
) |
|
|
2 |
|
Gain on sale of equity method investment |
|
|
(128 |
) |
|
|
|
|
Gain on sale of discontinued operations |
|
|
|
|
|
|
(270 |
) |
Gain on sale of emission allowances |
|
|
(9 |
) |
|
|
(42 |
) |
Gain recognized on settlement of pre-existing relationship |
|
|
(31 |
) |
|
|
|
|
Amortization of unearned equity compensation |
|
|
13 |
|
|
|
14 |
|
Changes in option premiums collected, net of acquisition |
|
|
(270 |
) |
|
|
99 |
|
Cash used by changes in other working capital, net of acquisition |
|
|
(239 |
) |
|
|
(253 |
) |
|
Net Cash Provided by Operating Activities |
|
|
722 |
|
|
|
436 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
Acquisition of Reliant Energy, net of cash acquired |
|
|
(345 |
) |
|
|
|
|
Capital expenditures |
|
|
(374 |
) |
|
|
(409 |
) |
Increase in restricted cash, net |
|
|
(3 |
) |
|
|
(1 |
) |
(Increase)/decrease in notes receivable |
|
|
(11 |
) |
|
|
21 |
|
Purchases of emission allowances |
|
|
(52 |
) |
|
|
(4 |
) |
Proceeds from sale of emission allowances |
|
|
15 |
|
|
|
61 |
|
Investments in nuclear decommissioning trust fund securities |
|
|
(172 |
) |
|
|
(285 |
) |
Proceeds from sales of nuclear decommissioning trust fund securities |
|
|
157 |
|
|
|
269 |
|
Proceeds from sale of discontinued operations and assets, net of cash divested |
|
|
|
|
|
|
229 |
|
Proceeds from sale of assets, net |
|
|
6 |
|
|
|
14 |
|
Proceeds from sale of equity method investment |
|
|
284 |
|
|
|
|
|
Other investment |
|
|
(5 |
) |
|
|
|
|
Equity investment in unconsolidated affiliates |
|
|
|
|
|
|
(17 |
) |
|
Net Cash Used by Investing Activities |
|
|
(500 |
) |
|
|
(122 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
(21 |
) |
|
|
(28 |
) |
Payment of financing element of acquired derivatives |
|
|
(22 |
) |
|
|
(28 |
) |
Payment for treasury stock |
|
|
|
|
|
|
(55 |
) |
Proceeds from issuance of common stock, net of issuance costs |
|
|
|
|
|
|
8 |
|
Proceeds from sale of noncontrolling interest in subsidiary |
|
|
50 |
|
|
|
50 |
|
Proceeds from issuance of long-term debt |
|
|
820 |
|
|
|
10 |
|
Payment of deferred debt issuance costs |
|
|
(29 |
) |
|
|
(2 |
) |
Payments for short and long-term debt |
|
|
(233 |
) |
|
|
(188 |
) |
|
Net Cash Provided by/(Used by) Financing Activities |
|
|
565 |
|
|
|
(233 |
) |
|
Change in cash from discontinued operations |
|
|
|
|
|
|
43 |
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
1 |
|
|
|
7 |
|
|
Net Increase in Cash and Cash Equivalents |
|
|
788 |
|
|
|
131 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
1,494 |
|
|
|
1,132 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
2,282 |
|
|
$ |
1,263 |
|
|
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 franchise in the ERCOT (Texas) market. 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 supply of electricity and energy
services to retail electricity customers in the Texas market.
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, 2008. 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, 2009, the
results of operations for the three and six months ended June 30, 2009 and 2008, and cash flows for
the six months ended June 30, 2009 and 2008. These financial statements and notes reflect the
Companys evaluation of events occurring subsequent to the balance sheet date through July 30,
2009, the date the financial statements were issued. Certain prior-year amounts have been
reclassified for comparative purposes.
Use of Estimates
The preparation of consolidated financial statements in accordance with generally accepted
accounting principles requires management to make estimates and assumptions. These estimates and
assumptions impact the reported amount of assets and liabilities and disclosures of contingent
assets and liabilities as of the date of the consolidated financial statements. They also impact
the reported amount of net earnings during the reporting period. Actual results could be different
from these estimates.
Cash and Cash Equivalents
Cash and cash equivalents at June 30, 2009, are predominantly held in money market funds
invested in treasury securities, treasury repurchase agreements or government agency debt.
Other Cash Flow Information
NRGs non-cash investing activities for the six months ended June 30, 2009 included capital
expenditures of $46 million for which the associated liability is reflected within accrued
expenses.
Recent Accounting Developments
SFAS 141R The Company adopted SFAS No. 141 (revised 2007), Business Combinations, or SFAS
141R, on January 1, 2009. The provisions of SFAS 141R are applied prospectively to business
combinations for which the acquisition date occurs after January 1, 2009. The statement requires
an acquirer to recognize and measure in its financial statements the identifiable assets acquired,
the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the
acquisition date. It also recognizes and measures the goodwill acquired or a gain from a bargain
purchase in the business combination and determines what information to disclose to enable users of
an entitys financial statements to evaluate the nature and financial effects of the business
combination. In addition, transaction costs are required to be expensed as incurred. As discussed
in Note 3, Business Acquisition, on May 1, 2009 NRG acquired all of the Texas electric retail
business operations, or Reliant Energy, of Reliant Energy, Inc., now known as RRI Energy, Inc., or
RRI. The Company has applied the provisions of SFAS 141R to the Reliant Energy acquisition. As
discussed further in Note 12, Income Taxes, any reductions after January 1, 2009, to existing net
deferred tax assets or valuation allowances or changes to uncertain tax benefits, as they relate to
Fresh Start or previously completed acquisitions, will be recorded to income tax expense rather
than additional paid-in capital or goodwill.
11
FSP FAS 141R-1 In April 2009, the FASB issued FSP No. FAS 141(R)-1, Accounting for Assets
Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, or FSP
FAS 141R-1, which the Company adopted effective January 1, 2009. This FSP amends and clarifies
SFAS 141R, to address application issues on initial recognition and measurement, subsequent
measurement and accounting, and disclosure of assets and liabilities arising from contingencies in
a business combination. The provisions of FSP FAS 141R-1 are applied prospectively to assets or
liabilities arising from contingencies in business combinations for which the acquisition date
occurs after January 1, 2009. Accordingly, the Company has applied the provisions of FSP FAS 141R-1
to the Reliant Energy acquisition.
SFAS 160 The Company adopted SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statementsan amendment of ARB No. 51, Consolidated Financial Statements, or SFAS 160, on
January 1, 2009. This statement amends ARB No. 51 to establish accounting and reporting standards
for the minority interest in a subsidiary and for the deconsolidation of a subsidiary. It also
amends certain of ARB No. 51s consolidation procedures for consistency with the requirements of
SFAS 141R. This statement is applied prospectively from the date of adoption, except for the
presentation and disclosure requirements, which shall be applied retrospectively. Accordingly, the
Company has conformed its financial statement presentation and disclosures to the requirements of
SFAS 160.
FSP APB 14-1 The Company adopted FSP No. APB 14-1, Accounting for Convertible Debt
Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement), or FSP
APB 14-1, on January 1, 2009, applying it retrospectively to all periods presented. FSP APB 14-1
clarifies that convertible debt instruments that may be settled in cash upon conversion (including
partial cash settlement) do not fall within the scope of paragraph 12 of Accounting Principles
Board Opinion No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants,
and specifies that issuers of such instruments should separately account for the liability
component and the equity component represented by the embedded conversion option in a manner that
will reflect the entitys nonconvertible debt borrowing rate when interest cost is recognized in
subsequent periods. Upon settlement, the entity shall allocate consideration transferred and
transaction costs incurred to the extinguishment of the liability component and the reacquisition
of the equity component.
During the third quarter 2006, NRGs unrestricted wholly-owned subsidiaries CSF I and CSF II
issued notes and preferred interests, or CSF Debt, which included an embedded derivative requiring
NRG to pay to Credit Suisse Group, or CS, at maturity, either in cash or stock at NRGs option, the
excess of NRGs then current stock price over a threshold price. The CSF Debt and its embedded
derivative are accounted for under the guidance in FSP APB 14-1. The fair value of the embedded
derivative at the date of issuance was determined to be $32 million and has been recorded as a debt
discount to the CSF Debt, with a corresponding credit to Additional Paid-in Capital. This debt
discount will be amortized over the terms of the underlying CSF Debt. The cumulative effect of the
change in accounting principle for periods prior to December 31, 2008, was recorded as a $7 million
decrease to Long-Term Debt, a $13 million decrease to Additional Paid-In Capital, and a $20 million
increase to Retained Earnings on the Condensed Consolidated Balance Sheet as of December 31, 2008.
The following table summarizes the effect of the adoption of FSP APB 14-1 on income and
per-share amounts for all periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended |
|
|
Six months ended |
|
|
|
June 30, |
|
|
June 30, |
|
(In millions, except per share amounts) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Increase/(decrease): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
3 |
|
|
$ |
5 |
|
Income From Continuing Operations |
|
|
(2) |
|
|
|
(2) |
|
|
|
(3) |
|
|
|
(5) |
|
Net Income attributable to NRG Energy, Inc. |
|
|
(2) |
|
|
|
(2) |
|
|
|
(3) |
|
|
|
(5) |
|
Basic Earnings Per Share |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.02 |
) |
Diluted Earnings Per Share |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.01 |
) |
|
$ |
(0.02 |
) |
|
12
FSP FAS 157-4 In April 2009, the FASB issued FSP No. FAS 157-4, Determining Fair Value When
the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and
Identifying Transactions That Are Not Orderly, or FSP FAS 157-4. FSP FAS 157-4 provides additional
guidance for estimating fair value in accordance with SFAS Statement No. 157, Fair Value
Measurements, when the volume and level of activity for the asset or liability have significantly
decreased, includes guidance on identifying circumstances that indicate a transaction is not
orderly, and requires disclosures about inputs and valuation techniques used to measure fair value.
This FSP applies to all assets and liabilities within the scope of accounting pronouncements that
require or permit fair value measurements. FSP FAS 157-4 is effective for interim and annual
reporting periods ending after June 15, 2009, and will be applied prospectively. The Companys
adoption of FSP FAS 157-4 beginning with the interim reporting period ended June 30, 2009, did not
have a material impact on the Companys results of operations, financial position, or cash flows.
FSP 107-1 and APB 28-1 In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1,
Interim Disclosures about Fair Value of Financial Instruments, or FSP 107-1 and APB 28-1. This FSP
amends FASB Statement No. 107, Disclosures about Fair Value of Financial Instruments, to require
disclosures about fair value of financial instruments for interim reporting periods of publicly
traded companies as well as in annual financial statements. This FSP also amends APB Opinion No.
28, Interim Financial Reporting, to require those disclosures in summarized financial information
at interim reporting periods. This FSP applies to all financial instruments within the scope of
FSP 107-1 held by publicly traded companies, as defined by Opinion 28. This FSP is effective for
interim reporting periods ending after June 15, 2009. FSP FAS 107-1 and APB 28-1 do not require
disclosures for earlier periods presented for comparative purposes at initial adoption. In periods
after initial adoption, this FSP requires comparative disclosures only for periods ending after
initial adoption. The Companys adoption of FSP 107-1 and APB 28-1 beginning with the interim
period ended June 30, 2009 did not have an impact on the Companys results of operations, financial
position, or cash flows.
FSP FAS 115-2 and FAS 124-2 In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2,
Recognition and Presentation of Other-Than-Temporary Impairments, or FSP FAS 115-2 and FAS 124-2.
This FSP amends the other-than-temporary impairment guidance in U.S. GAAP for debt securities to
make the guidance more operational and to improve the presentation and disclosure of
other-than-temporary impairments on debt and equity securities in the financial statements. This
FSP does not amend existing recognition and measurement guidance related to other-than-temporary
impairments of equity securities. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual
reporting periods ending after June 15, 2009. This FSP does not require disclosures for earlier
periods presented for comparative purposes at initial adoption. In periods after initial adoption,
this FSP requires comparative disclosures only for periods ending after initial adoption. The
Companys adoption of FSP FAS 115-2 and FAS 124-2 beginning with the interim period ended June 30,
2009 did not have an impact on the Companys results of operations, financial position, or cash
flows.
SFAS 165 In May 2009, the FASB issued SFAS No. 165, Subsequent Events, or SFAS 165. SFAS
165 incorporates the accounting and disclosure requirements related to subsequent events found in
auditing standards into U.S. GAAP, effectively making management directly responsible for
subsequent events accounting and disclosures. SFAS 165 also requires disclosure of the date
through which subsequent events have been evaluated. SFAS 165 is effective for interim and annual
reporting periods ending after June 15, 2009, and shall be applied prospectively. The Companys
adoption of SFAS 165 beginning with the interim period ended June 30, 2009 did not have an impact
on the Companys results of operations, financial position, or cash flows.
SFAS 167 In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No.
46(R), or SFAS 167. This guidance amends FIN 46(R) by altering how a company determines when an
entity that is insufficiently capitalized or not controlled through voting should be consolidated.
SFAS 167 is effective at the start of the first fiscal year beginning after November 15, 2009. The
Company is presently evaluating the impact of SFAS 167 on its results of operations, financial
position, and cash flows.
SFAS 168 In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles, or SFAS 168. This
guidance establishes the FASB Accounting Standards Codification, or Codification, as the source of
authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. In addition,
SFAS 168 also specifies that rules and interpretive releases of the Securities and Exchange
Commission under authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. All guidance contained in the Codification carries an equal level of authority.
SFAS 168 is effective for financial statements issued for interim and annual reporting periods that
end after September 15, 2009.
13
EITF 09-1 In July 2009, the FASB ratified EITF Issue No. 09-1, Accounting for Own-Share
Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing, or EITF
09-1. This Issue applies to equity-classified share lending arrangements on an entitys own shares,
when executed in contemplation of a convertible debt offering or other financing. EITF 09-1
addresses how to account for the share-lending arrangement and the effect, if any, that the loaned
shares have on earnings-per-share calculations. The share lending arrangement is required to be
measured at fair value and recognized as an issuance cost associated with the convertible debt
offering or other financing. Earnings-per-share calculations would not be affected by the loaned
shares unless the share borrower defaults on the arrangement and does not return the shares. If
counterparty default is probable, the share lender is required to recognize an expense equal to the
then fair value of the unreturned shares, net of the fair value of probable recoveries. The
Company will apply EITF 09-1 for share lending agreements entered into after June 15, 2009 and will
apply EITF 09-1 on a retrospective basis for arrangements outstanding as of January 1, 2010. NRG
is currently evaluating the impact of this statement upon its adoption on the Companys results of
operations, financial position and cash flows.
Other The following accounting standards were adopted on January 1, 2009, with no impact on
the Companys results of operations, financial position, or cash flows:
|
|
|
FSP No. FAS 142-3, Determination of the Useful Life of Intangible Assets |
|
|
|
|
FSP No. FAS 157-2, Effective Date of FASB Statement No. 157 |
|
|
|
|
SFAS No. 161, Disclosures About Derivative Instruments and Hedging Activities |
|
|
|
|
FSP No. FAS 132(R)-1, Employers Disclosures about Postretirement Benefit Plan Assets |
|
|
|
|
EITF No. 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an
Entitys Own Stock |
|
|
|
|
EITF No. 08-5, Issuers Accounting for Liabilities Measured at Fair Value with a
Third-Party Credit Enhancement |
|
|
|
|
EITF No. 08-6, Equity Method Investment Accounting Considerations |
Note 2 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) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Net income |
|
$ |
433 |
|
|
$ |
127 |
|
|
$ |
631 |
|
|
$ |
176 |
|
|
Changes in derivative activity, net of tax |
|
|
(109 |
) |
|
|
(698 |
) |
|
|
64 |
|
|
|
(1,000 |
) |
Foreign currency translation adjustment, net of tax |
|
|
36 |
|
|
|
(7 |
) |
|
|
18 |
|
|
|
35 |
|
Reclassification adjustment for translation (gain)/loss
realized upon sale of foreign investments |
|
|
(22 |
) |
|
|
15 |
|
|
|
(22 |
) |
|
|
15 |
|
Unrealized gain on available-for-sale securities, net of tax |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
Other comprehensive (loss)/income, net of tax |
|
|
(94 |
) |
|
|
(689 |
) |
|
|
62 |
|
|
|
(947 |
) |
|
Comprehensive income/(loss) attributable to NRG Energy, Inc. |
|
$ |
339 |
|
|
$ |
(562 |
) |
|
$ |
693 |
|
|
$ |
(771 |
) |
|
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, 2008 |
|
$ |
310 |
|
Changes in derivative activity |
|
|
64 |
|
Foreign currency translation adjustment |
|
|
18 |
|
Reclassification adjustment for translation gain realized upon sale of foreign investment |
|
|
(22 |
) |
Unrealized gain on available-for-sale securities |
|
|
2 |
|
|
Accumulated other comprehensive income as of June 30, 2009 |
|
$ |
372 |
|
|
14
Note 3 Business Acquisition
General
On May 1, 2009, NRG, through its wholly owned subsidiary NRG Retail LLC, acquired Reliant
Energy, which consisted of all of the Texas electric retail business operations of RRI, including
the exclusive use of the trade name Reliant. Reliant Energy 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. Reliant Energy is the second largest
electricity provider to residential and small business, or mass, customers in Texas, with
approximately 1.6 million mass customers as of June 30, 2009. Reliant Energy also sells
electricity and energy services to commercial, industrial and governmental/institutional customers,
or C&I customers, in Texas with 0.1 million C&I customers based on metered locations as of June 30, 2009.
These customers include refineries, chemical plants, manufacturing facilities, hospitals,
universities, government agencies, restaurants, and other facilities.
With its complementary generation portfolio, the Texas region will be a supplier of power to
Reliant Energy, thereby creating the potential for a more stable, reliable and competitive business
that benefits Texas consumers. By backing Reliant Energys load-serving requirements with NRGs
generation and risk management practices, the need to sell and buy power from other financial
institutions and intermediaries that trade in the ERCOT market may be reduced, resulting in reduced
transaction costs and credit exposures, which will provide for an efficient credit structure. This
will also allow for a reduction in actual and contingent collateral, which will be achieved
initially through offsetting transactions and over time by reducing the need to hedge the retail
power supply through third parties, thus reducing collateral postings. In addition, with Reliant
Energys base of retail customers, NRG now has a platform to build on the entire class of
distributed generation and retail alternative energy technologies.
Credit Support
On May 1, 2009, NRG arranged with Merrill Lynch Commodities, Inc. and certain of its
affiliates, or Merrill Lynch, the former credit provider of RRI, to provide continuing credit
support to Reliant Energy after closing the acquisition. In connection with entering into a
transitional credit sleeve facility, or CSRA, NRG contributed $200 million of cash to Reliant
Energy. In conjunction with the CSRA, NRG, Reliant Energy, counterparties, and Merrill Lynch
novated some of NRGs in-the-money trades to move collateral from NRG to Merrill Lynch, thereby
reducing Merrill Lynchs actual and contingent collateral supporting Reliant Energy out-of-money
positions. As a result, $522 million of cash collateral held by NRG was moved to Merrill Lynch on
the novation dates. NRG continues to record unrealized and realized gains/losses for these novated
trades in its Texas and Northeast segments. The CSRA is scheduled to provide collateral support
for Reliant Energy until November 1, 2010. NRG will also have two potential additional cash
contribution obligations: (i) in October 2009 of $250 million if the actual collateral posted by
Merrill Lynch exceeded the predetermined threshold as set forth in the CSRA; and (ii) in October
2010 for up to $400 million at the scheduled sleeve unwind. The monthly fee for the CSRA is 5.875%
on an annualized basis of the predetermined exposure. As a result of the CSRA, NRG has significant
credit risk with Merrill Lynch.
Additionally, on May 1, 2009, NRG entered into a $50 million working capital facility with
Merrill Lynch in connection with the acquisition of Reliant Energy. The facility requires that the
Company comply with all terms of the CSRA. The maturity date is November 1, 2010, and NRG
initially drew $25 million under the facility. These funds accrue interest at the prime rate.
Reliant Energy conducts its business through RERH Holdings, LLC and subsidiaries, or RERH,
Reliant Energy Texas Retail, LLC, and Reliant Energy Services Texas, LLC. The obligations of
Reliant Energy under the CSRA are secured by first liens on substantially all of the assets of
RERH. The obligations of RERH under the CSRA are non-recourse to NRG and its other non-pledgor
subsidiaries. The CSRA agreement (a) restricts the ability of RERH to, among other actions,
(i) encumber its assets; (ii) sell certain assets; (iii) incur additional debt; (iv) pay dividends
or pay subordinated debt; (v) make investments or acquisitions; or (vi) enter into certain
transactions with affiliates and (b) requires NRG to manage risks related to commodity prices.
RERH is designed to maintain the separate nature of its assets in order to ensure that such assets
are available first and foremost to satisfy the entities creditor claims. At June 30, 2009, the
cash balance at RERH was $294 million.
15
Acquisition method of accounting
The acquisition of Reliant Energy is accounted for under the acquisition method of accounting
in accordance with SFAS 141R. Accordingly, NRG has conducted a preliminary assessment of net
assets acquired and has recognized provisional amounts for identifiable assets acquired and
liabilities assumed at their estimated acquisition date fair values, which are preliminary at June
30, 2009, while transaction and integration costs associated with the acquisition are expensed as
incurred. The initial accounting for the business combination is not complete because the
appraisals necessary to assess the fair values of the net assets acquired and the amount of
goodwill (if any) to be recognized are still in process, and the Company is also in the process of
valuing the tax basis of the net assets acquired, which will affect the deferred tax balances. The
provisional amounts recognized are subject to revision as more detailed analyses are completed and
additional information is obtained about the facts and circumstances that existed as of the
acquisition date. Any changes to the fair value assessments and the tax basis values will affect
the final balance of goodwill.
NRG paid RRI $287.5 million in cash at closing, funded from NRGs cash on hand, and will remit
approximately $82 million of acquired net working capital to RRI over the eight months following
the closing, bringing cash consideration to approximately $370 million. On June 15, 2009, NRG paid
$63 million to RRI as an initial remittance of acquired net working capital. NRG also recognized a
$31 million non-cash gain 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. NRG has recorded this gain
within Operating Revenues in its condensed consolidated statement of operations. This non-cash
gain is considered a component of consideration in accordance with SFAS 141R, and together with
cash consideration, brings total consideration to approximately $401 million.
The following table summarizes the provisional 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 |
|
|
733 |
|
Customer relationships |
|
|
481 |
|
Trade names |
|
|
178 |
|
In-market energy supply contracts |
|
|
37 |
|
Other |
|
|
6 |
|
Derivative assets |
|
|
1,942 |
|
Deferred tax asset, net |
|
|
11 |
|
Goodwill |
|
|
|
|
|
Total assets acquired |
|
|
4,095 |
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
Current and non-current liabilities |
|
|
550 |
|
Derivative liabilities |
|
|
2,996 |
|
Out-of-market energy supply and customer contracts |
|
|
148 |
|
|
Total liabilities assumed |
|
|
3,694 |
|
|
Net assets acquired |
|
$ |
401 |
|
|
No goodwill is expected to be deductible for tax purposes.
Current assets include accounts receivable with a preliminary fair value of $569 million and
gross contractual amounts of $589 million at the time of acquisition. The Company expects to
collect the fair value of the contractual cash flows; any difference between fair value and the
amount collected will be an adjustment to the acquired working capital payment due to RRI.
16
The Company, through its acquisition of Reliant Energy, is subject to material contingencies
relating to Excess Mitigation Credits (see Note 14, Commitments and Contingencies) and Retail
Replacement Reserve (see Note 15, Regulatory Matters). Due to the number of variables and
assumptions involved in assessing the possible outcome of these matters, sufficient information
does not exist to reasonably estimate the fair value of these contingent liabilities. These
material contingencies have been evaluated in accordance with SFAS No. 5, Accounting for
Contingencies, or SFAS 5, and related guidance, and no provisional amounts for these matters have
been recorded at the acquisition date. In addition, NRG provided certain indemnities in connection
with the acquisition. See Note 17, Guarantees, to this Form 10-Q for further discussion.
Fair value measurements
The provisional fair values of the intangible assets/liabilities and property, plant and
equipment at the acquisition date were measured primarily based on significant inputs that are not
observable in the market and thus represent a Level 3 measurement as defined in SFAS No. 157, Fair
Value Measurement, or SFAS 157. Significant inputs were as follows:
|
|
|
Customer contracts The fair value of the customer contracts, representing those with
Reliant Energys C&I customers, was estimated based on the present value of the above/below
market cash flows attributable to the contracts based on contract type, discounted
utilizing a current market interest rate consistent with the overall credit quality of the
portfolio. The fair values also accounted for Reliant Energys historical costs to acquire
customers. The above/below market cash flows were estimated by comparing the expected cash
flows to be generated based on existing contracted prices and expected volumes with the
cash flows from estimated current market contract prices for the same expected volumes.
The estimated current market contract prices were derived considering current market costs,
such as price of energy, transmission and distribution costs, and miscellaneous fees, plus
a normal profit margin. The customer contracts are amortized to revenues, over a weighted
average amortization period of five years, based on expected volumes to be delivered for
the portfolio. |
|
|
|
|
Customer relationships The customer relationships, reflective of Reliant Energys
residential and small business customer base, or Mass, were valued using a variation of the
income approach. Under this approach, the Company estimated the present value of expected
future cash flows resulting from the existing customer relationships, considering attrition
and charges for contributory assets (such as net working capital, fixed assets, software,
workforce and trade names) utilized in the business, discounted at an independent power
producer peer groups weighted average cost of capital. The customer relationships are
amortized to depreciation and amortization, over a weighted average amortization period of
eight years, based on the expected discounted future net cash flows by year. |
|
|
|
|
Trade names The trade names were valued using a relief from royalty method, an
approach under which fair value is estimated to be the present value of royalties saved
because NRG owns the intangible asset and therefore does not have to pay a royalty for its
use. The trade names were valued in two parts based on Reliant Energys two primary
customer segments Mass customers and C&I customers. The avoided royalty revenues were
discounted at an independent power producer peer groups weighted average cost of capital.
The trade names are amortized to depreciation and amortization, on a straight-line basis,
over 15 years. |
|
|
|
|
Energy supply contracts The fair value of the in-market and out-of-market energy
supply contracts was determined in accordance with SFAS 157. These contracts are amortized
over periods ranging through 2016, based on the expected delivery under the respective
contracts. |
|
|
|
|
Property, plant and equipment The fair value of property, plant and equipment were
valued using a cost approach, which estimates value by determining the current cost of
replacing an asset with another of equivalent economic utility. The cost to replace a given
asset reflects the estimated reproduction or replacement cost for the property, less an
allowance for loss in value due to depreciation. |
The fair value of derivative assets and liabilities as of the acquisition date were determined
in accordance with FAS 157. The breakdown of Level 1, 2 and 3 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
(In millions) |
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
Derivative assets |
|
$ |
534 |
|
|
$ |
1,375 |
|
|
$ |
33 |
|
|
$ |
1,942 |
|
|
Derivative liabilities |
|
$ |
534 |
|
|
$ |
2,357 |
|
|
$ |
105 |
|
|
$ |
2,996 |
|
|
17
Amortization of acquired intangible assets and out-of-market contracts
The following table presents the estimated amortization related to the acquired intangible
assets for 2009 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
Customer |
|
|
Customer |
|
|
Trade |
|
|
Energy Supply |
|
(in millions) |
|
Contracts |
|
|
Relationships |
|
|
Names |
|
|
Contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 (six months) |
|
$ |
178 |
|
|
$ |
118 |
|
|
$ |
6 |
|
|
$ |
12 |
|
2010 |
|
|
208 |
|
|
|
106 |
|
|
|
12 |
|
|
|
|
|
2011 |
|
|
134 |
|
|
|
63 |
|
|
|
12 |
|
|
|
2 |
|
2012 |
|
|
93 |
|
|
|
47 |
|
|
|
12 |
|
|
|
3 |
|
2013 |
|
|
45 |
|
|
|
33 |
|
|
|
12 |
|
|
|
4 |
|
2014 |
|
|
|
|
|
|
26 |
|
|
|
12 |
|
|
|
4 |
|
|
The following table presents the estimated amortization related to the acquired out-of-market
contracts for 2009 2014:
|
|
|
|
|
|
|
Energy Supply |
|
Year Ended December 31, |
|
and Customer |
|
(in millions) |
|
Contracts |
|
|
|
|
|
|
|
2009 (six months) |
|
|
$ 49 |
|
2010 |
|
|
51 |
|
2011 |
|
|
18 |
|
2012 |
|
|
7 |
|
2013 |
|
|
3 |
|
2014 |
|
|
|
|
|
Supplemental Pro Forma Information
Since the acquisition date, Reliant Energy contributed $1,175 million of operating revenues
and $233 million in net income attributable to NRG.
The following supplemental pro forma information represents the results of operations as if
NRG and Reliant Energy had combined at the beginning of the respective reporting periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(In millions, except per share amounts) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Operating revenues |
|
$ |
2,672 |
|
|
$ |
3,497 |
|
|
$ |
5,716 |
|
|
$ |
6,513 |
|
Net income
attributable to NRG Energy, Inc. |
|
|
493 |
|
|
|
268 |
|
|
|
578 |
|
|
|
548 |
|
Earnings per share attributable to NRG common stockholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.92 |
|
|
$ |
1.08 |
|
|
$ |
2.27 |
|
|
$ |
2.20 |
|
Diluted |
|
$ |
1.78 |
|
|
$ |
0.97 |
|
|
$ |
2.07 |
|
|
$ |
1.91 |
|
|
The supplemental pro forma information has been adjusted to include the pro forma impact of
amortization of intangible assets and out-of-market contracts, and depreciation of property, plant
and equipment, based on the preliminary purchase price allocations. The pro forma data has also
been adjusted to eliminate the non-recurring transaction costs incurred by NRG. Transactions
between NRG and Reliant Energy have not been eliminated. The pro forma results are presented for
illustrative purposes only and do not reflect the realization of potential cost savings, or any
related integration costs. Certain cost savings may result from the acquisition; however, there can
be no assurance that these cost savings will be achieved. These pro forma results do not purport
to be indicative of the results that would have actually been obtained if the acquisition occurred
at the beginning of the respective reporting periods, nor does the pro forma data intend to be a
projection of results that may be obtained in the future.
18
Significant Accounting Policies
The following pertains to Reliant Energy, in addition to NRGs significant accounting policies
referred to in Note 1 to this Form 10-Q:
|
|
|
Revenues Gross revenues for energy sales and services to mass customers and to C&I
customers are recognized upon delivery under the accrual method. Energy sales and services
that have been delivered but not billed by period end are estimated. Gross revenues also
includes energy revenues from resales of purchased power and other hedging activities, which
were $52 million for the two months ended June 30, 2009. These revenues represent a sale of
excess supply to third parties in the market. |
|
|
|
As of June 30, 2009, Reliant Energy recorded unbilled revenues of $433 million for energy
sales and services. Accrued unbilled revenues are based on Reliant Energys estimates of
customer usage since the date of the last meter reading provided by the independent system
operators or electric distribution companies. Volume estimates are based on daily forecasted
volumes and estimated customer usage by class. Unbilled revenues are calculated by
multiplying these volume estimates by the applicable rate by customer class. Estimated
amounts are adjusted when actual usage is known and billed. |
|
|
|
The revenues and the related energy supply costs include the estimates of customer usage based
on initial usage information provided by the independent system operators and the distribution
companies. Reliant Energy revises these estimates and records any changes in the period as
additional settlement information becomes available (collectively referred to as market usage
adjustments). |
|
|
|
Cost of Energy Reliant Energy records cost of energy for electricity sales and services
to retail customers based on estimated supply volumes for the applicable reporting period. A
portion of its cost of energy ($93 million as of June 30, 2009) consisted of estimated
transmission and distribution charges not yet billed by the transmission and distribution
utilities. In estimating supply volumes, Reliant Energy considers the effects of historical
customer volumes, weather factors and usage by customer class. Reliant Energy estimates its
transmission and distribution delivery fees using the same method that it uses for
electricity sales and services to retail customers. In addition, Reliant Energy estimates
ERCOT ISO fees based on historical trends, estimates supply volumes and initial ERCOT ISO
settlements. Volume estimates are then multiplied by the supply rate and recorded as cost of
operations in the applicable reporting period. See the discussion above regarding market
usage adjustments. |
|
|
|
Allowance for Doubtful Accounts Reliant Energy accrues an allowance for doubtful
accounts based on estimates of uncollectible revenues by analyzing counterparty credit
ratings (for commercial and industrial customers), historical collections, accounts
receivable agings and other factors. Reliant Energy writes-off accounts receivable balances
against the allowance for doubtful accounts when it determines a receivable is uncollectible. |
|
|
|
Gross Receipts Taxes Reliant Energy records gross receipts taxes on a gross basis in
revenues and cost of operations in its condensed consolidated statements of operations.
During the two months ended June 30, 2009, Reliant Energys revenues and cost of operations
included gross receipts taxes of $16 million. |
|
|
|
Sales Taxes Reliant Energy records sales taxes collected from its taxable customers and
remitted to the various governmental entities on a net basis, thus, there is no impact on the
Companys condensed consolidated statement of operations. |
19
Note 4 Investments Accounted for by the Equity Method
MIBRAG On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag
B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and J&T Group.
Mibrag B.V.s principal holding is MIBRAG, which is jointly owned by NRG and URS Corporation. As
part of the transaction, URS Corporation also entered into an agreement to sell its 50% stake in
MIBRAG.
For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40
US$/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. The foreign currency forward
contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange
for $255 million on June 15, 2009. 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
(loss)/income, net.
NRG provided certain indemnities in connection with its share of the transaction. See Note 17,
Guarantees, to this Form 10-Q for further discussion.
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, 2009 |
|
|
2008 |
|
|
June 30, 2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
Cash and cash equivalents |
|
|
$ |
2,282 |
|
|
$ |
1,494 |
|
|
$ |
2,282 |
|
|
$ |
1,494 |
|
Funds deposited by counterparties |
|
|
|
468 |
|
|
|
754 |
|
|
|
468 |
|
|
|
754 |
|
Restricted cash |
|
|
|
19 |
|
|
|
16 |
|
|
|
19 |
|
|
|
16 |
|
Cash collateral paid in support of energy risk management activities |
|
|
|
243 |
|
|
|
494 |
|
|
|
243 |
|
|
|
494 |
|
Investment in available-for-sale securities (classified within other
non-current assets): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities |
|
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
Marketable equity securities |
|
|
|
4 |
|
|
|
2 |
|
|
|
4 |
|
|
|
2 |
|
Trust fund investments |
|
|
|
318 |
|
|
|
305 |
|
|
|
318 |
|
|
|
305 |
|
Notes receivable |
|
|
|
190 |
|
|
|
156 |
|
|
|
204 |
|
|
|
166 |
|
Derivative assets |
|
|
|
5,582 |
|
|
|
5,485 |
|
|
|
5,582 |
|
|
|
5,485 |
|
Long-term debt, including current portion |
|
|
|
8,619 |
|
|
|
8,019 |
|
|
|
8,267 |
|
|
|
7,475 |
|
Cash collateral received in support of energy risk management activities |
|
|
|
468 |
|
|
|
760 |
|
|
|
468 |
|
|
|
760 |
|
Derivative liabilities |
|
|
|
5,102 |
|
|
|
4,489 |
|
|
|
5,102 |
|
|
|
4,489 |
|
|
20
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, 2009 |
|
Level 1 |
|
Level 2 |
| |
Level 3 |
| |
Total | |
|
Cash and cash equivalents |
|
$ |
2,282 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,282 |
|
Funds deposited by counterparties |
|
|
468 |
|
|
|
|
|
|
|
|
|
|
|
468 |
|
Restricted cash |
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Cash collateral paid in support of energy risk management activities |
|
|
243 |
|
|
|
|
|
|
|
|
|
|
|
243 |
|
Investment in available-for-sale securities (classified within other non-current assets): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities |
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
7 |
|
Marketable equity securities |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
4 |
|
Trust fund investments |
|
|
183 |
|
|
|
101 |
|
|
|
34 |
|
|
|
318 |
|
Derivative assets |
|
|
1,063 |
|
|
|
4,394 |
|
|
|
125 |
|
|
|
5,582 |
|
|
Total assets |
|
$ |
4,262 |
|
|
$ |
4,495 |
|
|
$ |
166 |
|
|
$ |
8,923 |
|
|
Cash collateral received in support of energy risk management activities |
|
$ |
468 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
468 |
|
Derivative liabilities |
|
|
1,043 |
|
|
|
3,984 |
|
|
|
75 |
|
|
|
5,102 |
|
|
Total liabilities |
|
$ |
1,511 |
|
|
$ |
3,984 |
|
|
$ |
75 |
|
|
$ |
5,570 |
|
|
The following table reconciles, for the six months ended June 30, 2009, the beginning and
ending balances for financial instruments that are recognized at fair value in the consolidated
financial statements using significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using Significant Unobservable Inputs |
|
(Level 3) |
(In millions) |
|
|
|
|
|
Trust Fund |
|
|
|
|
Six months ended June 30, 2009 |
|
Debt Securities |
|
Investments |
|
Derivatives |
|
Total |
|
Beginning balance as of January 1, 2009 |
|
$ |
7 |
|
|
$ |
31 |
|
|
$ |
49 |
|
|
$ |
87 |
|
Total gains/(losses) (realized and unrealized) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
|
|
|
|
|
|
|
|
(30 |
) |
|
|
(30 |
) |
Included in nuclear decommissioning obligations |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
Purchases/(sales), net |
|
|
|
|
|
|
1 |
|
|
|
(4 |
) |
|
|
(3 |
) |
Transfer into Level 3 |
|
|
|
|
|
|
|
|
|
|
35 |
|
|
|
35 |
|
|
Ending balance as of June 30, 2009 |
|
$ |
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 |
|
$ |
|
|
|
$ |
|
|
|
$ |
28 |
|
|
$ |
28 |
|
|
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, 2009, the credit reserve resulted in a $23 million increase in fair value which is
composed of a $1 million loss in OCI and a $24 million gain in operating revenue and cost of operations.
This footnote should be read in conjunction with the complete description under Note 4, Fair
Value of Financial Instruments, to the Companys financial statements in its 2008 Annual Report on
Form 10-K.
21
Note 6 Accounting for Derivative Instruments and Hedging Activities
SFAS 133 requires NRG to recognize all derivative instruments on the balance sheet as either
assets or liabilities and to measure them at fair value each reporting period unless they qualify
for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be
able to designate certain derivatives as cash flow hedges and defer the effective portion of the
change in fair value of the derivatives to other comprehensive income, or OCI, until the hedged
transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge is
immediately recognized in earnings.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes
in fair value of both the derivative and the hedged transaction are recorded in current earnings.
The ineffective portion of a hedging derivative instruments change in fair value is immediately
recognized into earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge
accounting treatment, the changes in the fair value will be immediately recognized in earnings.
Under the guidelines established per SFAS 133, certain derivative instruments may qualify for the
NPNS exception and are therefore exempt from fair value accounting treatment. SFAS 133 applies to
NRGs energy related commodity contracts, interest rate swaps, and foreign exchange contracts.
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 SFAS 133. 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 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 in accordance with 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 buy or sell a commodity. |
The objectives for entering into derivative contracts designated as hedges include:
|
|
|
Fixing the price for a portion of anticipated future electricity sales through the use
of various derivative instruments including gas collars and swaps at a level that provides
an acceptable return on the Companys electric generation operations. |
|
|
|
Fixing the price of a portion of anticipated fuel purchases for the operation of NRGs
power plants. |
|
|
|
Fixing the price of a portion of anticipated energy purchases to supply Reliant Energys
customers. |
22
NRGs trading activities include contracts entered into to profit from market price changes as
opposed to hedging an exposure, and are subject to limits in accordance with the Companys risk
management policy. These contracts are recognized on the balance sheet at fair value and changes
in the fair value of these derivative financial instruments are recognized in earnings. These
trading activities are a complement to NRGs competitive wholesale supply and retail operations.
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, 2009, NRG had interest rate derivative instruments
extending through June 2019, all 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 derivative
transactions broken out by commodity, excluding those derivatives that qualified for the NPNS
exception as of June 30, 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 as |
|
|
|
|
of June 30, 2009 |
Commodity |
|
Units |
|
(In millions) |
|
Coal |
|
Short Ton |
|
|
67 |
|
Natural Gas |
|
MMBtu |
|
|
(572 |
) |
Power(a) |
|
MWH |
|
|
(30 |
) |
Interest |
|
Dollars |
|
$ |
3,306 |
|
|
|
|
|
(a) |
|
Power volumes include capacity sales. |
Fair Value of Derivative Instruments
The following table summarizes the fair value within the derivative instrument valuation on
the balance sheet as of June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
Fair Value |
(In millions) |
|
Derivatives Asset |
|
Derivatives Liability |
|
Derivatives Designated as Cash Flow or Fair Value Hedges: |
|
|
|
|
|
|
|
|
Interest rate contracts current |
|
$ |
|
|
|
$ |
6 |
|
Interest rate contracts long term |
|
|
11 |
|
|
|
119 |
|
Commodity contracts current |
|
|
337 |
|
|
|
7 |
|
Commodity contracts long term |
|
|
414 |
|
|
|
47 |
|
|
Total Derivatives Designated as Cash Flow or Fair Value Hedges |
|
|
762 |
|
|
|
179 |
|
|
Derivatives Not Designated as Cash Flow or Fair Value Hedges: |
|
|
|
|
|
|
|
|
Commodity contracts current |
|
|
4,057 |
|
|
|
4,183 |
|
Commodity contracts long term |
|
|
763 |
|
|
|
740 |
|
|
Total Derivatives Not Designated as Cash Flow or Fair Value Hedges |
|
|
4,820 |
|
|
|
4,923 |
|
|
Total Derivatives |
|
$ |
5,582 |
|
|
$ |
5,102 |
|
|
Impact of Derivative Instruments on the Statement of Financial Performance
The following table summarizes the amount of gain/(loss) resulting from fair value hedges
reflected in interest income/(expense) for interest rate contracts:
|
|
|
|
|
|
|
|
|
Amount of gain/(loss) recognized |
|
Three months ended
|
|
Six months ended |
(In millions) |
|
June 30, 2009 |
|
June 30, 2009 |
|
Derivative |
|
$ |
(7 |
) |
|
$ |
(8 |
) |
Senior Notes (hedged item) |
|
$ |
7 |
|
|
$ |
8 |
|
|
23
The following table summarizes the location and amount of gain/(loss) resulting from cash flow
hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
Amount of |
|
|
Amount of |
|
Location of |
|
Amount of |
|
gain/(loss) |
|
gain/(loss) |
|
|
gain/(loss) |
|
gain/(loss) |
|
gain/(loss) |
|
recognized in |
|
recognized in |
|
|
recognized in OCI |
|
reclassified from |
|
reclassified from |
|
income |
|
income |
(In millions) |
|
(effective portion) |
|
Accumulated |
|
Accumulated |
|
(ineffective |
|
(ineffective |
Three months ended June 30, 2009 |
|
after tax |
|
OCI into Income |
|
OCI into Income |
|
portion) |
|
portion) |
|
Interest rate contracts |
|
$ |
13 |
|
|
Interest expense |
|
$ |
1 |
|
|
Interest expense |
|
$ |
|
|
Commodity contracts |
|
|
(122 |
) |
|
Operating revenue |
|
|
76 |
|
|
Operating revenue |
|
|
(3 |
) |
|
Total |
|
$ |
(109 |
) |
|
|
|
|
|
$ |
77 |
|
|
|
|
|
|
$ |
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
Amount of |
|
|
Amount of |
|
Location of |
|
Amount of |
|
gain/(loss) |
|
gain/(loss) |
|
|
gain/(loss) |
|
gain/(loss) |
|
gain/(loss) |
|
recognized in |
|
recognized in |
|
|
recognized in OCI |
|
reclassified from |
|
reclassified from |
|
income |
|
income |
(In millions) |
|
(effective portion) |
|
Accumulated |
|
Accumulated |
|
(ineffective |
|
(ineffective |
Six months ended June 30, 2009 |
|
after tax |
|
OCI into Income |
|
OCI into Income |
|
portion) |
|
portion) |
|
Interest rate contracts |
|
$ |
25 |
|
|
Interest expense |
|
$ |
|
|
|
Interest expense |
|
$ |
|
|
Commodity contracts |
|
|
39 |
|
|
Operating revenue |
|
|
323 |
|
|
Operating revenue |
|
|
1 |
|
|
Total |
|
$ |
64 |
|
|
|
|
|
|
$ |
323 |
|
|
|
|
|
|
$ |
1 |
|
|
The following table summarizes the amount of gain/(loss) recognized in income for derivatives
not designated as cash flow or fair value hedges on commodity contracts:
|
|
|
|
|
|
|
|
|
Amount of gain/(loss) recognized in income or cost of operations for derivatives |
|
Three months ended |
|
Six months ended |
(In millions) |
|
June 30, 2009 |
|
June 30, 2009 |
|
Location of gain/(loss) recognized in income for derivatives: |
|
|
|
|
|
|
|
|
Operating revenue |
|
$ |
(207 |
) |
|
$ |
116 |
|
Cost of operations |
|
$ |
325 |
|
|
$ |
273 |
|
|
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. Other agreements
contain provisions that require the Company to post additional collateral if there was a one notch
downgrade in the Companys credit rating. There are certain marginable agreements where NRG has a
net liability position but the counterparty has not called for the collateral due, which was
approximately $87 million as of June 30, 2009. The aggregate fair value of all derivative
instruments with credit rating contingent features that are in a net liability position as of June
30, 2009 was $54 million. The aggregate fair value of all derivative instruments that have
adequate assurance clauses that are in a net liability position as of June 30, 2009 was $18
million.
Under the CSRA, Merrill Lynch provides guarantees and the posting of collateral to the
Companys counterparties in supply transactions for the Companys retail energy business. In the
event of any unwind of the CSRA with Merrill Lynch, NRG will have to post collateral for any
existing out-of-money hedging transactions that support the retail operation. The level of
collateral posting would be determined based on the timing of the unwind, and the volume and
pricing of the commodity hedging agreements. As of June 30, 2009, Merrill Lynch was providing $630
million in credit support to various counterparties. If Merrill Lynch experiences credit
deterioration, NRGs suppliers may require varying collateral amounts depending on Merrill Lynchs
credit rating, not to exceed $630 million.
24
Concentration of Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by
counterparties pursuant to the terms of their contractual obligations. The Company monitors and
manages credit risk through credit policies that include: (i) an established credit approval
process; (ii) a daily monitoring of counterparties credit limits; (iii) the use of credit
mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements; (iv)
the use of payment netting agreements; and (v) the use of master netting agreements that allow for
the netting of positive and negative exposures of various contracts associated with a single
counterparty. Risks surrounding counterparty performance and credit could ultimately impact the
amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a
diversified portfolio of counterparties, including ten participants under its first and second lien
structure. The Company also has credit protection within various agreements to call on additional
collateral support if and when necessary. Cash margin is collected and held at NRG to cover the
credit risk of the counterparty until positions settle.
Under the current economic downturn in the U.S. and overseas, the Company has heightened its
management and mitigation of counterparty credit risk by using credit limits, netting agreements,
collateral thresholds, volumetric limits and other mitigation measures, where available. NRG
avoids concentration of counterparties whenever possible and applies credit policies that include
an evaluation of counterparties financial condition, collateral requirements and the use of
standard agreements that allow for netting and other security.
As of June 30, 2009, total credit exposure to substantially all counterparties was $2.1 billion and
NRG held collateral (cash and letters of credit) against those positions of $469 million resulting
in a net exposure of $1.7 billion, compared with a net exposure of $1.3 billion as of March 31, 2009. This increase is due to Merrill Lynchs position as credit
provider to Reliant Energy and the exposure resulting from novated trades that were completed as
part of the acquisition of Reliant Energy, as discussed in Note 3 Business Acquisition. Total
credit exposure is discounted at the risk free rate.
The following table highlights the credit quality and the net counterparty credit exposure by
industry sector. Net counterparty credit 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 and sale, and non-derivative transactions. The
exposure is shown net of collateral held, includes amounts net of receivables or payables and
excludes non-affiliate third party exposure under the CSRA.
|
|
|
|
|
|
|
Net Exposure(a) (b) as of |
|
|
June 30, 2009 |
Category |
|
(% of Total) |
|
Financial institutions |
|
|
82 |
% |
Utilities, energy, merchants, marketers and other |
|
|
14 |
|
Coal suppliers |
|
|
2 |
|
ISOs |
|
|
2 |
|
|
Total |
|
|
100 |
% |
|
|
|
|
|
|
|
|
Net Exposure(a) (b) as of |
|
|
June 30, 2009 |
Category |
|
(% of Total) |
|
Investment grade |
|
|
94 |
% |
Non-Investment grade |
|
|
|
|
Non-rated |
|
|
6 |
|
|
Total |
|
|
100 |
% |
|
|
|
|
(a) |
|
Credit exposure excludes California tolling,
uranium, coal transportation, New
England Reliability Must-Run, 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, or credit risks for certain contracts are
not readily measurable due to a lack of market reference prices. |
|
(b) |
|
The exposure amounts presented in the above table
do not include non-affiliate third party exposure
under the CSRA. The gross credit exposure to third
parties under the CSRA is $410 million, and the cash
collateral held by Merrill Lynch against this exposure
is $312 million. |
25
NRG has credit risk exposure to certain counterparties representing more than 10% of
total net exposure and the aggregate of such counterparties was $707 million. NRG has significant
credit risk concentration with Merrill Lynch primarily due to cash collateral held by Merrill Lynch
for positions under the CSRA. NRG expects this risk to be significantly reduced when the Company
unwinds the CSRA. Approximately 85% of NRGs positions relating to credit risk roll-off by the end
of 2011. Changes in hedge positions and market prices will affect credit exposure and counterparty
concentration. 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 a counterparty.
NRG is exposed to retail credit risk through our competitive electricity supply business,
which serves commercial and industrial 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 arrangement.
Retail credit risk is dependent on the overall economy, but is minimized due to the fact that NRGs
portfolio of retail customers is largely diversified, with no significant single name
concentration.
Accumulated Other Comprehensive Income
The following table summarizes the effects of SFAS 133 on NRGs accumulated OCI balance
attributable to hedged derivatives, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Energy |
|
Interest |
|
|
Three months ended June 30, 2009 |
|
Commodities |
|
Rate |
|
Total |
|
Accumulated OCI balance at March 31, 2009 |
|
$ |
567 |
|
|
$ |
(79 |
) |
|
$ |
488 |
|
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
(76 |
) |
|
|
(1 |
) |
|
|
(77 |
) |
Mark-to-market of cash flow hedge accounting contracts |
|
|
(46 |
) |
|
|
14 |
|
|
|
(32 |
) |
|
Accumulated OCI balance at June 30, 2009 |
|
$ |
445 |
|
|
$ |
(66 |
) |
|
$ |
379 |
|
|
Gains/(losses) expected to be realized from OCI during
the next 12 months, net of $181 tax |
|
$ |
303 |
|
|
$ |
(3 |
) |
|
$ |
300 |
|
|
|
(In millions) |
|
Energy |
|
Interest |
|
|
|
|
Three months ended June 30, 2008 |
|
Commodities |
|
Rate |
|
Total |
|
Accumulated OCI balance at March 31, 2008 |
|
$ |
(493 |
) |
|
$ |
(74 |
) |
|
$ |
(567 |
) |
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
21 |
|
|
|
|
|
|
|
21 |
|
Mark-to-market of cash flow hedge accounting contracts |
|
|
(763 |
) |
|
|
44 |
|
|
|
(719 |
) |
|
Accumulated OCI balance at June 30, 2008 |
|
$ |
(1,235 |
) |
|
$ |
(30 |
) |
|
$ |
(1,265 |
) |
|
|
(In millions) |
|
Energy |
|
Interest |
|
|
|
|
Six months ended June 30, 2009 |
|
Commodities |
|
Rate |
|
Total |
|
Accumulated OCI balance at December 31, 2008 |
|
$ |
406 |
|
|
$ |
(91 |
) |
|
$ |
315 |
|
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
(188 |
) |
|
|
|
|
|
|
(188 |
) |
Due to discontinuance of cash flow hedge accounting |
|
|
(135 |
) |
|
|
|
|
|
|
(135 |
) |
Mark-to-market of cash flow hedge accounting contracts |
|
|
362 |
|
|
|
25 |
|
|
|
387 |
|
|
Accumulated OCI balance at June 30, 2009 |
|
$ |
445 |
|
|
$ |
(66 |
) |
|
$ |
379 |
|
|
|
|
|
Energy |
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
Rate |
|
Total |
|
Accumulated OCI balance at December 31, 2007 |
|
$ |
(234 |
) |
|
$ |
(31 |
) |
|
$ |
(265 |
) |
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Mark-to-market of cash flow hedge accounting contracts |
|
|
(1,007 |
) |
|
|
1 |
|
|
|
(1,006 |
) |
|
Accumulated OCI balance at June 30, 2008 |
|
$ |
(1,235 |
) |
|
$ |
(30 |
) |
|
$ |
(1,265 |
) |
|
26
As of June 30, 2009, the net balance in OCI relating to SFAS 133 was an unrecognized gain
of approximately $379 million, which is net of $233 million in income taxes. As of June 30, 2008,
the net balance in OCI relating to SFAS 133 was an unrecognized loss of approximately $1,265
million, which was net of $829 million in income taxes.
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. Since the required
threshold for cash flow hedge accounting was achieved for these transactions, on April 1, 2009,
these hedges were re-designated as cash flow hedges.
Statement of Operations
In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair
value of derivative instruments not accounted for as 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) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Unrealized mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized
unrealized losses/(gains) on
settled positions related to
economic hedges |
|
$ |
192 |
|
|
$ |
(15 |
) |
|
$ |
176 |
|
|
$ |
(25 |
) |
Reversal of previously recognized
unrealized gains on settled
positions related to trading
activity |
|
|
(35 |
) |
|
|
(7 |
) |
|
|
(104 |
) |
|
|
(12 |
) |
Net unrealized (losses)/gains on
open positions related to economic
hedges |
|
|
(40 |
) |
|
|
(162 |
) |
|
|
309 |
|
|
|
(259 |
) |
(Losses)/gains on ineffectiveness
associated with open positions
treated as cash flow hedges |
|
|
(3 |
) |
|
|
(333 |
) |
|
|
1 |
|
|
|
(378 |
) |
Net unrealized gains on open
positions related to trading
activity |
|
|
1 |
|
|
|
15 |
|
|
|
8 |
|
|
|
31 |
|
|
Total unrealized gains/(losses) |
|
$ |
115 |
|
|
$ |
(502 |
) |
|
$ |
390 |
|
|
$ |
(643 |
) |
|
|
|
|
|
|
|
|
|
|
|
Six months ended |
|
|
Three months ended June 30, |
|
June 30, |
|
(In millions) |
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
Revenue from operations energy commodities |
|
$ |
(210 |
) |
|
$ |
(502 |
) |
|
$ |
117 |
|
|
$ |
(643 |
) |
Cost of operations |
|
|
325 |
|
|
|
|
|
|
|
273 |
|
|
|
|
|
|
Total impact to statement of operations |
|
$ |
115 |
|
|
$ |
(502 |
) |
|
$ |
390 |
|
|
$ |
(643 |
) |
|
For the six months ended June 30, 2009, the unrealized gain associated with changes in the
fair value of derivative instruments not accounted for as hedge derivatives of $390 million was
comprised of $309 million of fair value increases in forward sales and purchases of natural gas,
electricity and fuel, $1 million gain from ineffectiveness, $72 million gain from the reversal of
mark-to-market losses and $8 million of gains associated with the Companys trading activity. The
$309 million gain from economic hedge positions includes $217 million recognized in earnings from
previously deferred amounts in 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 natural gas, electricity and fuel due to
decrease in forward power and gas prices. The $1 million gain is primarily from hedge accounting
ineffectiveness related to gas trades in Texas which was driven by decreasing forward gas prices
while forward power prices decreased at a slower pace. The Company recognized a derivative loss of
$29 million resulting from discontinued NPNS designated coal purchases due to expected lower coal
consumption and accordingly could not assert taking physical delivery. This amount is included in
the Companys cost of operations.
27
The
reversal of previously recognized unrealized losses on settled positions related to
economic hedges of $192 million and $176 million for the three months and six months ended June 30, 2009,
includes $210 million in gains from Reliant Energy representing roll-off of positions acquired as of May
1, 2009, at the acquisition dates forward prices. These gains are offset by the losses at the
settled prices and are reflected in the cost of operations during the same period.
For the six months ended June 30, 2008, the unrealized loss associated with changes in the
fair value of derivative instruments not accounted for as hedge derivatives of $643 million was
comprised of $259 million of fair value decreases in forward sales of electricity and fuel, a $378
million loss due to the ineffectiveness associated with financial forward contracted electric and
gas sales, $37 million from the reversal of mark-to-market gains which ultimately settled as
financial revenues of which $25 million was related to economic hedges and $12 million was related
to trading activity. These decreases were partially offset by $31 million of gains associated with
open positions related to trading activity.
Discontinued Hedge Accounting During the first half of 2009, a relatively sharp decline in
commodity prices resulted in falling power prices and expected lower power generation for the
remainder of 2009. As such, NRG discontinued cash flow hedge accounting for certain 2009 contracts
previously accounted for as cash flow hedges. These contracts were originally entered into as
hedges of forecasted sales by baseload plants in Texas and Northeast. As a result, $217 million of
gain previously deferred in OCI was recognized in earnings for the six months ended June 30, 2009.
Discontinued Normal Purchase and Sale for Coal Purchases Due to the decline in commodity
prices during the first quarter of 2009, the Companys coal consumption was lower than forecasted,
and the Company built-up inventory due to lower baseload plant generation. The Company expected to
net settle some of its coal purchases under NPNS designation and thus was no longer able to assert
physical delivery under these coal contracts. The forward positions previously treated as accrual
accounting have been reclassified into mark-to-market accounting during the first quarter and
prospectively. The impact of discontinuance of coal NPNS designated transactions resulted in a
derivative loss of $29 million that is reflected in the cost of operations for the six months ended
June 30, 2009.
Note 7 Long-Term Debt
2019 Senior Notes
On June 5, 2009, NRG issued $700 million aggregate principal amount of 8.5% Senior Notes due
2019, or 2019 Senior Notes, at a discount resulting in a yield of 8.75%. The 2019 Senior Notes
were issued under an Indenture, dated February 2, 2006, between NRG and Law Debenture Trust Company
of New York, as trustee, as amended through Supplemental Indentures, which is discussed in Note 11
Debt and Capital Leases, in the Companys Annual Report on Form 10-K for the fiscal year ended
December 31, 2008. The Indentures and the form of the notes provide, among other things, that the
2019 Senior Notes will be senior unsecured obligations of NRG.
The net proceeds of $678 million are intended to be used to facilitate the early termination
of NRGs obligations pursuant to the CSRA, anticipated in the late third or early fourth quarter
2009. Prior to the termination, or in the event NRG does not reach agreement on acceptable terms
with either Merrill Lynch or its counterparties, the net proceeds will be available for general
corporate purposes. Interest is payable semi-annually on the 2019 Senior Notes beginning on
December 15, 2009 until their maturity date of June 15, 2019. As of June 30, 2009, $700 million in
principal was outstanding under the 2019 Senior Notes.
Prior to June 15, 2012, NRG may redeem up to 35% of the aggregate principal amount of the 2019
Senior Notes with the net proceeds of certain equity offerings, at a redemption price of 108.5% of
the principal amount. Prior to June 15, 2014, NRG may redeem all or a portion of the 2019 Senior
Notes at a price equal to 100% of the principal amount plus a premium and accrued and unpaid
interest. The premium is the greater of (i) 1% of the principal amount of the note; or (ii) the
excess of the principal amount of the note over the following: the present value of 104.25% of the
note, plus interest payments due on the note from the date of redemption through June 15, 2014,
discounted at a Treasury rate plus 0.50%. In addition, on or after June 15, 2014, NRG may redeem
some or all of the notes at redemption prices expressed as percentages of principal amount as set
forth in the following table, plus accrued and unpaid interest on the notes redeemed to the first applicable
redemption date:
28
|
|
|
|
|
|
|
Redemption |
|
Redemption Period |
|
Percentage |
|
|
June 15, 2014 to June 14, 2015 |
|
|
104.25% |
|
June 15, 2015 to June 14, 2016 |
|
|
102.83% |
|
June 15, 2016 to June 14, 2017 |
|
|
101.42% |
|
June 15, 2017 and thereafter |
|
|
100.00% |
|
|
Interest Rate Swaps
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 February 1, 2013.
Reliant Energy Acquisition
See discussion in Note 3, Business Acquisition, regarding the CSRA as a result of the
acquisition of Reliant Energy on May 1, 2009. Further, see discussion in Note 3, Business
Acquisition, regarding the $50 million working capital facility entered into on May 1, 2009, of
which $25 million is outstanding as of June 30, 2009.
Senior Credit Facility
In March 2009, NRG made a repayment of approximately $197 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.
TANE Facility
On February 24, 2009, Nuclear Innovation North America LLC, or NINA, executed an Engineering,
Procurement and Construction, or EPC, agreement with Toshiba American Nuclear Energy Corporation,
or 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 a credit facility, or 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, 2009, no amounts
have been borrowed under the TANE Facility. NINA will be required to repay all outstanding amounts
associated with its existing $20 million non-recourse revolving credit facility before borrowing
under the TANE Facility.
Debt Related to Capital Allocation Program
Share Lending Agreements On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted
subsidiaries of the Company, entered into Share Lending Agreements with affiliates of Credit Suisse
Group, or CS, relating to the shares of NRG common stock currently held by CSF I and II in
connection with the CSF I and CSF II issued notes and preferred interests agreements, or CSF Debt,
originally entered into during the third quarter 2006, by and between CSF I and II and affiliates
of CS. The Company entered into Share Lending Agreements due to the current lack of liquidity in
the stock borrow market for NRG shares and in order to maintain the intended economic benefits of
the CSF Debt agreements. As of June 30, 2009, CSF I and II have lent affiliates of CS 12,000,000
shares of the 21,970,903 shares of NRG common stock held by CSF I and II. The Share Lending
Agreements permit affiliates of CS to borrow up to the total number of shares of NRG common stock
held by CSF I and II.
29
Shares borrowed by affiliates of CS under the Share Lending Agreements will be used to replace
shares borrowed by affiliates of CS from third parties in connection with CS hedging activities
related to the financing agreements.
The shares are expected to be returned upon the termination of the financing agreements.
Until the shares are returned, the shares will be treated as outstanding for corporate law
purposes, and accordingly, the holders of the borrowed shares will have all of the rights of a
holder of the Companys outstanding shares, including the right to vote the shares on all matters
submitted to a vote of the Companys stockholders. However, because the CS affiliates must return
all borrowed shares (or identical shares), the borrowed shares are not considered outstanding for
the purpose of computing and reporting the Companys basic or diluted earnings per share.
Adoption of FSP APB 14-1 As discussed in Note 1, Basis of Presentation, the Company adopted
FSP APB 14-1 on January 1, 2009. The following table summarizes certain information related to the
CSF Debt in accordance with FSP APB 14-1:
|
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
|
|
|
2009 |
|
2008 |
|
|
Equity Component |
|
|
|
|
|
|
|
|
|
Additional Paid-in Capital |
|
$ |
14 |
|
|
$ |
14 |
|
|
|
Liability Component |
|
|
|
|
|
|
|
|
|
Principal amount |
|
$ |
333 |
|
|
$ |
333 |
|
|
Unamortized discount |
|
|
(5 |
) |
|
|
(8 |
) |
|
|
Net carrying amount |
|
$ |
328 |
|
|
$ |
325 |
|
|
|
The unamortized discount will be amortized through the maturity of the CSF Debt. The CSF I
debt has a maturity date of June 2010 and the CSF II debt has a maturity date of October 2009.
Interest expense for the CSF Debt, including the debt discount amortization for the three and six
months ended June 30, 2009, was $9 million and $18 million, respectively. Interest expense for the
CSF Debt, including the debt discount amortization for the three and six months ended June 30, 2008
was $9 million and $19 million, respectively. The effective interest rate as of June 30, 2009, was
11.4% for the CSF I debt and 12.1% for the CSF II debt.
Dunkirk Power LLC Tax-Exempt Bonds On April 15, 2009, NRG executed a $59 million tax-exempt
bond financing through its wholly owned subsidiary, Dunkirk Power LLC. The bonds were issued by
the County of Chautauqua Industrial Development Agency and will be used for construction of
emission control equipment on the Dunkirk Generating Station in Dunkirk, NY. The bonds initially
bear weekly interest based on the Securities Industry and Financial Markets Association, or SIFMA,
rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the
Companys Revolving Credit Facility covering amounts drawn on the facility. The proceeds received
through June 30, 2009 were $34 million with the remaining balance being released over time as
construction costs are paid.
GenConn Energy LLC related financings On April 27, 2009, a wholly owned subsidiary of NRG
closed on an equity bridge loan facility, or EBL, in the amount of $121.5 million from a syndicate
of banks. The purpose of the EBL is to fund the Companys proportionate share of the project
construction costs required to be contributed into GenConn Energy LLC, or GenConn, a 50% equity
method investment of the Company. The EBL, which is fully collateralized with a letter of credit
issued under the Companys Synthetic Letter of Credit Facility covering amounts drawn on the
facility, will bear interest at a rate of LIBOR plus 2% on drawn amounts. The EBL will mature on
the earlier of the commercial operations date of the Middletown project or July 26, 2011. The EBL
also requires mandatory prepayment of the portion of the loan utilized to pay costs of the Devon
project, of approximately $56 million, on the earlier of Devons commercial operations date or
January 27, 2011. The proceeds of the EBL received through June 30, 2009 were $70 million and the
remaining amounts will be drawn as necessary to fund construction costs.
In April 2009, GenConn secured financing for 50% of the Devon and Middletown project
construction costs through a 7-year term loan facility, and also entered into a 5-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.
30
Note 8 Changes in Capital Structure
The following table reflects the changes in NRGs common stock issued and outstanding during
the six months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized |
| |
Issued |
|
Treasury |
|
Outstanding |
|
Balance as of December 31, 2008 |
|
|
500,000,000 |
|
|
|
263,599,200 |
|
|
|
(29,242,483 |
) |
|
|
234,356,717 |
|
Shares issued from LTIP |
|
|
|
|
|
|
216,741 |
|
|
|
|
|
|
|
216,741 |
|
Shares issued under NRG Employee
Stock Purchase Plan, or ESPP |
|
|
|
|
|
|
|
|
|
|
41,706 |
|
|
|
41,706 |
|
Shares borrowed by affiliates of CS |
|
|
|
|
|
|
|
|
|
|
12,000,000 |
|
|
|
12,000,000 |
|
4.00% Preferred Stock conversion |
|
|
|
|
|
|
20,650 |
|
|
|
|
|
|
|
20,650 |
|
5.75% Preferred Stock conversion |
|
|
|
|
|
|
18,601,201 |
|
|
|
|
|
|
|
18,601,201 |
|
|
Balance as of June 30, 2009 |
|
|
500,000,000 |
|
|
|
282,437,792 |
|
|
|
(17,200,777 |
) |
|
|
265,237,015 |
|
|
Employee Stock Purchase Plan
As of June 30, 2009, there were 458,294 shares of treasury stock reserved for issuance under
the ESPP. In July 2009, 39,826 shares of common stock were issued to employee accounts from
treasury stock.
5.75% Preferred Stock
Certain holders of the Companys 5.75% convertible perpetual preferred stock, or 5.75%
Preferred Stock, elected to convert their preferred shares into NRG common shares prior to the
mandatory conversion date of March 16, 2009 at the minimum conversion rate of 8.2712. As of March
16, 2009, each remaining outstanding share of the 5.75% Preferred Stock automatically converted
into shares of common stock at a rate of 10.2564, based upon the applicable market value of NRGs
common stock. These conversions resulted in a decrease in preferred stock of $447 million, and a
corresponding increase in Additional Paid-in Capital. The following table summarizes the
conversion of the 5.75% Preferred Stock into NRG Common Stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
Conversion Rate |
|
Common Stock |
|
|
Shares |
|
(per share) |
|
Shares |
|
Balance as of December 31, 2008 |
|
|
1,841,680 |
|
|
|
|
|
|
|
|
|
Preferred shares converted by the holders prior to March 16, 2009 |
|
|
144,975 |
|
|
|
8.2712 |
|
|
|
1,199,116 |
|
Preferred shares automatically converted as of March 16, 2009 |
|
|
1,696,705 |
|
|
|
10.2564 |
|
|
|
17,402,085 |
|
|
Balance at June 30, 2009 |
|
|
|
|
|
|
|
|
|
|
18,601,201 |
|
|
4% Preferred Stock
As of June 30, 2009, 413 shares of the 4% Preferred Stock were converted into 20,650 shares of
common stock in 2009.
31
Note 9 Equity Compensation
Non-Qualified Stock Options, or NQSOs
The following table summarizes the Companys NQSO activity as of June 30, 2009, and changes
during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Aggregate Intrinsic |
|
|
|
|
|
|
Average |
|
Value |
|
|
Shares |
|
Exercise Price |
|
(In millions) |
|
Outstanding as of December 31, 2008 |
|
|
4,008,188 |
|
|
$ |
25.84 |
|
|
|
|
|
Granted |
|
|
1,297,300 |
|
|
|
23.37 |
|
|
|
|
|
Forfeited |
|
|
(103,768 |
) |
|
|
27.18 |
|
|
|
|
|
|
|
|
|
|
Outstanding at June 30, 2009 |
|
|
5,201,720 |
|
|
|
25.20 |
|
|
$ |
22 |
|
Exercisable at June 30, 2009 |
|
|
2,862,448 |
|
|
$ |
21.87 |
|
|
|
18 |
|
|
The weighted average grant date fair value of NQSOs granted for the six months ended June 30,
2009, was $8.48.
Restricted Stock Units, or RSUs
The following table summarizes the Companys non-vested RSU awards as of June 30, 2009, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant-Date |
|
|
Units |
|
Fair Value Per Unit |
|
Non-vested as of December 31, 2008 |
|
|
1,061,996 |
|
|
$ |
32.97 |
|
Granted |
|
|
160,100 |
|
|
|
23.35 |
|
Vested |
|
|
(293,312 |
) |
|
|
23.76 |
|
Forfeited |
|
|
(36,040 |
) |
|
|
33.00 |
|
|
Non-vested as of June 30, 2009 |
|
|
892,744 |
|
|
$ |
34.27 |
|
|
Performance Units, or PUs
The following table summarizes the Companys non-vested PU awards as of June 30, 2009, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant- Date |
|
|
Units |
|
Fair Value Per Unit |
|
Non-vested as of December 31, 2008 |
|
|
659,564 |
|
|
$ |
22.81 |
|
Granted |
|
|
310,800 |
|
|
|
22.52 |
|
Forfeited |
|
|
(262,864 |
) |
|
|
19.33 |
|
|
Non-vested as of June 30, 2009 |
|
|
707,500 |
|
|
$ |
24.15 |
|
|
In the first half of 2009, 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, 2009, and
changes during the six months then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
Grant- Date |
|
|
Units |
|
Fair Value Per Unit |
|
Outstanding as of December 31, 2008 |
|
|
260,768 |
|
|
$ |
18.50 |
|
Granted |
|
|
65,437 |
|
|
|
22.77 |
|
Conversions |
|
|
(22,156 |
) |
|
|
23.69 |
|
|
Outstanding as of June 30, 2009 |
|
|
304,049 |
|
|
$ |
19.34 |
|
|
32
Note 10 Earnings Per Share
Basic earnings per share attributable to NRG common stockholders is computed by dividing net
income attributable to NRG 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. The 12,000,000
shares outstanding under the Share Lending Agreements with CS affiliates are not treated as
outstanding for earnings per share purposes because the CS affiliates must return all borrowed
shares (or identical shares) upon termination of the Agreements. See Note 7 Long-Term Debt, for
more information on the Share Lending Agreements. 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.
The reconciliation of basic earnings per common share to diluted earnings per share
attributable to NRG is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months ended
June 30, |
|
Six months ended
June 30, |
(In millions, except per share data) |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Basic earnings per share attributable to NRG common
stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations, net of income taxes |
|
$ |
433 |
|
|
$ |
(41 |
) |
|
$ |
631 |
|
|
$ |
4 |
|
Dividends for preferred shares |
|
|
(7 |
) |
|
|
(14 |
) |
|
|
(21 |
) |
|
|
(28 |
) |
|
Net income/(loss) available to common stockholders from
continuing operations |
|
|
426 |
|
|
|
(55 |
) |
|
|
610 |
|
|
|
(24 |
) |
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
172 |
|
Net income attributable to NRG Energy, Inc. available to
common stockholders |
|
$ |
426 |
|
|
$ |
113 |
|
|
$ |
610 |
|
|
$ |
148 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
253.2 |
|
|
|
235.9 |
|
|
|
245.2 |
|
|
|
236.1 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations |
|
$ |
1.68 |
|
|
$ |
(0.23 |
) |
|
$ |
2.49 |
|
|
$ |
(0.10 |
) |
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
0.71 |
|
|
|
|
|
|
|
0.73 |
|
|
Net income attributable to NRG Energy, Inc. |
|
$ |
1.68 |
|
|
$ |
0.48 |
|
|
$ |
2.49 |
|
|
$ |
0.63 |
|
|
Diluted earnings per share attributable to NRG common
stockholders |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) available to common stockholders from
continuing operations |
|
$ |
426 |
|
|
$ |
(55 |
) |
|
$ |
610 |
|
|
$ |
(24 |
) |
Add preferred stock dividends for dilutive preferred stock |
|
|
4 |
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
Adjusted income/(loss) from continuing operations |
|
|
430 |
|
|
|
(55 |
) |
|
|
624 |
|
|
|
(24 |
) |
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
172 |
|
|
Net income attributable to NRG Energy, Inc. available to
common stockholders |
|
$ |
430 |
|
|
$ |
113 |
|
|
$ |
624 |
|
|
$ |
148 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
253.2 |
|
|
|
235.9 |
|
|
|
245.2 |
|
|
|
236.1 |
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method) |
|
|
1.0 |
|
|
|
|
|
|
|
1.0 |
|
|
|
|
|
Incremental shares attributable to assumed conversion
features of outstanding preferred stock (if-converted
method) |
|
|
21.0 |
|
|
|
|
|
|
|
29.1 |
|
|
|
|
|
|
Total dilutive shares |
|
|
275.2 |
|
|
|
235.9 |
|
|
|
275.3 |
|
|
|
236.1 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations |
|
$ |
1.56 |
|
|
$ |
(0.23 |
) |
|
$ |
2.27 |
|
|
$ |
(0.10 |
) |
Income from discontinued operations, net of income taxes |
|
|
|
|
|
|
0.71 |
|
|
|
|
|
|
|
0.73 |
|
|
Net income attributable to NRG Energy, Inc. |
|
$ |
1.56 |
|
|
$ |
0.48 |
|
|
$ |
2.27 |
|
|
$ |
0.63 |
|
|
For the three and six months ended June 30, 2008, basic and diluted per share amounts
were the same within each period reported because potential common shares had an anti-dilutive
effect on loss from continuing operations available to common shares and were excluded from the
computation.
33
Effects on Earnings per Share
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) |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Equity compensation (NQSOs and PUs) |
|
|
5.3 |
|
|
|
7.5 |
|
|
|
5.3 |
|
|
|
7.5 |
|
4.0% convertible preferred stock |
|
|
|
|
|
|
21.0 |
|
|
|
|
|
|
|
21.0 |
|
5.75% convertible preferred stock |
|
|
|
|
|
|
16.5 |
|
|
|
|
|
|
|
16.5 |
|
Embedded derivative of 3.625% redeemable perpetual
preferred stock |
|
|
16.0 |
|
|
|
16.0 |
|
|
|
16.0 |
|
|
|
16.0 |
|
Embedded derivative of CSF preferred interests and notes |
|
|
7.6 |
|
|
|
18.3 |
|
|
|
7.6 |
|
|
|
18.3 |
|
|
Total |
|
|
28.9 |
|
|
|
79.3 |
|
|
|
28.9 |
|
|
|
79.3 |
|
|
Note 11 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 the second quarter 2009, management changed its method for allocating Corporate general and
administrative expenses to the segments. Corporate general and administrative expenses had been
allocated based on budgeted segment revenues. Beginning in the second quarter 2009, Corporate
general and administrative expenses are allocated based on forecasted earnings/(losses) before
interest expense, income taxes, depreciation and amortization expense.
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
Reliant 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 |
|
|
Total assets |
|
$ |
4,405 |
|
|
$ |
13,680 |
|
|
$ |
1,788 |
|
|
$ |
929 |
|
|
$ |
268 |
|
|
$ |
766 |
|
|
$ |
197 |
|
|
$ |
22,809 |
|
|
$ |
(17,537 |
) |
|
$ |
27,305 |
|
|
(a) |
|
Reliant Energy balances are for the two months ended June 30, 2009. |
|
(b) |
|
Includes inter-segment sales of $66 million to Reliant Energy. |
If the Company continued using the 2008 allocation method for corporate general and
administrative expenses, the effect to net income/(loss) of each segment for the three months ended
June 30, 2009 would have been as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
attributable to
NRG Energy, Inc. as
reported |
|
$ |
233 |
|
|
$ |
99 |
|
|
$ |
42 |
|
|
$ |
(9 |
) |
|
$ |
19 |
|
|
$ |
125 |
|
|
$ |
|
|
|
$ |
(76 |
) |
|
$ |
|
|
|
$ |
433 |
|
Increase/(decrease) in
net income/(loss)
attributable to
NRG
Energy, Inc. |
|
|
(11 |
) |
|
|
8 |
|
|
|
4 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net
income/(loss)
attributable to
NRG
Energy, Inc. |
|
$ |
222 |
|
|
$ |
107 |
|
|
$ |
46 |
|
|
$ |
(10 |
) |
|
$ |
19 |
|
|
$ |
125 |
|
|
$ |
|
|
|
$ |
(76 |
) |
|
$ |
|
|
|
$ |
433 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2008 |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
751 |
|
|
$ |
265 |
|
|
$ |
172 |
|
|
$ |
49 |
|
|
$ |
43 |
|
|
$ |
34 |
|
|
$ |
3 |
|
|
$ |
(1 |
) |
|
$ |
1,316 |
|
Depreciation and amortization |
|
|
113 |
|
|
|
25 |
|
|
|
17 |
|
|
|
3 |
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
161 |
|
Equity in (losses)/earnings of
unconsolidated affiliates |
|
|
(32 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19 |
) |
Income/(loss) from continuing
operations before income taxes |
|
|
14 |
|
|
|
(45 |
) |
|
|
(6 |
) |
|
|
13 |
|
|
|
23 |
|
|
|
2 |
|
|
|
(85 |
) |
|
|
(10 |
) |
|
|
(94 |
) |
Income from discontinued
operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
168 |
|
Net income/(loss) attributable
to
NRG Energy, Inc. |
|
$ |
13 |
|
|
$ |
(45 |
) |
|
$ |
(6 |
) |
|
$ |
13 |
|
|
$ |
186 |
|
|
$ |
2 |
|
|
$ |
(26 |
) |
|
$ |
(10 |
) |
|
$ |
127 |
|
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009 |
|
Reliant 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 balances are for the two months ended June 30, 2009. |
|
(b) |
|
Includes inter-segment sales of $66 million to Reliant Energy. |
If the Company continued using the 2008 allocation method for corporate general and
administrative expenses, the effect to net income/(loss) of each segment for the six months ended
June 30, 2009 would have been as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
attributable to
NRG
Energy, Inc. as
reported |
|
$ |
233 |
|
|
$ |
316 |
|
|
$ |
253 |
|
|
$ |
(8 |
) |
|
$ |
16 |
|
|
$ |
137 |
|
|
$ |
4 |
|
|
$ |
(320 |
) |
|
$ |
|
|
|
$ |
631 |
|
Increase/(decrease) in
net income/(loss)
attributable to NRG
Energy, Inc. |
|
|
(11 |
) |
|
|
8 |
|
|
|
4 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net
income/(loss)
attributable to
NRG
Energy, Inc. |
|
$ |
222 |
|
|
$ |
324 |
|
|
$ |
257 |
|
|
$ |
(9 |
) |
|
$ |
16 |
|
|
$ |
137 |
|
|
$ |
4 |
|
|
$ |
(320 |
) |
|
$ |
|
|
|
$ |
631 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2008 |
|
Texas |
|
Northeast |
|
Central |
|
West |
|
International |
|
Thermal |
|
Corporate |
|
Elimination |
|
Total |
|
Operating revenues |
|
$ |
1,400 |
|
|
$ |
625 |
|
|
$ |
351 |
|
|
$ |
87 |
|
|
$ |
81 |
|
|
$ |
78 |
|
|
$ |
(2 |
) |
|
$ |
(2 |
) |
|
$ |
2,618 |
|
Depreciation and amortization |
|
|
226 |
|
|
|
51 |
|
|
|
34 |
|
|
|
4 |
|
|
|
|
|
|
|
5 |
|
|
|
2 |
|
|
|
|
|
|
|
322 |
|
Equity in (losses)/earnings
of unconsolidated affiliates |
|
|
(50 |
) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23 |
) |
Income/(loss) from continuing
operations before income
taxes |
|
|
81 |
|
|
|
14 |
|
|
|
33 |
|
|
|
25 |
|
|
|
47 |
|
|
|
7 |
|
|
|
(192 |
) |
|
|
(10 |
) |
|
|
5 |
|
Income from discontinued
operations, net of income
taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172 |
|
Net income/(loss)
attributable to
NRG Energy,
Inc. |
|
$ |
50 |
|
|
$ |
14 |
|
|
$ |
33 |
|
|
$ |
25 |
|
|
$ |
210 |
|
|
$ |
7 |
|
|
$ |
(153 |
) |
|
$ |
(10 |
) |
|
$ |
176 |
|
|
36
Note 12 Income Taxes
Effective Tax Rate
Income taxes included in continuing operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
(In millions except otherwise noted) |
|
2009 |
|
2008 |
|
Income tax expense (benefit) |
|
$ |
150 |
|
|
$ |
(53 |
) |
Effective tax rate |
|
|
25.8 |
% |
|
|
56.4 |
% |
|
For the three months ended June 30, 2009, NRGs overall effective tax rate on continuing
operations was different than the statutory rate of 35% primarily due to a reduction in the state
and local income tax rate as a result of the Reliant Energy acquisition and the sale
of the MIBRAG facility. For the three months ended June 30, 2008, NRGs effective tax rate was
increased primarily due to the movement of the valuation allowance established as result of capital
losses generated in the period for which there is no projected capital gain or available tax
planning strategies.
Income taxes included in continuing operations were as follows:
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
(In millions except otherwise noted) |
|
2009 |
|
2008 |
|
Income tax expense |
|
$ |
448 |
|
|
$ |
1 |
|
Effective tax rate |
|
|
41.5 |
% |
|
|
20.0 |
% |
|
For the six months ended June 30, 2009, NRGs overall effective tax rate on continuing
operations 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 reduction of the state
and local income tax rate as a result of the Reliant Energy acquisition. For the six months ended
June 30, 2008, NRGs overall effective tax rate was reduced primarily by foreign earnings that are
taxed at rates in foreign jurisdictions lower than the U.S. statutory rate.
Deferred tax assets, liabilities and valuation allowance
On a provisional basis, NRG established deferred tax assets of $1,205 million and deferred tax
liabilities of $1,194 million as a result of NRGs acquisition of Reliant Energy.
37
Valuation Allowance
As of June 30, 2009, the Companys valuation allowance was increased by approximately $80
million primarily due to losses generated in the period from derivative trading
activity which require capital treatment for tax purposes. The Company increased its foreign
valuation allowance by approximately $10 million.
Uncertain tax benefits
As of June 30, 2009, NRG has recorded a $463 million non-current tax liability for
unrecognized tax benefits, resulting from taxable earnings for the period for which there are no
NOLs available to offset for financial statement purposes. NRG has accrued interest and penalties
related to these unrecognized tax benefits of approximately $9 million for the six months ended
June 30, 2009, and has accrued approximately $17 million since adoption. The Company recognizes
interest and penalties related to unrecognized tax benefits in income tax expense.
NRG is subject to examination by taxing authorities for income tax returns filed in the U.S.
federal jurisdiction and various state and foreign jurisdictions including major operations located
in Germany and Australia. The Company is no longer subject to U.S. federal income tax examinations
for years prior to 2002. With few exceptions, state and local income tax examinations are no longer
open for years before 2002. The Companys significant foreign operations are also no longer
subject to examination by local jurisdictions for years prior to 2000. The Company continues to be
under examination by the Internal Revenue Service.
Tax Receivable and Payable
As of June 30, 2009, the Company has recorded a tax receivable of approximately $49 million
that represents a domestic federal tax receivable of $9 million and state tax receivable of $40
million, net of $6 million reserve. In addition, the Company has recorded a current payable of
approximately $13 million which includes domestic tax payable of approximately $1 million as well
as foreign taxes payable of approximately $12 million.
38
Note 13 Benefit Plans and Other Postretirement Benefits
NRG Defined Benefit Plans
NRG sponsors and operates three defined benefit pension and other postretirement plans. The
NRG Plan for Bargained Employees and the NRG Plan for Non-Bargained Employees are maintained solely
for eligible legacy NRG participants. A third plan, the Texas Genco Retirement Plan, is maintained
for participation solely by eligible employees. The total amount of employer contributions paid
for the six months ended June 30, 2009 was $14 million. NRG expects to make $16 million in further
contributions for the remainder of 2009. The total 2009 planned contribution of $30 million was a
decrease of $30 million from the expected contributions as disclosed in Note 12 Benefit Plans
and Other Postretirement Benefits, in the Companys Annual Report on Form 10-K for the fiscal year
ended December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption
by the Company in March 2009 of the new funding method options now available. The new methods were
made allowable under new IRS guidance on the application of recent Congressional legislation on
funding requirements.
The net periodic pension cost related to all of the Companys defined benefit pension plans
include the following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plans |
|
|
|
Three months ended June 30, |
|
|
Six months ended June 30, |
|
(In millions) |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Service cost benefits earned |
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
7 |
|
|
$ |
7 |
|
Interest cost on benefit obligation |
|
|
5 |
|
|
|
4 |
|
|
|
10 |
|
|
|
9 |
|
Prior service cost |
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
Net gain |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
Expected return on plan assets |
|
|
(4 |
) |
|
|
(3 |
) |
|
|
(8 |
) |
|
|
(7 |
) |
|
Net periodic benefit cost |
|
$ |
5 |
|
|
$ |
3 |
|
|
$ |
10 |
|
|
$ |
8 |
|
|
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) |
|
2009 |
|
2008 |
|
2009 |
|
2008 |
|
Service cost benefits earned |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
1 |
|
Interest cost on benefit obligation |
|
|
1 |
|
|
|
2 |
|
|
|
3 |
|
|
|
3 |
|
|
Net periodic benefit cost |
|
$ |
2 |
|
|
$ |
2 |
|
|
$ |
5 |
|
|
$ |
4 |
|
|
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, 2009 was $2 million. The Company recognized net periodic costs
related to its 44% interest in STP defined benefits plans of $2 million for both the three months
ended June 30, 2009 and 2008, respectively. The Company recognized net periodic costs related to
its 44% interest in STP defined benefits plans of $5 million and $4 million for the six months
ended June 30, 2009 and 2008, respectively.
39
Note 14 Commitments and Contingencies
Operating Lease Commitments
As a result of the acquisition of Reliant Energy, the Companys operating lease commitments
have increased primarily due to additional lease agreements for office space through 2021. As of
June 30, 2009, eight additional office space locations were under lease for future commitments of
approximately $89 million.
Fuel Commitments
NRG enters into long-term contractual arrangements to procure fuel and transportation services
for the Companys generation assets. NRGs total net coal commitments, which span from 2009 through
2012, decreased by approximately $266 million during the six months ended June 30, 2009 as the 2009
monthly commitments were settled. In addition, NRGs natural gas purchase commitments decreased by
approximately $162 million during the six months ended June 30, 2009, as the 2009 monthly
commitments were settled and average natural gas prices decreased.
Purchased Power Commitments
As a result of the acquisition of Reliant Energy, NRG is party to purchased power contracts of
various quantities and durations that are not classified as derivative assets and liabilities.
These contracts are not included in the consolidated balance sheet as of June 30, 2009. Minimum
purchase commitment obligations under these agreements are as follows as of June 30, 2009:
|
|
|
|
|
|
|
|
|
(In millions) |
|
Fixed Pricing(a) |
|
Variable Pricing(b) |
|
Remainder of 2009
|
|
$ |
46 |
|
|
$ |
85 |
|
2010
|
|
|
42 |
|
|
8 |
2011
|
|
|
24 |
|
|
|
2012
|
|
|
20 |
|
|
|
2013
|
|
|
10 |
|
|
|
|
Total
|
|
$ |
142 |
|
|
$ |
93 |
|
|
(a) |
|
As of June 30, 2009, the maximum remaining term under any individual purchased power
contract is four years. |
|
(b) |
|
For contracts with variable pricing components, estimated prices are based on forward
commodity curves as of June 30, 2009. |
Other
As a result of the acquisition of Reliant Energy, the Company acquired the naming rights,
including advertising and other benefits, for a football stadium and other convention and
entertainment facilities included in the stadium complex in Houston, Texas. Pursuant to this
agreement, the Company is required to pay $10 million per year through 2031.
See discussion in Note 3, Business Acquisition, regarding the CSRA as a result of the
acquisition of Reliant Energy on May 1, 2009.
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, 2009 and July 23, 2009, all hedges under the first and second liens were in-the-money on a
counterparty aggregate basis.
RepoweringNRG Initiatives
NRG has capitalized $32 million through June 30, 2009, for the repowering of its El Segundo
generating facility in California. As a result of permitting delays related to on-going Natural
Resource Defense Counsel claims, the El Segundo project will not reach its original completion date
of June 1, 2011. The Company is contemplating certain PPA modifications including the commercial
operations date.
40
Contingencies
Set forth below is a description of the Companys material legal proceedings. The Company
believes that it has valid defenses to these legal proceedings and intends to defend them
vigorously. Pursuant to the requirements of SFAS No. 5, Accounting for Contingencies, or SFAS 5,
and related guidance, NRG records reserves for estimated losses from contingencies when information
available indicates that a loss is probable and the amount of the loss, or range of loss, can be
reasonably estimated. In addition, legal 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 vary from its currently recorded
reserves and such differences could be material.
In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other
litigation or legal proceedings arising in the ordinary course of business. In managements
opinion, the disposition of these ordinary course matters will not materially adversely affect
NRGs consolidated financial position, results of operations, or cash flows.
Exelon Related Litigation
Delaware Chancery Court
On November 11, 2008, Exelon and its wholly-owned subsidiary Exelon Xchange filed a complaint
against NRG and NRGs Board of Directors. The complaint alleges, among other things, that NRGs
Board of Directors failed to give due consideration and to take appropriate action in response to
the acquisition proposal announced by Exelon on October 19, 2008, in which Exelon offered to
acquire all of the outstanding shares of NRG common stock at an exchange ratio of 0.485 Exelon
shares for each NRG common share. On November 14, 2008, NRG and NRGs Board of Directors filed a
motion to dismiss Exelons complaint on the grounds that it failed to state a claim upon which
relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss, Exelon and
Exelon Xchange filed an amended complaint. The amended complaint seeks, among other things,
declaratory and injunctive relief: (i) declaring that NRG and its Board of Directors breached its
fiduciary duties by summarily rejecting the October 19, 2008 Exelon offer, by resorting to
defensive measures to interfere with Exelons tender offer, and by making false and misleading
statements to NRG stockholders; (ii) compelling NRG and its Board of Directors to approve the
Exelon tender offer by waiving the application of Section 203 of the Delaware General Corporation
Law; (iii) compelling NRG and its Board of Directors from taking any actions with respect to
regulatory authorities that would thwart or interfere with the Exelon tender offer; and (iv)
compelling NRG and its Board of Directors to correct any false and misleading statements to NRG
stockholders and to disclose all material facts necessary for NRG stockholders to make informed
decisions regarding the October 19, 2008 Exelon offer. On April 17, 2009, NRG and NRGs Board of
Directors filed a partial motion to dismiss the amended complaint asserting that many of the claims
are subject to the business judgment rule, are premature, and should be dismissed for failure to
state a claim upon which relief can be granted. Briefing on the motion commenced on June 12, 2009,
and concluded on July 24, 2009. On July 28, 2009, Exelon, NRG, and NRGs Board of Directors collectively filed a Stipulation of Dismissal of Exelons lawsuit, thereby ending the case.
On December 11, 2008, the Louisiana Sheriffs Pension & Relief Fund and City of St. Claire
Shores Police & Fire Retirement System, on behalf of themselves and all others similarly situated,
served a previously filed complaint on NRG and its Board of Directors alleging substantially
similar allegations as the Exelon complaint. On December 23, 2008, NRG and NRGs Board of
Directors filed a motion to dismiss the complaint on the grounds that it failed to state a claim
upon which relief can be granted. On March 16, 2009, prior to responding to the motion to dismiss,
these plaintiffs filed an amended complaint against only NRGs Board of Directors. The amended
complaint seeks, among other things, declaratory and injunctive relief: (i) declaring that it is a
proper class action; (ii) declaring that the NRG Board of Directors breached its fiduciary duties
by summarily rejecting the October 19, 2008 Exelon offer and by resorting to defensive measures
designed to prevent any potential acquirer from entering into a value-maximizing transaction with
NRG; (iii) compelling NRGs Board of Directors to engage in a dialogue with Exelon to more fully
understand the October 19, 2008 offer and to determine the potential for any improvement thereon;
(iv) enjoining NRG from proceeding with the acquisition of Reliant Energys retail business; (v)
enjoining the NRGs Board of Directors from taking any actions designed to block a transaction with
Exelon; and (vi) awarding plaintiffs their costs and fees. On April 17, 2009, the NRG Board of
Directors filed a motion to dismiss the amended complaint asserting that it fails to state a claim
upon which relief can be granted. Briefing on the motion commenced on June 11, 2009, and will
conclude on a date to be determined at a July 31, 2009, hearing.
41
Mercer County, New Jersey Superior Court
On January 6, 2009, three lawsuits previously filed against NRG and NRGs Board of Directors
on behalf of individual shareholders and all others similarly situated were consolidated into one
case in the Law Division of the Superior Court of Mercer County, New Jersey. On January 21, 2009,
the plaintiffs filed an Amended Consolidated Complaint in which they allege a single count of
breach of fiduciary duty against NRGs Board of Directors and seek injunctive relief: (i) declaring
that the action is a class action and certifying plaintiffs as class plaintiffs and counsel as
class counsel; (ii) declaring that defendants breached their fiduciary duties by summarily
rejecting the Exelon offer; (iii) ordering defendants to negotiate with respect to the Exelon offer
or with respect to another transaction to maximize shareholder value; (iv) ordering defendants to
exempt Exelons offer from Section 203 of the Delaware General Corporations Law; (v) awarding
compensatory damages including interest; (vi) awarding plaintiffs costs and fees; and (vii)
granting other relief the Court deems proper. On February 20, 2009, NRGs Board of Directors filed
a motion to dismiss the amended consolidated complaint for failure to state a claim or, in the
alternative, to stay the action in favor of the Delaware Chancery Court proceedings. On March 19,
2009, the plaintiffs filed their response and on April 6, 2009, NRGs Board of Directors filed its
reply. On April 17, 2009, and again on May 7, 2009, oral argument was held and on June 18, 2009,
the court found in favor of NRGs Board of Directors and stayed the consolidated lawsuits pending
resolution of the purported class-action lawsuit filed in Delaware Chancery court by the Louisiana
Sheriffs Pension & Relief Fund and City of St. Claire Shores Police & Fire Retirement System.
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 FERC to clarify FERCs 2003 reasoning regarding its rejection of the original
complaint relating to the financial burdens under the contracts at issue and to alleged market
manipulation at the time these contracts were formed. As a result, the 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 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.
42
On April 27, 2009, the U.S. Supreme Court granted certiorari in an unrelated proceeding
involving the Mobile-Sierra doctrine that may affect the standard of review applied to the CDWR
contract on remand before the FERC. Specifically, on March 18, 2008,
the U.S. Court of Appeals for the DC Circuit rejected the appeals filed by the Attorneys
General of the State of Connecticut and Commonwealth of Massachusetts regarding the settlement that
established the current New England capacity market. The settlement, filed with FERC on March 7,
2006 provides for interim capacity transition payments for all generators in New England for the
period starting December 1, 2006 through May 31, 2010 and for the Forward Capacity Market
thereafter. The DC Circuit Court of Appeals rejected all substantive challenges to the settlement,
but sustained one procedural argument relating to the applicability of the Mobile-Sierra doctrine
to non-settling parties. NRG sought certiorari before the U.S. Supreme Court, which was granted on
April 27, 2009, and on July 8, 2009, NRG submitted its brief.
Louisiana Generating, LLC
On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S.
Environmental Protection Agency, or U.S. EPA, commenced a lawsuit against Louisiana Generating, LLC
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 Louisiana Generating, LLC 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, Louisiana Generating, LLC made several filings. First, 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. Second, it 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. Last, it filed in the federal district court for the
Middle District of Louisiana a Motion for an Extension of Time to File Responsive Pleadings arguing
that the court should extend the May 11, 2009, deadline to respond to the February 11, 2009 lawsuit
until such time as directed by the court following resolution of Louisiana Generating, LLCs Motion
for Stay of Proceedings Pending Resolution of Certain Bankruptcy Actions filed concurrently with
the Motion for an Extension of Time. On May 4, 2009, the Department of Justice filed its
opposition to the Motion for Stay. On June 4, 2009, after the recusal of the federal bankruptcy
judge in this matter, the federal district court for the Middle District of Louisiana issued an
order recommending that another bankruptcy judge be appointed to hear the matter. The decision, by
the Chief Judge of the U.S. Court of Appeals for the Fifth Circuit, has yet to be made. On June 8,
2009, the parties filed a joint status report setting forth their views of the case and proposing a
trial schedule. On June 18, 2009, Louisiana Generating, LLC filed a motion to bifurcate the
Department of Justice lawsuit into separate liability and remedy phases, and on June 30, 2009, the
Department of Justice filed its opposition.
43
Citizens for Clean Power
On November 6, 2008, Citizens for Clean Power, or CCP, filed a notice of its intent to file a
lawsuit under the CAA against Indian River Power, LLC, or IRP, seeking to enforce opacity
limitations applicable to units 1, 2, 3, and 4. On January 5, 2009, the Delaware Department of
Natural Resources and Environmental Control, or DNREC, filed a lawsuit relating to opacity issues
against IRP in the Superior Court in Kent County, Delaware. On January 6, 2009, DNREC and IRP
agreed to a consent order resolving the DNREC action in which IRP agreed to pay a $5,000 civil
penalty and agreed to purchase for DNRECs use an Ultrafine Particle Monitor for approximately
$60,000. The consent order was filed with the court on February 6, 2009, and entered by the court
on February 13, 2009, thereby precluding CCPs ability under the CAA to commence its noticed
lawsuit. On February 26, 2009, notwithstanding the entry of the consent order, CCP filed a
complaint against IRP, in federal district court in Delaware. The complaint seeks injunctive and
declarative relief in addition to civil penalties: (i) declaring that IRP violated the CAA through
6,304 opacity violations between 2004 and 2008; (ii) seeking civil penalties of up to $32,500 for
each such violation; (iii) enjoining IRP from violating the CAA; (iv) ordering IRP to assess and
mitigate any environmental injuries caused by its emissions; and (v) awarding CCP its fees and
costs. On March 25, 2009, IRP filed a motion to dismiss the complaint, on April 7, 2009, CCP filed
its opposition, and on April 20, 2009, IRP filed its reply. On July 23, 2009, the court dismissed
the case thereby ending the matter.
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 Public Utility
Commission of Texas, or 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
will occur on October 6, 2009.
In November 2008, CenterPoint Energy and RRI, 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.
Disputed Claims Reserve
As part of NRGs plan of reorganization, NRG funded a disputed claims reserve for the
satisfaction of certain general unsecured claims that were disputed claims as of the effective date
of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from
the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the
aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the
funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy
the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor
pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the
reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG
has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG
recognized the issuance of the common stock as of December 6, 2003, and removed the cash amounts
from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the
balance sheet when the common stock was issued and cash contributed.
44
On April 3, 2006, the Company made a supplemental distribution to creditors under the
Companys Chapter 11 bankruptcy plan, totaling $25 million in cash and 5,082,000 shares of common
stock. On December 18, 2008, NRG filed with the U.S. Bankruptcy Court for the Southern District of
New York a Closing Report and an Application for Final Decree Closing the Chapter 11 Case for NRG
Energy, Inc. et al and on December 29, 2008, the court entered the Final Decree. As of December
21, 2008, the reserve held approximately $9.8 million in cash and 1,282,783 shares of common stock.
On December 21, 2008, the Company issued an instruction letter to The Bank of New York Mellon to
distribute all remaining cash and stock in the Disputed Claims Reserve to NRGs creditors. On
January 12, 2009, The Bank of New York Mellon commenced the distribution of all remaining cash and
stock in the Disputed Claim Reserve to the Companys creditors pursuant to NRGs Chapter 11
bankruptcy plan and on July 13, 2009, that distribution was complete.
Note 15 Regulatory Matters
NRG operates in a highly regulated industry and is subject to regulation by various federal
and state agencies. As such, NRG is affected by regulatory developments at both the federal and
state levels and in the regions in which NRG operates. In addition, NRG is subject to the market
rules, procedures and protocols of the various ISO markets in which NRG participates. These 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 By Order dated March 17, 2009, the U.S. Court of Appeals for the DC Circuit denied the
remaining appeals of the FERC orders establishing the RPM capacity market. In February of 2009, the
entities representing load interests, including the New Jersey Board of Public Utilities, the
District of Columbia Office of the Peoples Counsel, and the Maryland Office of Peoples Counsel,
agreed to withdraw their appeals regarding the establishment of the RPM market design.
On June 18, 2009, FERC denied rehearing of its order dated September 19, 2008 dismissing a
complaint filed by the Maryland Public Service Commission, together with other load interests,
against PJM challenging the results of the 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, and thus the auction prices are expected to
be realized.
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. Reliant Energy Power Supply, or 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.
45
Note 16 Environmental Matters
The construction and operation of power projects are subject to stringent environmental and
safety protection and land use laws and regulation in the U.S. If such laws and regulations become
more stringent, or new laws, interpretations or compliance policies apply and NRGs facilities are
not exempt from coverage, the Company could be required to make modifications to further reduce
potential environmental impacts. New legislation and regulations to mitigate the effects of
greenhouse gases, or GHGs, including CO2 from power plants, are under consideration at
the federal and state levels. In general, the effect of such future laws or regulations is expected
to require the addition of pollution control equipment or the imposition of restrictions or
additional costs on the Companys operations.
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that environmental capital
expenditures to be incurred during the remainder of 2009 through 2013 to meet NRGs environmental
commitments will be approximately $1.1 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, 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. This estimate reflects anticipated
schedules and controls related to the Clean Air Interstate Rule, or CAIR, 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.
Northeast Region
NRG operates electric generating units located in Connecticut, Delaware, Maryland,
Massachusetts and New York which are subject to RGGI. These units must surrender one allowance for
every U.S. ton of CO2 emitted with true up for 2009-2011 occurring in 2012. Allowances
are partially allocated only in the state of Delaware. In 2008, NRG emitted approximately 12
million tonnes of CO2 in RGGI states, although 2009 is tracking lower than 2008 year to
date. NRG believes that to the extent CO2 will not be fully reflected in wholesale
electricity prices, the direct financial impact on the Company is likely to be negative as costs
will be incurred in the course of securing the necessary RGGI allowances and offsets at auction and
in the market.
In January 2006, NRGs Indian River Operations, Inc. received a letter of informal
notification from the DNREC stating that the Company may be a potentially responsible party with
respect to a historic captive landfill. On October 1, 2007, NRG signed an agreement with DNREC to
investigate the site through the Voluntary Clean-up Program. On February 4, 2008, the DNREC issued
findings that no further action is required in relation to surface water and that a previously
planned shoreline stabilization project would adequately address 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, the 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 the DNREC and other trustees to close out
the assessment phase.
South Central Region
On February 11, 2009, the U.S. Department of Justice acting at the request of the U.S. EPA
commenced a lawsuit against Louisiana Generating, LLC 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 Louisiana Generating, LLC on February 15, 2005, and on
December 8, 2006. Further discussion on this matter can be found in Note 14 Commitments and
Contingencies, Louisiana Generating, LLC.
46
Note 17 Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and
guarantee provisions as a routine part of the Companys business activities. Examples of these
contracts include asset purchases and sale agreements, commodity sale and purchase agreements,
retail contracts, joint venture agreements, EPC agreements, operation and maintenance agreements,
service agreements, settlement agreements, and other types of contractual agreements with vendors
and other third parties, as well as affiliates. These contracts generally indemnify the
counterparty for tax, environmental liability, litigation and other matters, as well as breaches of
representations, warranties and covenants set forth in these agreements. In some cases, NRGs
maximum potential liability cannot be estimated, since the underlying agreements contain no limits
on potential liability. The Company is also obligated with respect to customer deposits associated with Reliant Energy.
This Note 17 should be read in conjunction with the complete description under Note 25,
Guarantees, to the Companys financial statements in its Annual Report on Form 10-K for the year
ended December 31, 2008.
In connection with the agreement to sell its 50% ownership interest in Mibrag B.V., NRG
executed an agreement guaranteeing the performance of its subsidiary Lambique Beheer under the
purchase and sale agreement. This agreement indemnifies the buyer for tax, environmental liability
and other matters, as well as breaches of representations and warranties and is limited to EUR 206
million.
NRG signed a guarantee agreement on behalf of its subsidiary NRG Retail, LLC guaranteeing the
payment and performance of its obligations under the LLC Membership Interest Purchase Agreement and
related agreements with RRI in connection with the purchase of its retail business, including purchase price and acquired net working capital. In accordance with the LLC Membership Interest Purchase
Agreement, on May 1, 2009, NRG signed an agreement guaranteeing payments up to $85 million related
to the Restated Power Purchase Agreement with FPL Energy Upton Wind II, LLC. NRG has no reason to
believe that the Company currently has any material liability relating to such routine
indemnification obligations.
47
Note 18 Condensed Consolidating Financial Information
As of June 30, 2009, 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, 2009:
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Arthur Kill Power LLC
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NRG Devon Operations Inc. |
Astoria Gas Turbine Power LLC
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NRG Dunkirk Operations, Inc. |
Berrians I Gas Turbine Power LLC
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NRG El Segundo Operations Inc. |
Big Cajun II Unit 4 LLC
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NRG Generation Holdings, Inc. |
Cabrillo Power I LLC
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NRG Huntley Operations Inc. |
Cabrillo Power II LLC
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NRG International LLC |
Chickahominy River Energy Corp.
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NRG Kaufman LLC |
Commonwealth Atlantic Power LLC
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NRG Mesquite LLC |
Conemaugh Power LLC
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NRG MidAtlantic Affiliate Services Inc. |
Connecticut Jet Power LLC
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NRG Middletown Operations Inc. |
Devon Power LLC
|
|
NRG Montville Operations Inc. |
Dunkirk Power LLC
|
|
NRG New Jersey Energy Sales LLC |
Eastern Sierra Energy Company
|
|
NRG New Roads Holdings LLC |
El Segundo Power, LLC
|
|
NRG North Central Operations, Inc. |
El Segundo Power II LLC
|
|
NRG Northeast Affiliate Services Inc. |
GCP Funding Company LLC
|
|
NRG Norwalk Harbor Operations Inc. |
Hanover Energy Company
|
|
NRG Operating Services Inc. |
Hoffman Summit Wind Project LLC
|
|
NRG Oswego Harbor Power Operations Inc. |
Huntley IGCC LLC
|
|
NRG Power Marketing LLC |
Huntley Power LLC
|
|
NRG Rocky Road LLC |
Indian River IGCC LLC
|
|
NRG Saguaro Operations Inc. |
Indian River Operations Inc.
|
|
NRG South Central Affiliate Services Inc. |
Indian River Power LLC
|
|
NRG South Central Generating LLC |
James River Power LLC
|
|
NRG South Central Operations Inc. |
Kaufman Cogen LP
|
|
NRG South Texas LP |
Keystone Power LLC
|
|
NRG Texas LLC |
Lake Erie Properties Inc.
|
|
NRG Texas C & I Supply LLC (a) |
Langford Wind Power, LLC (a)
|
|
NRG Texas Holding Inc. (a) |
Louisiana Generating LLC
|
|
NRG Texas Power LLC |
Middletown Power LLC
|
|
NRG West Coast LLC |
Montville IGCC LLC
|
|
NRG Western Affiliate Services Inc. |
Montville Power LLC
|
|
Oswego Harbor Power LLC |
NEO Chester-Gen LLC
|
|
Padoma Wind Power, LLC |
NEO Corporation
|
|
Reliant Energy Services Texas LLC (a) |
NEO Freehold-Gen LLC
|
|
Reliant Energy Texas Retail LLC (a) |
NEO Power Services Inc.
|
|
Saguaro Power LLC |
New Genco GP LLC
|
|
San Juan Mesa Wind Project II, LLC |
Norwalk Power LLC
|
|
Somerset Operations Inc. |
NRG Affiliate Services Inc.
|
|
Somerset Power LLC |
NRG Arthur Kill Operations Inc.
|
|
Texas Genco Financing Corp. |
NRG Asia-Pacific Ltd.
|
|
Texas Genco GP, LLC |
NRG Astoria Gas Turbine Operations Inc.
|
|
Texas Genco Holdings, Inc. |
NRG Bayou Cove LLC
|
|
Texas Genco LP, LLC |
NRG Cabrillo Power Operations Inc.
|
|
Texas Genco Operating Services, LLC |
NRG Cadillac Operations Inc.
|
|
Texas Genco Services, LP |
NRG California Peaker Operations LLC
|
|
Vienna Operations, Inc. |
NRG Cedar Bayou Development Company LLC
|
|
Vienna Power LLC |
NRG Connecticut Affiliate Services Inc.
|
|
WCP (Generation) Holdings LLC |
NRG Construction LLC
|
|
West Coast Power LLC |
| (a) |
|
Added as guarantors to the 2019 Notes on July 14, 2009. |
48
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.
49
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/(loss), net |
|
|
2 |
|
|
|
(12 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(11 |
) |
Interest expense |
|
|
(18 |
) |
|
|
(38 |
) |
|
|
(103 |
) |
|
|
|
|
|
|
(159 |
) |
|
Total other income/(expense) |
|
|
107 |
|
|
|
80 |
|
|
|
373 |
|
|
|
(597 |
) |
|
|
(37 |
) |
|
Income/(Losses) 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 attributable to NRG Energy, Inc. |
|
$ |
264 |
|
|
$ |
333 |
|
|
$ |
433 |
|
|
$ |
(597 |
) |
|
$ |
433 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
50
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/(loss), net |
|
|
3 |
|
|
|
(19 |
) |
|
|
2 |
|
|
|
|
|
|
|
(14 |
) |
Interest expense |
|
|
(66 |
) |
|
|
(59 |
) |
|
|
(172 |
) |
|
|
|
|
|
|
(297 |
) |
|
Total other income/(expense) |
|
|
70 |
|
|
|
73 |
|
|
|
704 |
|
|
|
(1,003 |
) |
|
|
(156 |
) |
|
Income/(Losses) 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. |
51
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
NRG Energy, Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
8 |
|
|
$ |
433 |
|
|
$ |
1,841 |
|
|
$ |
|
|
|
$ |
2,282 |
|
Funds deposited by counterparties |
|
|
468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
468 |
|
Restricted cash |
|
|
1 |
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
19 |
|
Accounts receivable, net |
|
|
372 |
|
|
|
814 |
|
|
|
|
|
|
|
|
|
|
|
1,186 |
|
Inventory |
|
|
514 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
530 |
|
Derivative instruments valuation |
|
|
3,360 |
|
|
|
1,308 |
|
|
|
|
|
|
|
(274 |
) |
|
|
4,394 |
|
Cash collateral paid in support of
energy risk management activities |
|
|
214 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
243 |
|
Prepayments and other current assets |
|
|
133 |
|
|
|
78 |
|
|
|
200 |
|
|
|
(201 |
) |
|
|
210 |
|
|
Total current assets |
|
|
5,070 |
|
|
|
2,696 |
|
|
|
2,041 |
|
|
|
(475 |
) |
|
|
9,332 |
|
|
Net property, plant and equipment |
|
|
10,653 |
|
|
|
927 |
|
|
|
29 |
|
|
|
|
|
|
|
11,609 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
421 |
|
|
|
221 |
|
|
|
16,467 |
|
|
|
(17,109 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
31 |
|
|
|
332 |
|
|
|
|
|
|
|
|
|
|
|
363 |
|
Capital leases and notes receivable,
less current portion |
|
|
4,113 |
|
|
|
483 |
|
|
|
3,018 |
|
|
|
(7,131 |
) |
|
|
483 |
|
Goodwill |
|
|
1,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,718 |
|
Intangible assets, net |
|
|
800 |
|
|
|
1,308 |
|
|
|
34 |
|
|
|
(31 |
) |
|
|
2,111 |
|
Nuclear decommissioning trust fund |
|
|
316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
316 |
|
Derivative instruments valuation |
|
|
864 |
|
|
|
547 |
|
|
|
11 |
|
|
|
(234 |
) |
|
|
1,188 |
|
Other non-current assets |
|
|
32 |
|
|
|
10 |
|
|
|
143 |
|
|
|
|
|
|
|
185 |
|
|
Total other assets |
|
|
8,295 |
|
|
|
2,901 |
|
|
|
19,673 |
|
|
|
(24,505 |
) |
|
|
6,364 |
|
|
Total Assets |
|
$ |
24,018 |
|
|
$ |
6,524 |
|
|
$ |
21,743 |
|
|
$ |
(24,980 |
) |
|
$ |
27,305 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and
capital leases |
|
$ |
73 |
|
|
$ |
421 |
|
|
$ |
32 |
|
|
$ |
(73 |
) |
|
$ |
453 |
|
Accounts payable |
|
|
(583 |
) |
|
|
1,010 |
|
|
|
430 |
|
|
|
|
|
|
|
857 |
|
Derivative instruments valuation |
|
|
2,593 |
|
|
|
1,871 |
|
|
|
6 |
|
|
|
(274 |
) |
|
|
4,196 |
|
Deferred income taxes |
|
|
575 |
|
|
|
(220 |
) |
|
|
(309 |
) |
|
|
|
|
|
|
46 |
|
Cash collateral received in support of
energy risk management activities |
|
|
468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
468 |
|
Accrued expenses and other current
liabilities |
|
|
176 |
|
|
|
283 |
|
|
|
287 |
|
|
|
(128 |
) |
|
|
618 |
|
|
Total current liabilities |
|
|
3,302 |
|
|
|
3,365 |
|
|
|
446 |
|
|
|
(475 |
) |
|
|
6,638 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
2,576 |
|
|
|
953 |
|
|
|
11,896 |
|
|
|
(7,131 |
) |
|
|
8,294 |
|
Nuclear decommissioning reserve |
|
|
292 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
292 |
|
Nuclear decommissioning trust liability |
|
|
217 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
217 |
|
Deferred income taxes |
|
|
684 |
|
|
|
124 |
|
|
|
756 |
|
|
|
|
|
|
|
1,564 |
|
Derivative instruments valuation |
|
|
275 |
|
|
|
776 |
|
|
|
89 |
|
|
|
(234 |
) |
|
|
906 |
|
Out-of-market contracts |
|
|
259 |
|
|
|
150 |
|
|
|
|
|
|
|
(31 |
) |
|
|
378 |
|
Other non-current liabilities |
|
|
419 |
|
|
|
29 |
|
|
|
466 |
|
|
|
|
|
|
|
914 |
|
|
Total non-current liabilities |
|
|
4,722 |
|
|
|
2,032 |
|
|
|
13,207 |
|
|
|
(7,396 |
) |
|
|
12,565 |
|
|
Total liabilities |
|
|
8,024 |
|
|
|
5,397 |
|
|
|
13,653 |
|
|
|
(7,871 |
) |
|
|
19,203 |
|
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
15,994 |
|
|
|
1,127 |
|
|
|
7,843 |
|
|
|
(17,109 |
) |
|
|
7,855 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
24,018 |
|
|
$ |
6,524 |
|
|
$ |
21,743 |
|
|
$ |
(24,980 |
) |
|
$ |
27,305 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
52
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 |
|
|
$ |
631 |
|
|
$ |
(1,003 |
) |
|
$ |
631 |
|
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 by/(used by) changes in other working
capital, net of acquisition |
|
|
532 |
|
|
|
170 |
|
|
|
(941 |
) |
|
|
|
|
|
|
(239 |
) |
|
Net Cash Provided/(Used) by Operating Activities |
|
|
1,596 |
|
|
|
310 |
|
|
|
(524 |
) |
|
|
(660 |
) |
|
|
722 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany loans to 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 by Investing Activities |
|
|
(1,204 |
) |
|
|
262 |
|
|
|
(299 |
) |
|
|
741 |
|
|
|
(500 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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) financing element of acquired
derivatives |
|
|
102 |
|
|
|
(124 |
) |
|
|
|
|
|
|
|
|
|
|
(22 |
) |
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 Equivalents |
|
|
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. |
53
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
|
|
|
|
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
1,222 |
|
|
$ |
94 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,316 |
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
946 |
|
|
|
65 |
|
|
|
1 |
|
|
|
(1 |
) |
|
|
1,011 |
|
|
|
|
|
Depreciation and amortization |
|
|
153 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
161 |
|
|
|
|
|
General and administrative |
|
|
18 |
|
|
|
(7 |
) |
|
|
72 |
|
|
|
|
|
|
|
83 |
|
|
|
|
|
Development costs |
|
|
(5 |
) |
|
|
1 |
|
|
|
8 |
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,112 |
|
|
|
67 |
|
|
|
81 |
|
|
|
(1 |
) |
|
|
1,259 |
|
|
|
|
|
|
Operating Income/(Loss) |
|
|
110 |
|
|
|
27 |
|
|
|
(81 |
) |
|
|
1 |
|
|
|
57 |
|
|
|
|
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings/(losses) of consolidated
subsidiaries |
|
|
138 |
|
|
|
(32 |
) |
|
|
303 |
|
|
|
(409 |
) |
|
|
|
|
|
|
|
|
Equity in losses of unconsolidated affiliates |
|
|
(1 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
|
(19 |
) |
|
|
|
|
Other income, net |
|
|
14 |
|
|
|
(4 |
) |
|
|
3 |
|
|
|
(1 |
) |
|
|
12 |
|
|
|
|
|
Interest expense |
|
|
(51 |
) |
|
|
(18 |
) |
|
|
(75 |
) |
|
|
|
|
|
|
(144 |
) |
|
|
|
|
|
Total other income/(expense) |
|
|
100 |
|
|
|
(72 |
) |
|
|
231 |
|
|
|
(410 |
) |
|
|
(151 |
) |
|
|
|
|
|
Income/(Loss) From Continuing Operations Before
Income Taxes |
|
|
210 |
|
|
|
(45 |
) |
|
|
150 |
|
|
|
(409 |
) |
|
|
(94 |
) |
|
|
|
|
Income tax (benefit)/expense |
|
|
46 |
|
|
|
(25 |
) |
|
|
(74 |
) |
|
|
|
|
|
|
(53 |
) |
|
|
|
|
|
Income/(Loss) From Continuing Operations |
|
|
164 |
|
|
|
(20 |
) |
|
|
224 |
|
|
|
(409 |
) |
|
|
(41 |
) |
|
|
|
|
Income from discontinued operations, net of
income taxes |
|
|
|
|
|
|
265 |
|
|
|
(97 |
) |
|
|
|
|
|
|
168 |
|
|
|
|
|
|
Net Income/(Loss) attributable to
NRG Energy,
Inc. |
|
$ |
164 |
|
|
$ |
245 |
|
|
$ |
127 |
|
|
$ |
(409 |
) |
|
$ |
127 |
|
|
|
|
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
54
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Non-Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
2,423 |
|
|
$ |
195 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,618 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
1,681 |
|
|
|
132 |
|
|
|
3 |
|
|
|
(1 |
) |
|
|
1,815 |
|
Depreciation and amortization |
|
|
306 |
|
|
|
14 |
|
|
|
2 |
|
|
|
|
|
|
|
322 |
|
General and administrative |
|
|
31 |
|
|
|
(4 |
) |
|
|
131 |
|
|
|
|
|
|
|
158 |
|
Development costs |
|
|
(5 |
) |
|
|
3 |
|
|
|
18 |
|
|
|
|
|
|
|
16 |
|
|
Total operating costs and expenses |
|
|
2,013 |
|
|
|
145 |
|
|
|
154 |
|
|
|
(1 |
) |
|
|
2,311 |
|
|
Operating Income/(Loss) |
|
|
410 |
|
|
|
50 |
|
|
|
(154 |
) |
|
|
1 |
|
|
|
307 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings/(losses) of consolidated
subsidiaries |
|
|
210 |
|
|
|
(50 |
) |
|
|
445 |
|
|
|
(605 |
) |
|
|
|
|
Equity in losses of unconsolidated affiliates |
|
|
(3 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
(23 |
) |
Other income, net |
|
|
15 |
|
|
|
(1 |
) |
|
|
8 |
|
|
|
(1 |
) |
|
|
21 |
|
Interest expense |
|
|
(102 |
) |
|
|
(39 |
) |
|
|
(159 |
) |
|
|
|
|
|
|
(300 |
) |
|
Total other income/(expense) |
|
|
120 |
|
|
|
(110 |
) |
|
|
294 |
|
|
|
(606 |
) |
|
|
(302 |
) |
|
Income/(Loss) From Continuing Operations Before
Income Taxes |
|
|
530 |
|
|
|
(60 |
) |
|
|
140 |
|
|
|
(605 |
) |
|
|
5 |
|
Income tax expense/(benefit) |
|
|
167 |
|
|
|
(33 |
) |
|
|
(133 |
) |
|
|
|
|
|
|
1 |
|
|
Income/(Loss) From Continuing Operations |
|
|
363 |
|
|
|
(27 |
) |
|
|
273 |
|
|
|
(605 |
) |
|
|
4 |
|
Income from discontinued operations, net of
income taxes |
|
|
|
|
|
|
269 |
|
|
|
(97 |
) |
|
|
|
|
|
|
172 |
|
|
Net Income/(Loss) attributable to NRG
Energy,
Inc. |
|
$ |
363 |
|
|
$ |
242 |
|
|
$ |
176 |
|
|
$ |
(605 |
) |
|
$ |
176 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
55
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
Guarantor |
|
NRG Energy, |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
Inc. |
|
Eliminations (a) |
|
Balance |
|
ASSETS |
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
(2 |
) |
|
$ |
159 |
|
|
$ |
1,337 |
|
|
$ |
|
|
|
$ |
1,494 |
|
Funds deposited by counterparties |
|
|
|
|
|
|
|
|
|
|
754 |
|
|
|
|
|
|
|
754 |
|
Restricted cash |
|
|
7 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
Accounts receivable, net |
|
|
422 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
464 |
|
Inventory |
|
|
443 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
455 |
|
Derivative instruments valuation |
|
|
4,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,600 |
|
Cash collateral paid in support of energy
risk management activities |
|
|
494 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
494 |
|
Prepayments and other current assets |
|
|
130 |
|
|
|
37 |
|
|
|
278 |
|
|
|
(230 |
) |
|
|
215 |
|
|
Total current assets |
|
|
6,094 |
|
|
|
259 |
|
|
|
2,369 |
|
|
|
(230 |
) |
|
|
8,492 |
|
|
Net Property, Plant and Equipment |
|
|
10,725 |
|
|
|
791 |
|
|
|
29 |
|
|
|
|
|
|
|
11,545 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
651 |
|
|
|
|
|
|
|
11,949 |
|
|
|
(12,600 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
26 |
|
|
|
464 |
|
|
|
|
|
|
|
|
|
|
|
490 |
|
Capital leases and note receivable, less
current portion |
|
|
598 |
|
|
|
435 |
|
|
|
3,177 |
|
|
|
(3,775 |
) |
|
|
435 |
|
Goodwill |
|
|
1,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,718 |
|
Intangible assets, net |
|
|
797 |
|
|
|
16 |
|
|
|
2 |
|
|
|
|
|
|
|
815 |
|
Nuclear decommissioning trust fund |
|
|
303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
303 |
|
Derivative instruments valuation |
|
|
870 |
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
885 |
|
Other non-current assets |
|
|
9 |
|
|
|
4 |
|
|
|
112 |
|
|
|
|
|
|
|
125 |
|
|
Total other assets |
|
|
4,972 |
|
|
|
919 |
|
|
|
15,255 |
|
|
|
(16,375 |
) |
|
|
4,771 |
|
|
Total Assets |
|
$ |
21,791 |
|
|
$ |
1,969 |
|
|
$ |
17,653 |
|
|
$ |
(16,605 |
) |
|
$ |
24,808 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital
leases |
|
$ |
67 |
|
|
$ |
235 |
|
|
$ |
229 |
|
|
$ |
(67 |
) |
|
$ |
464 |
|
Accounts payable |
|
|
(1,302 |
) |
|
|
429 |
|
|
|
1,324 |
|
|
|
|
|
|
|
451 |
|
Derivative instruments valuation |
|
|
3,976 |
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
3,981 |
|
Deferred income taxes |
|
|
503 |
|
|
|
31 |
|
|
|
(333 |
) |
|
|
|
|
|
|
201 |
|
Cash collateral received in support of energy
risk management activities |
|
|
760 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
760 |
|
Accrued expenses and other current liabilities |
|
|
507 |
|
|
|
48 |
|
|
|
333 |
|
|
|
(164 |
) |
|
|
724 |
|
|
Total current liabilities |
|
|
4,511 |
|
|
|
746 |
|
|
|
1,555 |
|
|
|
(231 |
) |
|
|
6,581 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
2,730 |
|
|
|
1,014 |
|
|
|
7,729 |
|
|
|
(3,776 |
) |
|
|
7,697 |
|
Nuclear decommissioning reserve |
|
|
284 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
284 |
|
Nuclear decommissioning trust liability |
|
|
218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
218 |
|
Deferred income taxes |
|
|
705 |
|
|
|
(187 |
) |
|
|
672 |
|
|
|
|
|
|
|
1,190 |
|
Derivative instruments valuation |
|
|
348 |
|
|
|
46 |
|
|
|
114 |
|
|
|
|
|
|
|
508 |
|
Out-of-market contracts |
|
|
291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
291 |
|
Other non-current liabilities |
|
|
405 |
|
|
|
44 |
|
|
|
220 |
|
|
|
|
|
|
|
669 |
|
|
Total non-current liabilities |
|
|
4,981 |
|
|
|
917 |
|
|
|
8,735 |
|
|
|
(3,776 |
) |
|
|
10,857 |
|
|
Total liabilities |
|
|
9,492 |
|
|
|
1,663 |
|
|
|
10,290 |
|
|
|
(4,007 |
) |
|
|
17,438 |
|
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
12,299 |
|
|
|
306 |
|
|
|
7,116 |
|
|
|
(12,598 |
) |
|
|
7,123 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
21,791 |
|
|
$ |
1,969 |
|
|
$ |
17,653 |
|
|
$ |
(16,605 |
) |
|
$ |
24,808 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
56
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
NRG Energy, |
|
|
|
|
|
|
|
|
Guarantor |
|
Guarantor |
|
Inc. |
|
|
|
|
|
Consolidated |
(In millions) |
|
Subsidiaries |
|
Subsidiaries |
|
(Note Issuer) |
|
Eliminations(a) |
|
Balance |
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
363 |
|
|
$ |
242 |
|
|
$ |
176 |
|
|
$ |
(605 |
) |
|
$ |
176 |
|
Adjustments to reconcile net income to net cash provided by
operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity (earnings)/losses of
unconsolidated affiliates and consolidated subsidiaries |
|
|
(207 |
) |
|
|
79 |
|
|
|
(445 |
) |
|
|
605 |
|
|
|
32 |
|
Depreciation and amortization |
|
|
306 |
|
|
|
14 |
|
|
|
2 |
|
|
|
|
|
|
|
322 |
|
Amortization of nuclear fuel |
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30 |
|
Amortization of financing costs and debt
discount/premiums |
|
|
|
|
|
|
8 |
|
|
|
11 |
|
|
|
|
|
|
|
19 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(147 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(147 |
) |
Changes in deferred income taxes and liability for
unrecognized tax benefits |
|
|
(159 |
) |
|
|
(52 |
) |
|
|
307 |
|
|
|
|
|
|
|
96 |
|
Changes in nuclear decommissioning liability |
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Changes in derivatives |
|
|
664 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
669 |
|
Changes in collateral deposits supporting energy risk
management activities |
|
|
(328 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(328 |
) |
Loss on disposal and sale of assets |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Gain on sale of discontinued operations |
|
|
|
|
|
|
(270 |
) |
|
|
|
|
|
|
|
|
|
|
(270 |
) |
Gain on sale of emission allowances |
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42 |
) |
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
14 |
|
Changes in option premium collected |
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99 |
|
Cash provided by/(used by) changes in other working
capital, net of dispositions affects |
|
|
185 |
|
|
|
96 |
|
|
|
(534 |
) |
|
|
|
|
|
|
(253 |
) |
|
Net Cash Provided by/Used by Operating Activities |
|
|
783 |
|
|
|
122 |
|
|
|
(469 |
) |
|
|
|
|
|
|
436 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries |
|
|
(81 |
) |
|
|
|
|
|
|
444 |
|
|
|
(363 |
) |
|
|
|
|
Capital expenditures |
|
|
(201 |
) |
|
|
(204 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
(409 |
) |
Increase in restricted cash |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
Decrease in notes receivable |
|
|
|
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
Purchases of emission allowances |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
Proceeds from sale of emission allowances |
|
|
61 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61 |
|
Investment in nuclear decommissioning trust fund securities |
|
|
(285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(285 |
) |
Proceeds from sales of nuclear decommissioning trust fund
securities |
|
|
269 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
269 |
|
Proceeds from sale of discontinued operations and assets,
net of cash divested |
|
|
|
|
|
|
(59 |
) |
|
|
288 |
|
|
|
|
|
|
|
229 |
|
Proceeds from sale of assets |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14 |
|
Equity investment in unconsolidated affiliate |
|
|
|
|
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
(17 |
) |
|
Net Cash Provided/Used by Investing Activities |
|
|
(227 |
) |
|
|
(243 |
) |
|
|
711 |
|
|
|
(363 |
) |
|
|
(122 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds for intercompany loans |
|
|
(523 |
) |
|
|
79 |
|
|
|
81 |
|
|
|
363 |
|
|
|
|
|
Receipt/(Payment) from intercompany dividend |
|
|
|
|
|
|
17 |
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
Payments for dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(28 |
) |
|
|
|
|
|
|
(28 |
) |
Payment of financing element of acquired derivatives |
|
|
(28 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(28 |
) |
Payments for treasury stock |
|
|
|
|
|
|
|
|
|
|
(55 |
) |
|
|
|
|
|
|
(55 |
) |
Proceeds from issuance of common stock, net of issuance
costs |
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
8 |
|
Proceeds from sale of noncontrolling interest on subsidiary |
|
|
|
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
50 |
|
Proceeds from issuance of long term debt |
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
10 |
|
Payments for deferred debt issuance costs |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
(2 |
) |
Payments for short and long-term debt |
|
|
|
|
|
|
(30 |
) |
|
|
(158 |
) |
|
|
|
|
|
|
(188 |
) |
|
Net Cash Provided by/Used by Financing Activities |
|
|
(551 |
) |
|
|
126 |
|
|
|
(171 |
) |
|
|
363 |
|
|
|
(233 |
) |
Change in cash from discontinued operations |
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
43 |
|
Effect of exchange rate changes on cash and cash equivalents |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
Net
Increase in Cash and Cash Equivalents |
|
|
5 |
|
|
|
55 |
|
|
|
71 |
|
|
|
|
|
|
|
131 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
(4 |
) |
|
|
124 |
|
|
|
1,012 |
|
|
|
|
|
|
|
1,132 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
1 |
|
|
$ |
179 |
|
|
$ |
1,083 |
|
|
$ |
|
|
|
$ |
1,263 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
57
|
|
|
ITEM 2 |
|
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS |
In this discussion and analysis, NRG discusses and explains its financial condition and
results of operations, including:
|
|
|
Factors which affect the Companys business; |
|
|
|
|
NRGs earnings and costs in the periods presented; |
|
|
|
|
Changes in earnings and costs between periods; |
|
|
|
|
Impact of these factors on NRGs overall financial condition; |
|
|
|
|
A discussion of new and ongoing initiatives that may affect NRGs future results of
operations and financial condition; |
|
|
|
|
Expected future expenditures for capital projects; and |
|
|
|
|
Expected sources of cash for future operations and capital expenditures. |
As you read this discussion and analysis, refer to the Companys Condensed Consolidated
Statements of Operations, which present the results of operations for the three and six months
ended June 30, 2009 and 2008. NRG analyzes and explains the differences between periods in the
specific line items of NRGs Condensed Consolidated Statements of Operations. Also refer to NRGs
2008 Annual Report on Form 10-K, 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, including the Reliant Energy acquisition and the disposition of the MIBRAG
investment. |
58
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 franchise in the ERCOT (Texas) market. 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 supply of electricity and energy
services to retail electricity customers in the Texas market.
As of June 30, 2009, NRG had a total global generation portfolio of 187 active operating
fossil fuel and nuclear generation units, at 47 power generation plants, with an aggregate
generation capacity of approximately 24,085 MW, and approximately 350 MW under construction which
includes partners interests of 100 MW. In addition to its fossil fuel plant ownership, NRG has
ownership interests in two wind farms representing an aggregate generation capacity of 270 MW,
which includes partner interests of 75 MW. Within the U.S., NRG has one of the largest and most
diversified power generation portfolios in terms of geography, fuel-type and dispatch levels, with
approximately 23,080 MW of fossil fuel and nuclear generation capacity in 179 active generating
units at 43 plants. In addition, NRG has ownership interests in two wind farms representing 195 MW
of wind generation capacity. The Companys power generation facilities are most heavily
concentrated in Texas (approximately 11,175 MW, including the 195 MW from the two wind farms), the
Northeast (approximately 7,015 MW), South Central (approximately 2,840 MW), and West (approximately
2,130 MW) regions of the U.S., and approximately 115 MW of additional generation capacity from the
Companys thermal assets.
NRGs principal domestic power plants consist of a mix of natural gas-, coal-, oil-fired,
nuclear and wind facilities, representing approximately 46%, 32%, 16%, 5% and 1% of the Companys
total domestic generation capacity, respectively. In addition, 11% of NRGs domestic generating
facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest
cost fuel option.
NRGs domestic generation facilities consist of intermittent, baseload, intermediate and
peaking power generation facilities, the ranking of which is referred to as Merit Order, and
include thermal energy production plants. The sale of capacity and power from baseload generation
facilities accounts for the majority of the Companys revenues and provides a stable source of cash
flow. In addition, NRGs generation portfolio provides the Company with opportunities to capture
additional revenues by selling power during periods of peak demand, offering capacity or similar
products to retail electric providers and others, and providing ancillary services to support
system reliability.
On May 1, 2009, NRG acquired Reliant Energy, which is the second largest mass market
electricity provider to residential and commercial customers in Texas. Based on metered locations,
as of June 30, 2009, Reliant Energy had approximately
1.6 million mass customers and 0.1 million C&I
customers. Reliant Energy 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.
NRGs Business Strategy
NRGs business strategy is intended to maximize shareholder value over time through the
production and the sale of safe, reliable and affordable power to its customers and in the markets
served by the Company. The key to successful implementation of this strategy is the Companys
sizable fleet of wholesale power generation assets in the U.S., its leading retail franchise in
Texas and, increasingly, its position as an industry leader in the development of various types of
low and no carbon generation technology. NRG utilizes its asset base as a platform for growth and
development and as a source of cash flow generation which can be used for the return of capital to
debt and equity holders. More specifically, the Companys strategy is focused on: (i) top decile
operating performance of its existing operating assets and enhanced operating performance of the
Companys commercial operations and hedging program; (ii) repowering of power generation assets at
existing sites and development of new power generation projects; (iii) empowering retail customers
with distinctive products and services that transform how they use, manage, and value energy; (iv)
investment in energy-related new businesses and new technologies being developed and deployed in
response to the twin societal dynamics to foster sustainability and combat climate change, 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. This strategy is
supported by the Companys five major initiatives (FORNRG, RepoweringNRG, econrg, Future NRG and
NRG Global Giving) which are designed to enhance the Companys competitive advantages in these
strategic areas and enable the Company to convert the challenges faced by the power industry in the
coming years into opportunities for financial growth. This strategy is being implemented by
focusing on the following principles, which are more fully described in the Companys 2008 Annual
Report on Form 10-K:
59
Operational Performance The Company is focused on increasing value from its existing
assets, primarily through the Companys FORNRG initiative, commercial operations strategy,
efficiency between the retail and wholesale business, and maintenance of appropriate levels of
liquidity, debt and equity in order to ensure continued access to capital.
Development NRG is favorably positioned to pursue growth opportunities through expansion of
its existing generating capacity and development of new generating capacity at its existing
facilities, primarily through the Companys RepoweringNRG initiative. NRG expects that these
efforts will provide some or all of the following benefits: improved heat rates; lower delivered
costs; expanded electricity production capability; improved ability to dispatch economically across
the regional general portfolio; increased technological and fuel diversity; and reduce
environmental impacts, including facilities that either have near zero GHG emissions or can be
equipped to capture and sequester GHG emissions. Several of the Companys original RepoweringNRG
projects or projects commenced under that initiative since its inception may qualify for financial
support under the infrastructure financing component of the American Recovery and Reinvestment Act.
New Businesses and New Technology NRG is focused on the development and investment in
energy-related new businesses and new technologies where the benefits of such investments represent
significant commercial opportunities and create a comparative advantage for the Company, including
low or no GHG emitting energy generating sources, such as nuclear, wind, solar thermal,
photovoltaic, clean coal and gasification, and the retrofit of post-combustion carbon capture
technologies. A primary focus of this strategy is supported by the econrg initiative whereby NRG
is pursuing investments in new generating facilities and technologies that are expected to be
highly efficient and will employ no and low carbon technologies to limit CO2 emissions
and other air emissions. While the Companys effort in this regard to date has focused on
businesses and technologies applicable to the centralized power station, the acquisition of Reliant
Energy has put the Company in a position to consider and pursue smart meters and distributed
clean solutions.
Company-Wide Initiatives In addition, the Companys overall strategy is also supported by
Future NRG and NRG Global Giving initiatives, which address workforce planning and community
involvement and support, respectively.
Finally, NRG will continue to pursue selective acquisitions, joint ventures and divestitures
to enhance its asset mix and competitive position in the Companys core markets. NRG intends to
concentrate on opportunities that present attractive risk-adjusted returns. NRG will also
opportunistically pursue other strategic transactions, including mergers, acquisitions or
divestitures.
Business Environment Financial Credit Market Availability
Power generation companies are capital intensive and, as such, rely on the credit markets for
liquidity and for the financing of power generation investments. At the end of the second quarter
2009, there were some indications that the nations credit markets began to recover although credit
continued to be tight relative to previous years. As evidence of the markets improvement, in
April 2009, GenConn Energy, a joint venture of NRG and the United Illuminating Company, closed on a
$534 million project financing and NRG was able to issue $700 million of bonds in June 2009 with a
10 year maturity at a yield to maturity of 8.75%. NRG has a diversified liquidity program, with
$4.0 billion in total liquidity, excluding funds deposited by counterparties, and a first and
second lien structure that enables significant strategic hedging while reducing requirements for
the posting of cash or letters of credit as collateral. NRG expects to continue to manage
commodity price volatility through its strategic hedging program, under which the Company expects
to hedge revenues and fuel costs. This program should provide the Company with the flexibility to
enter into hedges opportunistically, such as when gas prices are increasing, while at the same time
protecting NRG against longer-term volatility in the commodity markets. NRG transacts with a
diversified pool of counterparties and actively manages the Companys exposure to any single
counterparty. See Part I, Item 2 Liquidity and Capital Resources, and Part I, Item 3
Quantitative and Qualitative Disclosures about Market Risk for further discussion.
The addition of Reliant Energy to NRGs existing generation portfolio may provide
opportunities to match generation to load directly which should reduce hedging and credit costs
that both businesses would incur if hedged separately. Reliant Energy, which expects to lock in
supply and thereby its margin as load is contracted, should also benefit from having better access
to nonstandard products necessary to meet load. NRG expects to continue hedging the generation
consistent with its prior practice, but now will benefit from having an additional outlet for its
range of generation products.
60
Unsolicited Exelon Proposal
On October 19, 2008, the Company received an unsolicited proposal from Exelon Corporation to
acquire all of the outstanding shares of the Company and on November 12, 2008, Exelon announced a
tender offer for all of the Companys outstanding common stock. NRGs Board of Directors, after
carefully reviewing the proposal, unanimously concluded that the proposal was not in the best
interests of the stockholders and recommended that NRG stockholders not tender their shares. In
addition, on June 17, 2009 Exelon filed a Definitive Proxy Statement with the SEC with respect to
their proposals for the Companys 2009, Annual Meeting of Stockholders, which consisted of: (i)
consideration of Exelons four nominees as Class III directors; (ii) consideration of the expansion
of NRGs Board of Directors to 19 directors; (iii) if the Exelon board expansion is approved,
consideration of five additional Exelon nominees; and (iv) consideration of repealing any
amendments to the NRG Bylaws after February 26, 2008. NRGs Board of Directors recommended a vote
against each of the proposals. On July 2, 2009, Exelon revised their unsolicited proposal and
NRGs Board of Directors, after carefully reviewing the proposal, unanimously concluded that the
proposal was not in the best interests of the stockholders and recommended that NRG stockholders
not tender their shares. On July 21, 2009, based on the preliminary vote count at NRGs 2009
Annual Meeting of Stockholders, stockholders voted to re-elect all of the Companys director
nominees to the NRG Board of Directors. In addition, NRGs stockholders rejected Exelons proposal
to expand NRGs Board with its own slate of five Director nominees. On July 21, 2009, Exelon
Corporation announced that in light of the vote results, effective immediately, it terminated its
offer to acquire all of the outstanding shares of NRG. On July
29, 2009, IVS Associates, Inc., the independent inspector of
elections, certified the final results. The total defense costs associated with
Exelons unsolicited proposal was approximately $17 million as of June 30, 2009 of which $9 million
was for the six months ended June 30, 2009. In the third quarter 2009, the Company expects to
incur an additional $19 million of expenditures related to the Exelon defense.
Environmental Matters
Climate Change
On June 26, 2009, the House of Representatives passed The American Clean Energy and Security
Act of 2009. This comprehensive bill proposes a multi-sector, market based greenhouse gas cap and
trade system starting in 2012 as well as national Renewable Energy Standards, expedited
transmission planning and approval and aggressive efficiency measures. The bill provides for a
declining cap in U.S. GHG emissions and provides for allocation of allowances to merchant coal
generators and local distribution companies, the use of both international and domestic offsets,
and a transition from already existing state programs, all of which are important to the electric
generation industry. The bill further exempts CO2 from regulation under New Source
Review, or NSR, as a criteria pollutant, or a hazardous air pollutant under the CAA. It proposes
requirements for new coal-fueled power plants to implement, based on commercial availability,
carbon capture and sequestration to reduce CO2 emissions. The debate will now move to
the Senate. NRG will continue to provide input as a leading energy company and member of the U.S.
Climate Action Partnership, or USCAP, in support of federal legislation.
In 2008, NRG emitted in the U.S. 60 million metric tonnes of CO2. If the
Waxman-Markey legislation or some other federal comprehensive climate change bill were to pass both
Houses of Congress and be enacted into law, the actual impact on the Companys financial
performance would depend on a number of factors, including the overall level of GHG reductions
required under any final legislation, the degree to which offsets may be used for compliance and
their price and availability, and the extent to which NRG would be entitled to receive
CO2 emissions allowances without having to purchase them in an auction or on the open
market. Thereafter, the impact would depend on the level of success of the Companys multifold
strategy, which includes (i) shaping public policy with the objective being constructive and
effective federal GHG regulatory policy; and (ii) pursuing its RepoweringNRG and econrg programs.
The Companys multifold strategy is discussed in greater detail in Part I, Item 1 Business,
Carbon Update in NRGs 2008 Annual Report on Form 10-K.
On April 24, 2009, the U.S. EPA published a proposed endangerment finding that the mix of six
key GHGs, including CO2, threaten the public health and welfare. The proposed
endangerment finding does not include any proposed regulations. This is in response to the Supreme
Courts decision in Massachusetts v. U.S. EPA, which requires the U.S. EPA to decide under the
CAAs mobile source title whether GHGs contribute to climate change, and if so, promulgate
appropriate regulations. Absent eventual action from Congress on climate change, this finding
could ultimately serve as a basis for rulemaking for stationary sources, like power plants, under
the existing CAA.
61
Federal Environmental Initiatives
A number of regulations are under review by U.S. EPA including CAIR, MACT, National Ambient
Air Quality Standards, or NAAQS, for ozone, small particle matter, or PM2.5, and the Phase II
316(b) Rule. These rules address air emissions and best practices for units with
once-through-cooling. In addition, the U.S. EPA has announced that it is considering new rules
regarding the handling and disposition of coal combustion byproducts. While the Company cannot
predict the requirements in the final versions nor the ultimate effect that the changing
regulations will have on NRGs business, NRG has prepared an environmental capital expenditure plan
in anticipation of such requirements.
The U.S. Supreme Court released its decision in the Phase II 316(b) Rule case on April 1,
2009, that the U.S. EPA does have the authority to allow a cost-benefit analysis in the evaluation
of Best Technology Available, or BTA. This ruling is favorable for the industry and NRG as it
improves the U.S. EPAs ability to include alternatives to closed-loop cooling in its redraft of
the Phase II 316(b) Rules.
On April 24, 2009, the U.S. EPA granted petitions to reconsider three NSR rules; Fugitive
Emissions, PM2.5 Implementation, and Reasonable Possibility. A Notice for reconsideration of the
PM2.5 implementation Rule was published in Federal Register on May 1, 2009. While none of these
actions directly impact NRG at this point, it is unknown if final rules will impact future
projects.
Regional Environmental Initiatives
Northeast Region NRG operates electric generating units located in Connecticut, Delaware,
Maryland, Massachusetts and New York which are subject to RGGI. The RGGI CO2
cap-and-trade program went into effect on January 1, 2009. An allowance must be surrendered for
every U.S. ton of CO2 emitted with true up for 2009-2011 occurring in 2012. NRGs
emissions under RGGI were approximately 12 million tonnes in 2008.
Regulatory Matters
As an operator of power plants and a participant in the wholesale markets, NRG is subject to
regulation by various federal and state government agencies. In addition, NRG is subject to the
market rules, procedures, and protocols of the various ISO markets in which NRG participates. NRG
is also subject to regulatory requirements as a competitive retail electric service provider in
Texas. The power markets are subject to ongoing legislative and regulatory changes. In some of
NRGs regions, interested parties have advocated for material market design changes, including the
elimination of a single clearing price mechanism, as well as proposals to re-regulate the markets
or require divestiture by generating companies in order to reduce their market share. The Company
cannot predict the future design of the wholesale power markets or the ultimate effect that the
changing regulatory environment will have on NRGs business.
West Region
California The CAISO Market Redesign and Technology Update, or MRTU, commenced April 1,
2009. Significant components of the MRTU include: (i) locational marginal pricing of energy; (ii) a
more effective congestion management system; (iii) a day-ahead market; and (iv) an increase to the
existing bid caps. NRG considers these market reforms to generally be a positive development for
its assets in the region, but additional time is needed to assess the impact of MRTU.
62
Texas Region
On October 6, 2008, as part of its determination of Competitive Renewable Energy Zones, or
CREZ, the Public Utility Commission of Texas, or PUCT, issued its final order approving a
significant transmission expansion plan to provide for the delivery of approximately 18,500 MW of
energy from the western region of Texas, primarily wind generation. The transmission expansion
plan is composed of approximately 2,300 miles of new 345 kV lines and 42 miles of new 138 kV lines.
In January 2009, Texas Industrial Energy Consumers, a trade organization composed of large
industrial customers, appealed the PUCTs CREZ plan in state district court, seeking reversal of
the final order. On March 30, 2009, the PUCT issued a final order designating the transmission
utilities that plan to construct the various CREZ transmission component projects. A large number
of separate transmission licensing proceedings will be required prior to construction of the CREZ
facilities. In July of 2009, the PUCT approved schedules for utilities to file applications to
license several of the CREZ transmission projects (to obtain certificates of convenience and
necessity, or CCNs). If the CREZ projects are completed as currently anticipated, the transmission upgrades and
associated wind generation could impact wholesale energy and ancillary service prices in ERCOT. As
part of the normal ERCOT five-year planning process, transmission utilities are also planning other
system improvements, 2,800 circuit miles of transmission and more than 17,000 MVA of
autotransformer capacity, intended to support increasing power demand and to address transmission
congestion in the ERCOT Region.
Changes in Accounting Standards
See Note 1 to the condensed consolidated financial statements of this Form 10-Q as found in
Item 1 for a discussion of recent accounting developments.
63
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) |
|
2009 |
|
|
2008 |
|
|
Change % |
|
2009 |
|
|
2008 |
|
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
725 |
|
|
$ |
1,373 |
|
|
|
(47 |
)% |
|
$ |
1,612 |
|
|
$ |
2,298 |
|
|
|
(30 |
)% |
Capacity revenue |
|
|
253 |
|
|
|
334 |
|
|
|
(24 |
) |
|
|
513 |
|
|
|
681 |
|
|
|
(25 |
) |
Retail revenue |
|
|
1,250 |
|
|
|
|
|
|
|
N/A |
|
|
|
1,250 |
|
|
|
|
|
|
|
N/A |
|
Risk management activities |
|
|
(12 |
) |
|
|
(588 |
) |
|
|
(98 |
) |
|
|
425 |
|
|
|
(717 |
) |
|
|
(159 |
) |
Contract amortization |
|
|
(53 |
) |
|
|
88 |
|
|
|
(160 |
) |
|
|
(32 |
) |
|
|
157 |
|
|
|
(120 |
) |
Thermal revenue |
|
|
21 |
|
|
|
23 |
|
|
|
(9 |
) |
|
|
55 |
|
|
|
59 |
|
|
|
(7 |
) |
Other revenues |
|
|
53 |
|
|
|
86 |
|
|
|
(38 |
) |
|
|
72 |
|
|
|
140 |
|
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
2,237 |
|
|
|
1,316 |
|
|
|
70 |
|
|
|
3,895 |
|
|
|
2,618 |
|
|
|
49 |
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales (including risk management activities
of
$204 and $136 for the three and six months
ended June
30, 2009, respectively) |
|
|
971 |
|
|
|
783 |
|
|
|
24 |
|
|
|
1,492 |
|
|
|
1,353 |
|
|
|
10 |
|
Other cost of operations |
|
|
271 |
|
|
|
228 |
|
|
|
19 |
|
|
|
516 |
|
|
|
462 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations |
|
|
1,242 |
|
|
|
1,011 |
|
|
|
23 |
|
|
|
2,008 |
|
|
|
1,815 |
|
|
|
11 |
|
Depreciation and amortization |
|
|
213 |
|
|
|
161 |
|
|
|
32 |
|
|
|
382 |
|
|
|
322 |
|
|
|
19 |
|
Selling, general and administrative |
|
|
131 |
|
|
|
83 |
|
|
|
58 |
|
|
|
214 |
|
|
|
158 |
|
|
|
35 |
|
Acquisition-related transaction and integration costs |
|
|
23 |
|
|
|
|
|
|
|
N/A |
|
|
|
35 |
|
|
|
|
|
|
|
N/A |
|
Development costs |
|
|
9 |
|
|
|
4 |
|
|
|
125 |
|
|
|
22 |
|
|
|
16 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,618 |
|
|
|
1,259 |
|
|
|
29 |
|
|
|
2,661 |
|
|
|
2,311 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
619 |
|
|
|
57 |
|
|
|
N/A |
|
|
|
1,234 |
|
|
|
307 |
|
|
|
302 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in
earnings/(losses) of unconsolidated affiliates |
|
|
5 |
|
|
|
(19 |
) |
|
|
126 |
|
|
|
27 |
|
|
|
(23 |
) |
|
|
217 |
|
Gain on sale of equity method investments |
|
|
128 |
|
|
|
|
|
|
|
N/A |
|
|
|
128 |
|
|
|
|
|
|
|
N/A |
|
Other income, net |
|
|
(11 |
) |
|
|
12 |
|
|
|
(192 |
) |
|
|
(14 |
) |
|
|
21 |
|
|
|
(167 |
) |
Interest expense |
|
|
(159 |
) |
|
|
(144 |
) |
|
|
10 |
|
|
|
(297 |
) |
|
|
(300 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total other expense |
|
|
(37 |
) |
|
|
(151 |
) |
|
|
(75 |
) |
|
|
(156 |
) |
|
|
(302 |
) |
|
|
(48 |
) |
|
|
|
|
|
|
|
|
|
|
|
Income/(Losses)
from Continuing Operations before
income tax
expense |
|
|
582 |
|
|
|
(94 |
) |
|
|
N/A |
|
|
|
1,078 |
|
|
|
5 |
|
|
|
N/A |
|
Income tax expense/(benefit) |
|
|
150 |
|
|
|
(53 |
) |
|
|
383 |
|
|
|
448 |
|
|
|
1 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Losses) from Continuing Operations |
|
|
432 |
|
|
|
(41 |
) |
|
|
N/A |
|
|
|
630 |
|
|
|
4 |
|
|
|
N/A |
|
Income from
discontinued operations, net of income
taxes |
|
|
|
|
|
|
168 |
|
|
|
N/A |
|
|
|
|
|
|
|
172 |
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income |
|
|
432 |
|
|
|
127 |
|
|
|
240 |
|
|
|
630 |
|
|
|
176 |
|
|
|
258 |
|
|
|
|
|
|
|
|
|
|
|
|
Less: Net loss attributable to noncontrolling interest |
|
|
(1 |
) |
|
|
|
|
|
|
N/A |
|
|
|
(1 |
) |
|
|
|
|
|
|
N/A |
|
|
|
|
|
|
|
|
|
|
|
|
Net
income attributable to NRG Energy, Inc. |
|
$ |
433 |
|
|
$ |
127 |
|
|
|
241 |
|
|
$ |
631 |
|
|
$ |
176 |
|
|
|
259 |
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMBtu) |
|
|
3.68 |
|
|
|
11.32 |
|
|
|
(67 |
)% |
|
|
4.13 |
|
|
|
9.95 |
|
|
|
(58 |
)% |
|
N/A Not Applicable
64
Managements discussion of the results of operations for the three months ended June 30, 2009
and 2008:
For the benefit of the following discussions, the table below represents the results of NRG
excluding the impact of Reliant Energy during the two months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total excluding |
|
|
|
|
|
|
|
(In millions) |
|
Consolidated |
|
|
Reliant Energy |
|
|
Reliant Energy |
|
|
Consolidated |
|
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
725 |
|
|
$ |
|
|
|
$ |
725 |
|
|
$ |
1,373 |
|
|
|
(47 |
)% |
Capacity revenue |
|
|
253 |
|
|
|
|
|
|
|
253 |
|
|
|
334 |
|
|
|
(24 |
) |
Retail revenue |
|
|
1,250 |
|
|
|
1,250 |
|
|
|
|
|
|
|
|
|
|
|
N/A |
|
Risk management activities |
|
|
(12 |
) |
|
|
|
|
|
|
(12 |
) |
|
|
(588 |
) |
|
|
(98 |
) |
Contract amortization |
|
|
(53 |
) |
|
|
(75 |
) |
|
|
22 |
|
|
|
88 |
|
|
|
(75 |
) |
Thermal revenue |
|
|
21 |
|
|
|
|
|
|
|
21 |
|
|
|
23 |
|
|
|
(9 |
) |
Other revenues |
|
|
53 |
|
|
|
|
|
|
|
53 |
|
|
|
86 |
|
|
|
(38 |
) |
|
|
|
|
|
Total operating revenues |
|
|
2,237 |
|
|
|
1,175 |
|
|
|
1,062 |
|
|
|
1,316 |
|
|
|
(19 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales (including risk
management activities) |
|
|
971 |
|
|
|
614 |
|
|
|
357 |
|
|
|
783 |
|
|
|
(54 |
) |
Other operating costs |
|
|
271 |
|
|
|
41 |
|
|
|
230 |
|
|
|
228 |
|
|
|
1 |
|
|
|
|
|
|
Total cost of operations |
|
|
1,242 |
|
|
|
655 |
|
|
|
587 |
|
|
|
1,011 |
|
|
|
(42 |
) |
Depreciation and amortization |
|
|
213 |
|
|
|
43 |
|
|
|
170 |
|
|
|
161 |
|
|
|
6 |
|
Selling, general and administrative |
|
|
131 |
|
|
|
49 |
|
|
|
82 |
|
|
|
83 |
|
|
|
(1 |
) |
Acquisition-related transaction and
integration costs |
|
|
23 |
|
|
|
|
|
|
|
23 |
|
|
|
|
|
|
|
N/A |
|
Development costs |
|
|
9 |
|
|
|
|
|
|
|
9 |
|
|
|
4 |
|
|
|
125 |
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,618 |
|
|
|
747 |
|
|
|
871 |
|
|
|
1,259 |
|
|
|
(31 |
) |
|
|
|
|
|
Operating income |
|
|
619 |
|
|
|
428 |
|
|
|
191 |
|
|
|
57 |
|
|
|
235 |
% |
|
Operating Revenues
Operating revenues, excluding risk management activities, increased by $345 million during the
three months ended June 30, 2009, compared to the same period in 2008.
|
|
|
Energy revenue decreased $648 million during the three months ended June 30, 2009,
compared to the same period in 2008: |
|
o |
|
Texas energy revenue decreased by $325 million, with $283 million of the
decrease driven by lower energy prices and $42 million of the decrease driven by
reduction in generation. The average realized energy price decreased by 32%, driven by
a 63% decrease in merchant prices offset by a 25% increase in contract prices.
Generation decreased by 5% driven by a 9% decrease in coal plant generation and a 13%
decrease in gas plant generation, offset by a 17% increase in nuclear plant generation,
as well as generation from the recently constructed Elbow Creek wind farm, which was not
in operation in the second quarter 2008. Coal plant generation was adversely affected
by lower energy prices driven by a 68% decrease in average natural gas prices in
combination with depressed heat rates in the region. Increased wind generation shifted
the coal units position in the bid stack which also negatively affected coal plant
generation. The 2008 period contained a planned outage at the Companys nuclear plant
which did not occur in 2009 resulting in an increase in plant generation. |
65
|
o |
|
Northeast energy revenue decreased by $206 million, with $83 million driven by
lower energy prices and $147 million attributable to a reduction in generation offset by
a $24 million increase from higher net contract revenue. Merchant energy prices were
lower by an average of 56%. The lower energy prices reduced the Companys net cost
incurred to meet obligations under load serving contracts in the PJM market. Generation
decreased by 50% with a 51% decrease in coal generation and a 41% decrease in oil and
gas generation. Weakened demand for power combined with low gas prices resulted in
reduced merchant energy prices. Lower merchant energy prices combined with higher cost
of production from the introduction of RGGI resulted in increased hours where the units
were uneconomic to dispatch. The decline in oil and gas generation is attributable to
fewer reliability run hours at the Connecticut plants and a planned major maintenance
outage at the Arthur Kill plant. |
|
|
o |
|
South Central energy revenue decreased by $49 million due to a $27 million
decline in contract revenue coupled with a decrease of $22 million in merchant energy
revenues. The decline in contract energy price was driven by a $9 million decrease in
fuel cost pass through from the cooperatives and an $18 million decrease due to the
expiration of a contract with a regional utility. Total MWh sales to the regions
contract customers were down 12% while the average realized price on contract energy
sales was $22.98 per MWh in 2009 compared to $30.23 per MWh in 2008. The expiration of
the contract allowed more energy to be sold into the merchant market, but at lower
average prices resulting in a $22 million decline in revenue. Megawatt hours sold to
the merchant market increased by 43% as increased use of the regions tolled facility
provided additional energy to the merchant market while prices fell by 61%. |
|
|
o |
|
West decreased by $8 million due to a 33% decline in merchant energy prices and
a 31% decrease in generation. |
|
|
o |
|
Intercompany energy revenues intercompany sales of $54 million by NRGs Texas
region to Reliant Energy is eliminated in consolidation. |
|
|
|
Capacity revenue decreased $81 million during the three months ended June 30, 2009,
compared to the same period in 2008: |
|
o |
|
Texas capacity revenue decreased by $72 million due to a lower proportion of
baseload contracts which contained a capacity component. |
|
o |
|
South Central capacity revenue increased by $7 million primarily resulting from
a new capacity agreement. |
|
o |
|
Intercompany capacity revenue intercompany sales of $12 million by NRGs Texas
region to Reliant Energy is eliminated in consolidation. |
|
|
|
Retail revenue the acquisition of Reliant Energy contributed $1.3 billion of retail
revenue during the two months ended June 30, 2009. This includes mass revenues of
$761 million, C&I revenues of $437 million, and supply management revenues of $52 million. |
|
|
|
Contract amortization revenue decreased by $141 million in the three months ended June
30, 2009, as compared to the same period in 2008. The decrease includes $75 million in
amortization expense of intangible assets related to the Reliant Energy acquisition in 2009
and a reduction of $66 million in revenue from the Texas Genco acquisition due to the lower
volume of contracted energy. |
|
|
|
Other revenues decreased by $33 million driven by $24 million in lower ancillary
revenue and $26 million in lower emissions revenues. These decreases were offset by the
recognition of a $31 million non-cash gain related to the settlement of pre-existing
in-the-money contract with Reliant Energy. |
66
Cost of Operations
Cost of operations, excluding risk management activities, increased $435 million during the
three months ended June 30, 2009, compared to the same period in 2008.
|
|
|
Cost of energy increased $392 million during the three months ended June 30, 2009,
compared to the same period in 2008 due to: |
|
o |
|
Retail Reliant Energy incurred $803 million of cost of energy during the two
months ended June 30, 2009, which included $66 million of intercompany purchased energy
costs. |
|
o |
|
Texas cost of energy decreased $166 million due to lower natural gas and
ancillary services costs offset by an increase in coal costs. Natural gas costs
decreased $150 million, reflecting a 68% decline in average natural gas per MMBtu prices
and a 13% decrease in gas-fired generation. Coal costs increased $3 million due to $10
million in higher prices and $4 million from higher transportation costs offset by a $12
million decrease due to 5% lower generation. Ancillary service costs decreased by $12
million due to a decrease in purchased ancillary services costs incurred to meet
contract obligation. |
|
o |
|
Northeast cost of energy decreased $123 million due to a $78 million reduction
in natural gas and oil costs and a $48 million reduction in coal costs. Natural gas and
oil costs decreased due to 41% lower generation and 68% lower average natural gas
prices. Coal costs decreased due to 51% lower coal generation. These decreases were
offset by a $3 million increase in costs related to RGGI which became effective in 2009. |
|
o |
|
South Central
cost of energy decreased $32 million primarily due to a decrease
in purchased energy reflecting lower fuel costs associated with energy from the
regions tolled facility and lower costs related to market
purchases. |
|
o |
|
West cost of energy decreased $9 million due to a 67% decrease in average
natural gas per MMBtu prices and an 11% decrease in natural gas consumption. |
|
o |
|
Intercompany cost of energy intercompany purchases of $66 million by Reliant
Energy from NRGs Texas region is eliminated in consolidation. |
|
|
|
Other operating expenses increased $43 million during the three months ended June 30,
2009, compared to the same period in 2008. Reliant Energy incurred $41 million in other
operating costs during the two months ended June 30, 2009. Further, operating and
maintenance expense increased $5 million offset by a decrease in property taxes of $4
million. |
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
increased by $780 million during the three months ended June 30, 2009, compared to the same period
in 2008. The breakdown of changes by region follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2009 |
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Energy |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
West |
|
|
Thermal |
|
|
Elimination |
|
Total |
|
|
Net gains/(losses) on settled positions, or financial income |
|
$ |
(114 |
) |
|
$ |
101 |
|
|
$ |
95 |
|
|
$ |
(5 |
) |
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
77 |
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized (gains)/losses on
settled positions related to economic hedges |
|
|
210 |
|
|
|
(4 |
) |
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
192 |
|
Reversal of previously recognized unrealized (gains)/losses on
settled positions related to trading activity |
|
|
|
|
|
|
(14 |
) |
|
|
(9 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35 |
) |
Net unrealized gains/(losses) on open positions related to
economic hedges |
|
|
93 |
|
|
|
(116 |
) |
|
|
(17 |
) |
|
|
(9 |
) |
|
|
7 |
|
|
|
(1 |
) |
|
|
|
|
|
|
(43 |
) |
Net unrealized gains/(losses) on open positions related to
trading activity |
|
|
|
|
|
|
(10 |
) |
|
|
5 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results |
|
|
303 |
|
|
|
(144 |
) |
|
|
(34 |
) |
|
|
(15 |
) |
|
|
7 |
|
|
|
(2 |
) |
|
|
|
|
|
|
115 |
|
|
Total derivative gain/(loss) |
|
|
189 |
|
|
|
(43 |
) |
|
|
61 |
|
|
|
(20 |
) |
|
|
6 |
|
|
|
(1 |
) |
|
|
|
|
|
|
192 |
|
|
Total derivative gain/(loss) included in revenues |
|
|
|
|
|
|
(54 |
) |
|
|
51 |
|
|
|
(12 |
) |
|
|
6 |
|
|
|
(1 |
) |
|
|
(2 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gain/(loss) included in cost of operations |
|
$ |
189 |
|
|
$ |
11 |
|
|
$ |
10 |
|
|
$ |
(8 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
204 |
|
|
67
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2008 |
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
(In millions) |
|
Texas |
|
Northeast |
|
|
Central |
|
|
Total |
|
|
Net losses on settled positions, or financial income |
|
$ |
(48 |
) |
|
$ |
(34 |
) |
|
$ |
(4 |
) |
|
$ |
(86 |
) |
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled positions related to economic hedges |
|
|
(9 |
) |
|
|
(6 |
) |
|
|
|
|
|
|
(15 |
) |
Reversal of previously recognized unrealized gains on settled positions related to trading activity |
|
|
|
|
|
|
(3 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
Net unrealized losses on open positions related to economic hedges |
|
|
(382 |
) |
|
|
(113 |
) |
|
|
|
|
|
|
(495 |
) |
Net
unrealized gains/(losses) on open positions related to trading activity |
|
|
20 |
|
|
|
10 |
|
|
|
(15 |
) |
|
|
15 |
|
|
Subtotal mark-to-market results |
|
|
(371 |
) |
|
|
(112 |
) |
|
|
(19 |
) |
|
|
(502 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative loss |
|
$ |
(419 |
) |
|
$ |
(146 |
) |
|
$ |
(23 |
) |
|
$ |
(588 |
) |
|
Total derivative loss included in revenues |
|
|
(419 |
) |
|
|
(146 |
) |
|
|
(23 |
) |
|
|
(588 |
) |
Total derivative gain/(loss) included in cost of operations |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
NRGs second quarter 2009 gain was comprised of $115 million of mark-to-market gains and
$77 million in settled gains, or financial income. Of the $115 million of mark-to-market gains, a
$192 million gain represented the reversal of mark-to-market losses recognized on economic hedges
and a $35 million loss represents the reversal of mark-to-market gains recognized on trading
activity during 2008. The $43 million loss from economic hedge positions included a $40 million
decrease in value in forward purchases and sales of electricity and fuel due to higher forward
power and gas prices, and a $3 million loss primarily from hedge accounting ineffectiveness related
to gas trades in the Texas region which was driven by decreasing forward gas prices while forward
power prices decreased at a slower pace.
Reliant Energy gains of $210 million represents the roll-off of positions acquired as of May
1, 2009, valued at that dates forward prices which are offset by the losses at the settled prices
and are reflected in the cost of operations.
Since these hedging activities are intended to mitigate the risk of commodity price movements
on revenues and cost of energy, the changes in such results should not be viewed in isolation, but
rather should be taken together with the effects of pricing and cost changes on energy revenue and
costs. During and prior to 2009, NRG hedged a portion of the Companys 2008 and 2009 generation.
During the second quarter 2009, the settled and forward prices of electricity and natural gas
decreased resulting in the recognition of realized gains and unrealized mark-to-market gains, while
in the second quarter 2008, increasing prices of electricity and natural gas resulted in
recognition of unrealized mark-to-market losses.
Depreciation and Amortization
NRGs depreciation and amortization expense increased by $52 million for the three months
ended June 30, 2009, compared to the same period in 2008. Reliant Energys depreciation and
amortization expense for the two month period was $43 million
principally for amortization of customer relationships. The balance of the increase was
due to depreciation on the baghouse projects in western New York and the Elbow Creek project which
came on line in late 2008.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $48 million for the three months
ended June 30, 2009, compared to the same period in 2008. The increase was due to:
|
|
|
Retail selling, general and administrative expense totaled $49 million, including $9
million of bad debt expense during the two months ended June 30, 2009. |
|
|
|
Consultant costs increased $2 million consisting of costs related to Exelons exchange
offer and proxy contest efforts of $4 million offset by a decrease in other consulting
costs of $3 million. |
|
|
|
Wage and benefits expense increased $3 million. |
These increases were offset by:
|
|
|
Other expenses decreased by $5 million consisting of information technology,
administrative fees and travel related costs. |
68
Acquisition-related Transaction and Integration Costs
NRG
incurred Reliant Energy acquisition-related transaction costs of $21 million and integration costs of
$2 million for the three months ended June 30, 2009.
Equity in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates increased by $24 million for the three
months ended June 30, 2009, compared to the same period in 2008. During the three months ended
June 30, 2009, Sherbino recognized a $6 million mark-to-market unrealized loss whereas in the three
months ended June 30, 2008 Sherbino recognized a $32 million mark-to-market loss on a natural gas
swap executed to hedge its future power generation. Additionally, in 2009, the Companys share in
NRG Saguaro LLC earnings increased by $2 million.
Gain on Sale of Equity Method Investments and Other (Loss)/Income, Net
NRGs gain on sale of equity method investments increased by $128 million for the three months
ended June 30, 2009, compared to the same period in 2008 and other (loss)/income, net decreased by
$23 million for the three months ended June 30, 2009, compared to the same period in 2008. The
2009 amounts include a $128 million gain on the sale of NRGs 50% ownership interest in MIBRAG and
a $15 million realized loss on a forward contract for foreign currency executed to hedge the sale
proceeds from the MIBRAG sale.
Interest Expense
NRGs interest expense increased by $15 million for the three months ended June 30, 2009,
compared to the same period in 2008. This increase was primarily due to $13 million in fees
incurred on the CSRA facility for the months of May and June.
Income Tax Expense
NRGs income tax expense increased by $203 million for the three months ended June 30, 2009,
compared to the same period in 2008. The increase in income tax
expense was primarily due to an increase in income. The effective tax
rate was 25.8% and 56.4% for the three
months ended June 30, 2009, and 2008, respectively.
For
the three months ended June 30, 2009, NRGs overall effective tax rate on
continuing operations was different than the statutory rate of 35%
primarily due to a reduction in the state and local income tax rate
as a result of the Reliant Energy acquisition and the sale of the MIBRAG facility. For the
three months ended June 30, 2008, NRGs effective tax rate was
increased primarily due to the movement of the valuation allowance
established as result of capital losses generated in the period for
which there is no projected capital gain or available tax planning
strategies.
Income from Discontinued Operations, Net of Income Tax Expense
For the three months ended June 30, 2008, NRG recorded income from discontinued operations,
net of income tax expense, of $168 million. NRG closed the sale of ITISA during the second quarter
2008.
69
Managements discussion of the results of operations for the six months ended June 30, 2009 and 2008:
For the benefit of the following discussions, the table below represents the results of NRG
excluding the impact of Reliant Energy during the two months ended June 30, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, |
|
|
|
|
|
|
2009 |
|
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total excluding |
|
|
|
|
|
|
|
|
(In millions) |
|
Consolidated |
|
Reliant Energy |
|
Reliant Energy |
|
Consolidated |
|
Change % |
|
|
|
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
1,612 |
|
|
$ |
|
|
|
$ |
1,612 |
|
|
$ |
2,298 |
|
|
|
(30 |
)% |
|
|
|
|
Capacity revenue |
|
|
513 |
|
|
|
|
|
|
|
513 |
|
|
|
681 |
|
|
|
(25 |
) |
|
|
|
|
Retail revenue |
|
|
1,250 |
|
|
|
1,250 |
|
|
|
|
|
|
|
|
|
|
|
N/A |
|
|
|
|
|
Risk management activities |
|
|
425 |
|
|
|
|
|
|
|
425 |
|
|
|
(717 |
) |
|
|
(159 |
) |
|
|
|
|
Contract amortization |
|
|
(32 |
) |
|
|
(75 |
) |
|
|
43 |
|
|
|
157 |
|
|
|
(73 |
) |
|
|
|
|
Thermal revenue |
|
|
55 |
|
|
|
|
|
|
|
55 |
|
|
|
59 |
|
|
|
(7 |
) |
|
|
|
|
Other revenues |
|
|
72 |
|
|
|
|
|
|
|
72 |
|
|
|
140 |
|
|
|
(49 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
3,895 |
|
|
|
1,175 |
|
|
|
2,720 |
|
|
|
2,618 |
|
|
|
4 |
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales (including risk
management activities) |
|
|
1,492 |
|
|
|
614 |
|
|
|
878 |
|
|
|
1,353 |
|
|
|
(35 |
) |
|
|
|
|
Other operating costs |
|
|
516 |
|
|
|
41 |
|
|
|
475 |
|
|
|
462 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations |
|
|
2,008 |
|
|
|
655 |
|
|
|
1,353 |
|
|
|
1,815 |
|
|
|
(25 |
) |
|
|
|
|
Depreciation and amortization |
|
|
382 |
|
|
|
43 |
|
|
|
339 |
|
|
|
322 |
|
|
|
5 |
|
|
|
|
|
Selling, general and administrative |
|
|
214 |
|
|
|
49 |
|
|
|
165 |
|
|
|
158 |
|
|
|
4 |
|
|
|
|
|
Acquisition-related transaction and
integration costs |
|
|
35 |
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
N/A |
|
|
|
|
|
Development costs |
|
|
22 |
|
|
|
|
|
|
|
22 |
|
|
|
16 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
2,661 |
|
|
|
747 |
|
|
|
1,914 |
|
|
|
2,311 |
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
1,234 |
|
|
|
428 |
|
|
|
806 |
|
|
|
307 |
|
|
|
163 |
% |
|
|
|
|
|
Operating Revenues
Operating revenues, excluding risk management activities, increased $135 million during the
six months ended June 30, 2009, compared to the same period in 2008.
|
|
|
Energy revenue decreased $686 million during the six months ended June 30, 2009,
compared to the same period in 2008: |
|
o |
|
Texas energy revenue decreased by $277 million, with $198 million by driven by
lower energy prices and $79 million decrease driven by a reduction in generation. The
average realized energy price decreased by 14%, driven by a 51% decrease in merchant
prices offset by a 24% increase in contract prices. Generation decreased by 5% driven by
a 8% decrease in coal plant generation and a 21% decrease in gas plant generation,
offset by generation from the recently constructed Elbow Creek wind farm, which was not
in operation in 2008. Coal plant generation was adversely affected by lower energy
prices driven by a 61% decrease in average natural gas prices also in combination with
depressed heat rates in the region. Increased wind generation shifted the coal units
position in the bid stack, negatively affecting coal plant generation. |
|
o |
|
Northeast energy revenue decreased by $289 million, with $113 million driven by
lower energy prices and $212 million attributable to a reduction in generation offset by
a $35 million increase from higher net contract revenue. Merchant energy prices were
lower by an average of 32%. The lower energy prices reduced the Companys net cost
incurred to meet obligations under load serving contracts in the PJM market. Generation
decreased by 38%, with a 37% decrease in coal generation and a 40% decrease in oil and
gas generation. Weakened demand for power combined with low gas prices resulted in
reduced merchant energy prices. Lower merchant energy prices combined with higher cost
of production from the introduction of RGGI resulted in increased hours where the units
were uneconomic to dispatch. The decline in oil and gas generation is attributable to
fewer reliability run hours at the Connecticut plants and a planned major maintenance
outage at the Arthur Kill plant. |
70
|
o |
|
South Central decreased by $53 million due to a $42 million decline in contract
revenue coupled with an $11 million decrease in merchant energy revenues. Contract
customer sales volumes were down 11%. The decline in contract energy price was driven
by a $7 million decrease in fuel cost pass through to the cooperatives. Also
contributing to the decline in contract revenue was $31 million due to the expiration of
a contract with a regional utility. Average realized price on contract energy sales was
$23.17 per MWh in 2009 compared to $28.72 per MWh in 2008. The expiration of the
contract allowed more energy to be sold into the merchant market, but at lower average
prices resulting in an $11 million decline in revenue. Megawatt hours sold to the
merchant market increased by 51%, while prices fell by 42%. Increased use of the
regions tolled facility provided additional energy to the merchant market. |
|
o |
|
Intercompany energy revenues intercompany sales of $54 million by NRGs Texas
region to Reliant Energy is eliminated in consolidation. |
|
|
|
Capacity revenue decreased $168 million during the six months ended June 30, 2009,
compared to the same period in 2008: |
|
o |
|
Texas capacity revenue decreased by $143 million due to a lower proportion of
baseload contracts which contained a capacity component. |
|
o |
|
Northeast capacity revenue decreased by $15 million due to lower capacity
prices in the NYISO and PJM markets which was partially offset by higher capacity prices
in the NEPOOL market. |
|
o |
|
South Central capacity revenue increased by $18 million resulting primarily
from a new capacity agreement. |
|
o |
|
West capacity revenue decreased by $9 million due to the expiration of a two
year tolling agreement at the El Segundo facility in April 2008, which was replaced by
resource adequacy and capacity contracts at lower prices. |
|
o |
|
Intercompany capacity revenue intercompany sales of $12 million by NRGs Texas
region to Reliant Energy is eliminated in consolidation. |
|
|
|
Retail revenue the acquisition of Reliant Energy contributed $1.3 billion of retail
revenue during the two months ended June 30, 2009. This includes mass revenues of
$761 million, C&I revenues of $437 million, and supply management revenues of $52 million. |
|
|
|
Contract amortization revenue decreased by $189 million in the six months ended June
30, 2009, as compared to the same period in 2008. The decrease includes a reduction of
$114 million in revenue from the Texas Genco acquisition due to the lower volume of contracted
energy and $75 million in amortization expense of intangible assets related to the Reliant
Energy acquisition in 2009. |
|
|
|
Other revenues decreased by $68 million driven by $30 million in lower ancillary
revenue, $33 million in lower emissions revenue, and a $37 million decrease in fuels trading.
These decreases were offset by the recognition of a $31 million non-cash gain related to
settlement of a pre-existing in-the-money contract with Reliant Energy. |
71
Cost of Operations
Cost of operations, excluding risk management activities, increased $329 million during the
six months ended June 30, 2009, compared to the same period in 2008.
|
|
|
Cost of energy
increased $275 million during the six months ended June 30, 2009,
compared to the same period in 2008 due to: |
|
o |
|
Retail revenue Reliant Energy incurred $803 million of cost of energy during
the two months ended June 30, 2009 which included $66 million of intercompany purchased
energy costs. |
|
o |
|
Texas cost of energy decreased $250 million due to lower natural gas, coal,
purchased energy and ancillary services costs. Natural gas costs decreased $197
million, reflecting a 61% decline in average natural gas per MMBtu prices and a 21%
decrease in gas-fired generation. Coal costs decreased $9 million as the 2008 expense
included a $15 million loss reserve related to a coal contract dispute and $12 million
resulting from reduced generation. This decrease was offset by an $11 million increase
due to higher prices and a $7 million increase in transportation cost. Purchased energy
decreased $14 million due to a lower average price to procure energy from the market
offset by a greater number of MWhs purchased. Ancillary service costs decreased by $24
million due to a decrease in purchased ancillary services costs incurred to meet
contract obligations. Nuclear fuel expenses decreased by $10 million as amortization of
nuclear fuel inventory ended in March 2008 related to the Texas Genco acquistion. |
|
o |
|
Northeast cost of energy decreased $169 million due to a $107 million reduction
in natural gas and oil costs and a $69 million reduction in coal costs. Natural gas and
oil costs decreased due to 40% lower generation and 56% lower average natural gas
prices. Coal costs decreased due to 37% lower coal generation. These decreases were
offset by a $8 million increase in costs related to RGGI which became effective in 2009. |
|
o |
|
South Central cost of energy decreased $19 million due to a $16 million
decrease in purchased energy reflecting lower fuel costs associated with the regions
tolled facility and lower market energy prices, and a $4 million decrease in
transmission expense due to transmission line outages. |
|
o |
|
West cost of
energy decreased $7 million due to a 66% decline in average natural
gas per MMBtu prices offset by a $3 million increase in fuel oil expense resulting
from a write down to market of fuel oil inventory no longer used in the production of
energy. |
|
o |
|
Intercompany cost of energy intercompany purchases of $66 million by Reliant
Energy from NRGs Texas region are eliminated in consolidation. |
|
|
|
Other operating expenses increased $54 million during the six months ended June 30,
2009, compared to the same period in 2008. Reliant Energy incurred $41 million in other
operating costs during the two months ended June 30, 2009. Further, operating and
maintenance expenses increased by $7 million and property taxes
increased by $5 million. |
72
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
increased by $1,278 million during the six months ended June 30, 2009, compared to the same period
in 2008. The breakdown of changes by region follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2009 |
|
|
|
Reliant |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Energy |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
West |
|
|
Thermal |
|
|
Elimination |
|
|
Total |
|
|
Net gains/(losses) on settled positions, or financial income |
|
$ |
(114 |
) |
|
$ |
130 |
|
|
$ |
151 |
|
|
$ |
5 |
|
|
$ |
(3 |
) |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
171 |
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized (gains)/losses
on settled positions related to economic hedges |
|
|
210 |
|
|
|
(12 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
176 |
|
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 |
|
|
93 |
|
|
|
88 |
|
|
|
136 |
|
|
|
(14 |
) |
|
|
6 |
|
|
|
1 |
|
|
|
|
|
|
|
310 |
|
Net unrealized gains/(losses) on open positions related to
trading activity |
|
|
|
|
|
|
(8 |
) |
|
|
4 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8 |
|
|
|
Subtotal mark-to-market results |
|
|
303 |
|
|
|
25 |
|
|
|
97 |
|
|
|
(40 |
) |
|
|
6 |
|
|
|
(1 |
) |
|
|
|
|
|
|
390 |
|
|
Total derivative gain/(loss) |
|
|
189 |
|
|
|
155 |
|
|
|
248 |
|
|
|
(35 |
) |
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
561 |
|
|
Total derivative gain/(loss) included in revenues |
|
|
|
|
|
|
209 |
|
|
|
233 |
|
|
|
(19 |
) |
|
|
3 |
|
|
|
1 |
|
|
|
(2 |
) |
|
|
425 |
|
|
Total derivative gain/(loss) included in cost of operations |
|
$ |
189 |
|
|
$ |
(54 |
) |
|
$ |
15 |
|
|
$ |
(16 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
136 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
(In millions) |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
Total |
|
|
|
Net losses on settled positions, or financial income |
|
$ |
(50 |
) |
|
$ |
(24 |
) |
|
$ |
|
|
|
$ |
(74 |
) |
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled positions related to economic hedges |
|
|
(16 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
(25 |
) |
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity |
|
|
1 |
|
|
|
(2 |
) |
|
|
(11 |
) |
|
|
(12 |
) |
Net unrealized losses on open positions related to economic hedges |
|
|
(495 |
) |
|
|
(142 |
) |
|
|
|
|
|
|
(637 |
) |
Net unrealized gains/(losses) on open positions related to trading activity |
|
|
37 |
|
|
|
(7 |
) |
|
|
1 |
|
|
|
31 |
|
|
Subtotal mark-to-market results |
|
|
(473 |
) |
|
|
(160 |
) |
|
|
(10 |
) |
|
|
(643 |
) |
|
Total derivative loss |
|
$ |
(523 |
) |
|
$ |
(184 |
) |
|
$ |
(10 |
) |
|
$ |
(717 |
) |
|
Total derivative loss included in revenues |
|
|
(523 |
) |
|
|
(184 |
) |
|
|
(10 |
) |
|
|
(717 |
) |
Total derivative gain/(loss) included in cost of operations |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
NRGs first half of 2009 gain was comprised of a $390 million of mark-to-market gains and $171
million in settled gains, or financial income. Of the $390 million of mark-to-market gains, a $176
million gain represents the reversal of mark-to-market losses recognized on economic hedges and a
$104 million loss represents the reversal of mark-to-market gains recognized on trading activity
during 2008. The $310 million gain from economic hedge positions included $217 million recognized
in earnings from previously deferred amounts in OCI as the Company discontinued cash flow hedge
accounting in the first quarter for certain 2009 transactions in Texas and New York due to lower
expected generation, a $92 million increase in value in forward sales of electricity and fuel due
to lower forward power and gas prices, and a $1 million gain primarily from hedge accounting
ineffectiveness related to gas trades in the Texas region which was driven by decreasing forward
gas prices while forward power prices decreased at a slower pace. The Company recognized a
derivative loss of $29 million resulting from discontinued NPNS designated coal purchases due to
expected lower coal consumption and accordingly the Company could not assert taking physical
delivery of coal purchase transactions under NPNS designation. This amount was included in the
Companys cost of operations during the six months ended June 30, 2009.
Reliant Energy gains of $210 million represents the roll-off of positions acquired as of May
1, 2009, valued at that dates forward prices which are offset by the losses at the settled prices
and are reflected in the cost of operations.
Since these hedging activities are intended to mitigate the risk of commodity price movements
on revenues and cost of energy, the changes in such results should not be viewed in isolation, but
rather should be taken together with the effects of pricing and cost changes on energy revenue and
costs. During and prior to 2008, NRG hedged a portion of the Companys 2008 and 2009 generation.
During the first half of 2009, the settled and forward prices of electricity and natural gas
decreased resulting in the recognition of realized gains and unrealized mark-to-market gains, while
in the first half of 2008, increasing prices of electricity and natural gas resulted in recognition
of unrealized mark-to-market losses.
73
Depreciation and Amortization
NRGs depreciation and amortization expense increased by $60 million for the six months ended
June 30, 2009, compared to the same period in 2008. Reliant Energys depreciation and amortization
expense for the two month period was $43 million principally for
amortization of customer relationships. The balance of the increase was due to
depreciation on the baghouse projects in western New York and the Elbow Creek project which came
online in late 2008.
Selling, General and Administrative Expenses
Selling, general and administrative expenses increased by $56 million for the six months ended
June 30, 2009, compared to the same period in 2008. The increase was due to:
|
|
|
Retail selling, general and administrative expense totaled $49 million, including $9
million of bad debt expense during the two months ended June 30, 2009. |
|
|
|
|
Wage and benefits expense increased $6 million. |
|
|
|
|
Consultant costs increased $5 million consisting of costs related to Exelons
exchange offer and proxy contest efforts of $9 million offset by a decrease in other
consulting costs of $4 million. |
These increases were offset by:
|
|
|
Other expenses decreased by $2 million consisting of information technology,
administrative fees and travel related costs. |
Acquisition-related Transaction and Integration Costs
NRG
incurred Reliant Energy acquisition-related transaction costs of $33 million and integration costs of
$2 million for the six months ended June 30, 2009.
Equity in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates increased by $50 million for the six
months ended June 30, 2009, compared to the same period in 2008. During 2009, Sherbino recognized
a $1 million mark-to-market unrealized loss whereas in 2008 Sherbino recognized a $50 million
mark-to-market loss on a natural gas swap executed to hedge its future power generation.
Additionally, in 2009, the Companys share in NRG Saguaro LLC earnings increased by $7 million and
the Companys share in Gladstone decreased by $4 million.
Gain on Sale of Equity Method Investments and Other (Loss)/Income, Net
NRGs gain on sale of equity method investments increased by $128 million for the six months
ended June 30, 2009, compared to the same period in 2008 and other (loss)/income, net decreased by
$35 million for the six months ended June 30, 2009, compared to the same period in 2008. The 2009
amounts include a $128 million gain on the sale of NRGs
50% ownership interest in MIBRAG and a $24
million mark-to-market unrealized loss on a forward contract for foreign currency executed to hedge
the sale proceeds from the MIBRAG sale.
Interest Expense
NRGs interest expense decreased by $3 million for the six months ended June 30, 2009,
compared to the same period in 2008. This decrease was primarily due to a $19 million decrease in
interest expense on the Companys Term Loan facility due to a decrease in the average interest
rates and the outstanding notional amount offset by a $13 million increase in fees incurred on the
CSRA facility for the months of May and June.
74
Income Tax Expense
NRGs
income tax expense increased by $447 million for the six months ended June 30, 2009,
compared to the same period in 2008.
The increase in income tax expense was primarily due to an increase
in income. The effective tax rate was 41.5% and 20.0% for the six
months ended June 30, 2009, and 2008, respectively.
For the
six months ended June 30, 2009, NRGs overall effective tax rate on
continuing operations 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
reduction of the state and local income tax rate as a result of the
Reliant Energy acquisition. For the six months ended June 30, 2008,
NRGs overall effective tax rate was reduced primarily by
foreign earnings that are taxed at rates in foreign jurisdictions
lower than the U.S. statutory rate.
Income from Discontinued Operations, Net of Income Tax Expense
For the six months ended June 30, 2008, NRG recorded income from discontinued operations, net
of income tax expense, of $172 million. NRG closed the sale of ITISA during the second quarter
2008.
75
Results of Operations for Reliant Energy
Reliant Energy
The following is a detailed discussion of the results of operations of NRGs retail business
segment since the date of acquisition.
Operating Strategy
Reliant Energys business is to earn a margin by selling electricity to end use customers,
providing innovative and value-enhancing services to such customers, and acquiring supply for the
estimated demand. As a retail energy provider, Reliant Energy arranges for the transmission and
delivery of electricity to customers, bills customers, collects payment for electricity sold,
develops innovative energy solutions, engages in energy efficiency initiatives and maintains call
centers to provide customer service. Although NRG has begun the process of becoming the primary
provider of Reliant Energys supply requirements, Reliant Energy presently purchases a substantial
portion of its supply requirements from third parties such as generation companies and power
marketers. Transmission and distribution services are purchased from entities regulated by the
PUCT and subject to ERCOT protocols.
The energy usage of Reliant Energys retail customers varies by season, with generally higher
usage during the summer period. As a result, Reliant Energys net working capital requirements
generally increase during summer months along with the higher revenues, and then decline during
off-peak months.
As of June 30,
2009, Reliant Energy had approximately 1,274 employees, none of whom are covered
by a bargaining agreement.
Customer Segments
The following is a description of Reliant Energys significant customer segments in Texas.
|
|
|
Mass Reliant Energys Mass customer base is made up of approximately 1.6 million
residential and small business customers in the ERCOT market with more than half located
in the Houston area. Reliant Energy also serves customers in other competitive markets in
ERCOT including the Dallas, Fort Worth, and Corpus Christi areas. |
|
|
|
|
Commercial and industrial Reliant Energy markets electricity and energy services to
approximately 0.1 million C&I customers in Texas. These customers include refineries, chemical
plants, manufacturing facilities, hospitals, universities, commercial real estate,
government agencies, restaurants, and other commercial facilities. |
Market Framework
Reliant Energy operates within the same ERCOT market as the Companys Texas region. For
further discussion of the Texas market framework, see pages 25-26 of NRG Energy Inc.s 2008 Annual Report on Form 10-K.
For further discussion of the Companys Reliant Energy operations, see Item I, Note 3,
Business Acquisition.
76
Selected Income Statement Data
|
|
|
|
|
|
|
Period ended |
(In millions except otherwise noted) |
|
June 30, 2009(a) |
|
Operating Revenues |
|
|
|
|
Mass revenues |
|
$ |
761 |
|
Commercial and industrial revenues |
|
|
437 |
|
Supply management revenues |
|
|
52 |
|
Contract amortization |
|
|
(75 |
) |
|
Total operating revenues |
|
|
1,175 |
|
Operating Costs and Expenses |
|
|
|
|
Cost of energy (including risk management activities) |
|
|
614 |
|
Other operating expenses |
|
|
90 |
|
Depreciation and amortization |
|
|
43 |
|
|
Operating Income |
|
$ |
428 |
|
Electricity sales volume GWh (in thousands): |
|
|
|
|
Mass |
|
|
4,851 |
|
Commercial and Industrial (c) |
|
|
5,580 |
|
Business Metrics |
|
|
|
|
Weighted average Retail customers count (in thousands, metered locations)
|
|
|
|
|
Mass |
|
|
1,601 |
|
Commercial and Industrial (c) |
|
|
71 |
|
Retail customers count (in thousands, metered locations) |
|
|
|
|
Mass |
|
|
1,589 |
|
Commercial and Industrial (c) |
|
|
68 |
|
|
|
|
|
|
Cooling Degree Days, or CDDs (b) |
|
|
971 |
|
CDDs 30 year average |
|
|
819 |
|
Heating Degree Days, or HDDs (b) |
|
|
1 |
|
HDDs 30 year average |
|
|
5 |
|
|
|
(a) |
|
For the period May 1, 2009, to June 30, 2009. |
|
(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) |
|
Includes customers of the Texas General Land Office for whom the Company provides
services. |
77
Year to date results
Operating Income
Operating income for the two months ended June 30, 2009, was $428 million, which consisted of
the following:
|
|
|
|
|
|
|
Period ended |
(In millions except otherwise noted) |
|
June 30, 2009(a) |
|
Reliant Energy Operating Income: |
|
|
|
|
Mass revenues |
|
$ |
761 |
|
Commercial and industrial revenues |
|
|
437 |
|
Supply management revenues |
|
|
52 |
|
|
Total retail operating revenues (a) |
|
|
1,250 |
|
|
Retail cost of sales (a) |
|
|
930 |
|
|
Total retail gross margin |
|
|
320 |
|
Unrealized gains on energy supply derivatives |
|
|
303 |
|
Contract amortization, net |
|
|
(62 |
) |
Other operating expenses |
|
|
(90 |
) |
Depreciation and amortization |
|
|
(43 |
) |
|
Operating Income |
|
$ |
428 |
|
|
(a) |
|
Amounts exclude unrealized gains/(losses) on energy supply derivatives and contract
amortization. |
|
|
|
Gross margin Reliant Energys gross margin totaled $320 million, which was driven by
strong margins in the residential customer segment and expanding margins in the commercial
and industrial segment. In addition, volumes were higher due to greater customer usage as
a result of warmer weather as compared to the 30 year CDD average, although partially
offset by a decrease in number of customers during the two months ended June 30, 2009. The
strong margins were driven by high revenue rates relative to the current market cost of
energy as the Company acquired Reliant Energy customers on prices more consistent with 2008 costs
of natural gas. The lag between significant declines in energy costs and the corresponding
price reductions resulted in higher margins for the period. This benefit from lower cost
of energy will be partially offset in future periods by the Companys announced and enacted
price reductions of up to 20% for certain mass customers. These price reductions are
consistent with recent trends in competitive offers, and the Company expects to see
competitors continue to more accurately reflect their true cost of capital in their
pricing. Competition, along with the Companys pricing and supply decisions, will likely
drive lower margins in the future and the Company believes that, in order to stabilize
customer count, this level of margins will not be sustainable. |
|
|
|
|
With the decline in natural gas prices, and the corresponding decline in the cost of energy
supply, competitive retail prices have decreased relative to 2008. If costs continue to
remain low, the Company expects competitive retail prices to continue to decline and place
pressure on unit margins. Additionally, the Companys customer counts have declined
approximately 1% for each of the past two months. The recent price reductions for certain
mass customers are expected to improve customer retention. Further price reductions may be
necessary if current attrition trends continue. |
|
|
|
|
Risk management activities Unrealized gains of $303 million on economic hedges
relates to supply contracts that were recognized for the two months ended June 2009
including $210 million of gains representing a roll-off of positions acquired at May 1, 2009,
at forward prices and $93 million of gains that represents mark-to-market changes in
forward value of purchased electricity and gas. The $210 million gain from roll-off
positions is offset by the realized losses at the settled prices and reflected in the cost
of operations. |
78
Operating Revenues
Total operating revenues for the two months ended June 30, 2009 were $1.2 billion and
consisted of the following:
|
|
|
Mass revenues totaled $761 million from retail electric sales to approximately 1.6
million end use customers in the Texas market. Revenue rates for acquired Reliant Energy customers were not consistent with current costs of natural gas. The Company lowered
prices up to 10% on select residential customer segments effective June 1, and announced
another rate reduction for July. These two pricing actions will provide up to 20% lower
prices for certain Mass customers. Also, warmer weather, as compared to the 30 year CDD
average, caused an increase in customer usage. The higher prices, along with higher usage,
were accompanied with a decrease in number of customers by approximately 1% per month. The
Company expects the announced price reductions to stem the recent attrition trends. |
|
|
|
|
Commercial and industrial revenue As of May 1, 2009, Reliant Energy re-launched its
C&I segment. C&I revenues for the two months ended June 30, 2009
totaled $437 million on volume sales of roughly 5,580 GWh. Variable rate contracts tied to
the market price of natural gas accounted for approximately 68% of the contracted volumes
as of June 30, 2009. |
|
|
|
|
Contract amortization reduced operating
revenues by $75 million resulting from net in-market C&I
contracts, which will continue to amortize over the term of the contracts
acquired in the Reliant Energy acquisition. |
|
|
|
|
Supply management revenues totaled $52 million from the sale of excess supply into
various markets in Texas. |
Cost of Energy
Cost of energy for the two months ended June 30, 2009, was $614 million and consisted of the
following:
|
|
|
Supply costs totaled $550 million. The current market cost of energy is
significantly down in 2009. Natural gas prices have declined 70% since the second quarter
of 2008. Also, warmer weather for the period, as compared to the 30 year CDD average,
caused an increase in purchased supply volumes at a relatively low cost. |
|
|
|
|
Risk management activities Unrealized gains of $303 million on economic hedges
relate to supply contracts that were recognized for the two months ended June 2009
including $210 million of gains which represent a roll-off of positions acquired at May 1,
2009 valued at forward prices and $93 million of gains that represent mark-to-market
changes in forward value of purchased electricity and gas. The $210 million gain from roll-off positions is offset by
the losses at the settled prices and reflected in cost of
operations. |
|
|
|
|
Transmission and distribution charges totaled $267 million. |
|
|
|
|
Financial settlements totaled $114 million resulting from financial settlement of
energy related derivatives. |
|
|
|
|
Contract amortization reduced the cost of energy by $13 million, resulting from the net out-of-market
supply contracts established at the acquisition date. These contracts will be amortized
over the life of the contracts. |
Other Operating Expenses
Other operating expenses for the two months ended June 30, 2009, was $90 million, or 8% of the
regions total operating revenues. Other operating expenses consisted of the following:
|
|
|
Operations and maintenance expenses totaled $25 million, 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. |
|
|
|
|
Selling, general and administrative expenses totaled $40 million, 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. |
|
|
|
|
Gross receipts tax totaled $16 million or 1.4% of revenue. |
|
|
|
|
Bad debt expense totaled $9 million or 0.8% of revenue. |
79
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
For a discussion of the business profile of the Companys Texas operations, see pages 23-26 of
NRG Energy, Inc.s 2008 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) |
|
2009 |
|
|
2008 |
|
|
Change % |
|
2009 |
|
|
2008 |
|
|
Change % |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
600 |
|
|
$ |
925 |
|
|
|
(35 |
)% |
|
$ |
1,194 |
|
|
$ |
1,471 |
|
|
|
(19 |
)% |
Capacity revenue |
|
|
47 |
|
|
|
119 |
|
|
|
(61 |
) |
|
|
94 |
|
|
|
237 |
|
|
|
(60 |
) |
Risk management activities |
|
|
(54 |
) |
|
|
(419 |
) |
|
|
(87 |
) |
|
|
209 |
|
|
|
(523 |
) |
|
|
(140 |
) |
Contract amortization |
|
|
17 |
|
|
|
83 |
|
|
|
(80 |
) |
|
|
32 |
|
|
|
146 |
|
|
|
(78 |
) |
Other revenues |
|
|
9 |
|
|
|
43 |
|
|
|
(79 |
) |
|
|
15 |
|
|
|
69 |
|
|
|
(78 |
) |
|
| |
| |
|
|
|
|
|
Total operating revenues |
|
|
619 |
|
|
|
751 |
|
|
|
(18 |
) |
|
|
1,544 |
|
|
|
1,400 |
|
|
|
10 |
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management activities) |
|
|
236 |
|
|
|
413 |
|
|
|
(43 |
) |
|
|
474 |
|
|
|
671 |
|
|
|
(29 |
) |
Other operating expenses |
|
|
154 |
|
|
|
150 |
|
|
|
3 |
|
|
|
322 |
|
|
|
314 |
|
|
|
3 |
|
Depreciation and amortization |
|
|
117 |
|
|
|
113 |
|
|
|
4 |
|
|
|
234 |
|
|
|
226 |
|
|
|
4 |
|
|
| |
| |
|
|
|
|
|
Operating Income |
|
$ |
112 |
|
|
$ |
75 |
|
|
|
49 |
|
|
$ |
514 |
|
|
$ |
189 |
|
|
|
172 |
|
MWh sold (in thousands) |
|
|
12,333 |
|
|
|
12,675 |
|
|
|
(3 |
) |
|
|
22,506 |
|
|
|
23,706 |
|
|
|
(5 |
) |
MWh generated (in thousands) |
|
|
11,919 |
|
|
|
12,500 |
|
|
|
(5 |
) |
|
|
21,992 |
|
|
|
23,256 |
|
|
|
(5 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
45.20 |
|
|
|
164.29 |
|
|
|
(72 |
) |
|
|
39.43 |
|
|
|
117.80 |
|
|
|
(67 |
) |
Cooling Degree Days, or CDDs (a) |
|
|
982 |
|
|
|
1,009 |
|
|
|
(3 |
) |
|
|
1,108 |
|
|
|
1,092 |
|
|
|
1 |
|
CDDs 30 year average |
|
|
854 |
|
|
|
854 |
|
|
|
|
|
|
|
948 |
|
|
|
949 |
|
|
|
|
|
Heating Degree Days, or HDDs (a) |
|
|
100 |
|
|
|
112 |
|
|
|
(11 |
)% |
|
|
1,003 |
|
|
|
1,157 |
|
|
|
(13 |
) |
HDDs 30 year average |
|
|
83 |
|
|
|
83 |
|
|
|
|
|
|
|
1,205 |
|
|
|
1,215 |
|
|
|
(1 |
)% |
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD represents
the number of degrees that the mean temperature for a particular day is above 65 degrees
Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period
of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly Results
Operating Income
Operating income increased by $37 million for the three months ended June 30, 2009, compared
to the same period in 2008, primarily due to:
|
|
|
Risk management activities an increase of
$365 million was primarily due to a $212 million reduction
in unrealized derivative losses and $153 million in realized gains on
settled financial transactions. These changes reflect a decline in
forward and settled power and gas
prices related to economic hedges in the second quarter 2009 as compared to the same period
of 2008. |
|
|
|
|
Energy revenues decreased by $325 million due to lower average energy prices and
lower sales volume. |
|
|
|
|
Cost of energy decreased by $177 million reflecting lower gas costs and a decrease
in coal and gas generation. |
80
Operating Revenues
Total operating revenues decreased by $132 million during the three months ended June 30,
2009, compared to the same period in 2008, due to:
|
|
|
Risk management activities loss of $54 million was recognized for the three months
ended June 30, 2009, compared to a $419 million loss in the same period in 2008. The $54
million of losses included $159 million of unrealized mark-to-market losses and $105
million in settled gains, or financial income, compared to $371 million in unrealized
derivative losses and $48 million of settled financial losses in the same period in 2008.
The $159 million loss included a $133 million unrealized loss due to the increase of
forward power and gas prices related to economic hedges, a $2 million unrealized loss due
to ineffectiveness on gas hedges, and a $24 million unrealized loss attributable to trading
activities. |
|
|
|
Energy revenues decreased $325 million due to: |
|
o |
|
Energy Prices decreased by $283 million as the unusually high prices that
occurred in the second quarter of 2008 did not repeat in the same period 2009. Higher
MWh sold in the merchant market were offset by significantly lower merchant prices in
2009 versus the same period of 2008. The average realized energy price decreased by
32%, driven by a 63% decrease in merchant prices offset by a 25% increase in contract
prices. |
|
o |
|
Generation
decreased by 5% contributing to a $42 million decrease in sales
volume. This decrease was driven by a 9% decrease in coal plant generation and a 13%
decrease in gas plant generation, offset by a 17% increase in nuclear plant generation
as the second quarter of 2008 contained a planned outage which did not occur in the same
period 2009, as well as generation from the recently constructed Elbow Creek wind farm,
which was not in operation in the second quarter 2008. Coal plant generation was
adversely affected by lower energy prices driven by a 68% decrease in average natural
gas prices in combination with depressed heat rates in the region. Increased wind
generation shifted the coal units position in the bid stack
which
also negatively affected
coal plant generation. These factors led to increased hours in which the coal units
were uneconomic to dispatch. |
|
|
|
Capacity revenue decreased by $72 million due to a lower proportion of baseload
contracts which contain a capacity component. |
|
|
|
|
Contract amortization revenue resulting from the Texas Genco acquisition decreased by
$66 million due to the reduced volume of contracted energy in 2009 as compared to 2008. |
|
|
|
|
Other revenue decreased by $34 million due to lower ancillary services revenue, lower
emissions credit revenue and lower physical coal and natural gas sales. |
Cost of Energy
Cost of energy decreased by $177 million during the three months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Natural gas costs decreased by $150 million due to a 68% decline in average natural
gas prices and a 13% decrease in gas-fired generation. |
|
|
|
|
Derivative Cost of Energy decreased $17 million due to the recognition of unrealized
gains on coal contracts of $8 million as the Company discontinued NPNS accounting for coal
purchases combined with $9 million of unrealized gains associated with oil transactions
hedging price risk on rail transportation contracts. |
|
|
|
|
Ancillary Services Costs decreased by $12 million due to a decrease in purchased
ancillary services costs incurred to meet obligations. |
81
These decreases were offset by:
|
|
|
Financial Cost of Energy increased $6 million primarily due to higher risk management
activities to hedge for coal transportation, as well as certain hedge allocations. |
|
|
|
|
Coal costs increased by $3 million due to higher cost of coal of $10 million and
greater transportation costs of $4 million . These increases were offset by reduced
generation of $12 million. |
Other Operating Expenses
Other operating expenses increased by $4 million during the three months ended June 30, 2009,
compared to the same period in 2008, driven by increased development costs in 2009, offset by a
decrease in operations and maintenance expense.
Year to date results
Operating Income
Operating income increased by $325 million for the six months ended June 30, 2009, compared to
the same period in 2008, primarily due to:
|
|
|
Risk management activities an increase of $732 million was primarily due to a $539
million increase in unrealized derivative gains and $193 million in realized gains on
settled financial transactions. These changes reflect a decline in forward power and gas
prices related to economic hedges in the first half of 2009 as compared to the same period
of 2008. |
|
|
|
Energy revenues decreased by $277 million due to lower average energy prices and
lower sales volume. |
|
|
|
Cost of energy decreased by $197 million reflecting lower gas costs and a decrease in
coal and gas generation. |
Operating Revenues
Total operating revenues increased by $144 million during the six months ended June 30, 2009,
compared to the same period in 2008, due to:
|
|
|
Risk management activities $209 million gain was recognized for the six months ended
June 30, 2009, compared to a $523 million loss in the same period in 2008. The $209
million gain included $65 million of unrealized mark-to-market gains and $144 million in
settled gains, or financial income, compared to $473 million in unrealized derivative
losses and $50 million of settled financial losses in the same period in 2008. The $65
million gain included an $115 million unrealized gain due to
decreases in forward and settled power and
gas prices related to economic hedges, and a $50 million unrealized loss attributable to
trading activities. |
|
|
|
Energy revenues decreased $277 million due to: |
|
o |
|
Energy Prices decreased by $198 million as unusually high prices that occurred
in the second quarter 2008 did not repeat in 2009. Higher MWh sold under merchant
market was offset by lower merchant prices. The average realized energy price decreased
by 14%, driven by a 51% decrease in merchant prices offset by a 24% increase in contract
prices. |
|
|
o |
|
Generation
decreased by 5% contributing to a $79 million decrease in sales
volume. This decrease was driven by an 8% decrease in coal plant generation and a 21%
decrease in gas plant generation, offset by generation from the recently constructed
Elbow Creek wind farm, which was not in operation in the first half of 2008. Coal plant
generation was adversely affected by lower energy prices driven by a 61% decrease in
average natural gas prices in combination with depressed heat rates in the region.
Increased wind generation shifted the coal units position in the bid stack also
negatively affecting coal plant generation. These factors led to increased hours where
the coal units were uneconomic to dispatch. |
82
|
|
|
Capacity revenue decreased by $143 million due to a lower proportion of baseload
contracts which contain a capacity component. |
|
|
|
|
Contract amortization revenue resulting from the Texas Genco acquisition decreased by
$114 million due to the reduced volume of contracted energy in 2009 as compared to 2008. |
|
|
|
|
Other revenue decreased by $54 million due to lower ancillary services provided to
the market as well as lower emissions credit revenue and reduced physical sales. |
Cost of Energy
Cost of energy decreased by $197 million during the six months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Natural gas costs decreased by $197 million due to a 61% decline in average natural
gas prices and a 21% decrease in gas-fired generation. |
|
|
|
|
Ancillary Service Costs decreased by $24 million due to a decrease in purchased
ancillary services costs incurred to meet contract obligations. |
|
|
|
|
Coal costs decreased by $9 million as the first half of 2008 included a $15 million
loss reserve related to a coal contract dispute. In addition, there was a $12 million
reduction caused by lower generation. These decreases were offset by higher coal costs of
$11 million and greater transportation costs of $7 million. |
|
|
|
|
Purchased energy decreased by $14 million due to a lower average price to procure
energy from the market offset by a greater number of MWhs purchased. |
|
|
|
|
Nuclear fuel expense resulting from the Texas Genco purchase accounting, decreased
$10 million as amortization of nuclear fuel inventory ended in March 2008. |
These decreases were offset by:
|
|
|
Derivative Cost of Energy increased $40 million due to the recognition of unrealized
losses on coal contracts of $32 million as the Company discontinued NPNS accounting for
coal purchases combined with $8 million of unrealized losses associated with oil
transactions hedging price risk on rail transportation contracts. |
Other Operating Expenses
Other operating expenses increased by $8 million during the six months ended June 30, 2009,
compared to the same period in 2008, driven by an increase in general and administrative expense as
a result of higher external consulting expenditures and higher corporate allocations, offset by
lower operations and maintenance expenditures.
83
Northeast Region
For a discussion of the business profile of the Northeast region, see pages 27-29 of NRG
Energy, Inc.s 2008 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) |
|
2009 |
|
|
2008 |
|
|
Change % |
|
2009 |
|
|
2008 |
|
|
Change % |
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
79 |
|
|
$ |
285 |
|
|
|
(72 |
)% |
|
$ |
260 |
|
|
$ |
549 |
|
|
|
(53 |
)% |
Capacity revenue |
|
|
100 |
|
|
|
101 |
|
|
|
(1 |
) |
|
|
196 |
|
|
|
211 |
|
|
|
(7 |
) |
Risk management activities |
|
|
51 |
|
|
|
(146 |
) |
|
|
(135 |
) |
|
|
233 |
|
|
|
(184 |
) |
|
|
(227 |
) |
Other revenues |
|
|
7 |
|
|
|
25 |
|
|
|
(72 |
) |
|
|
12 |
|
|
|
49 |
|
|
|
(76 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
237 |
|
|
|
265 |
|
|
|
(11 |
) |
|
|
701 |
|
|
|
625 |
|
|
|
12 |
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management activities) |
|
|
58 |
|
|
|
191 |
|
|
|
(70 |
) |
|
|
175 |
|
|
|
359 |
|
|
|
(51 |
) |
Other operating expenses |
|
|
94 |
|
|
|
91 |
|
|
|
3 |
|
|
|
188 |
|
|
|
184 |
|
|
|
2 |
|
Depreciation and amortization |
|
|
30 |
|
|
|
25 |
|
|
|
20 |
|
|
|
59 |
|
|
|
51 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss) |
|
$ |
55 |
|
|
$ |
(42 |
) |
|
|
(231 |
) |
|
$ |
279 |
|
|
$ |
31 |
|
|
|
N/A |
|
MWh sold (in thousands) |
|
|
1,634 |
|
|
|
3,245 |
|
|
|
(50 |
) |
|
|
4,272 |
|
|
|
6,836 |
|
|
|
(38 |
) |
MWh generated (in thousands) |
|
|
1,634 |
|
|
|
3,245 |
|
|
|
(50 |
) |
|
|
4,272 |
|
|
|
6,836 |
|
|
|
(38 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) (b) |
|
|
39.68 |
|
|
|
107.36 |
|
|
|
(63 |
) |
|
|
48.99 |
|
|
|
96.76 |
|
|
|
(49 |
) |
Cooling Degree Days, or CDDs(a) |
|
|
77 |
|
|
|
165 |
|
|
|
(53 |
) |
|
|
77 |
|
|
|
165 |
|
|
|
(53 |
) |
CDDs 30 year average |
|
|
105 |
|
|
|
105 |
|
|
|
|
|
|
|
105 |
|
|
|
105 |
|
|
|
|
|
Heating Degree Days, or HDDs(a) |
|
|
789 |
|
|
|
771 |
|
|
|
2 |
% |
|
|
3,997 |
|
|
|
3,731 |
|
|
|
7 |
|
HDDs 30 year average |
|
|
841 |
|
|
|
841 |
|
|
|
|
|
|
|
3,935 |
|
|
|
3,968 |
|
|
|
(1 |
)% |
|
|
|
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
|
(b) |
|
MWh sold are shown net of MWh purchased to satisfy certain load contracts in the region. |
Quarterly Results
Operating Income
Operating income increased by $97 million for the three months ended June 30, 2009, compared
to the same period in 2008 due to:
|
|
|
Cost of energy decreased by $133 million due to lower generation and fuel costs. |
|
|
|
|
Operating revenues decreased by $28 million due to unfavorable energy revenues offset
by favorable impact of risk management activities. |
84
Operating Revenues
Operating revenues decreased by $28 million for the three months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Energy revenues decreased by $206 million due to: |
|
o |
|
Energy prices decreased by $83 million reflecting an average 56% decline in
merchant energy prices. This decrease was partially offset by higher net contract
revenues of $24 million driven by lower net costs incurred in meeting obligations under
load serving contracts in the PJM market. |
|
|
o |
|
Generation decreased by $147 million due to a 50% decrease in generation in
2009 compared to 2008, with a 51% decrease in coal generation and a 41% decrease in oil
and gas generation. Coal generation in western New York declined 44%, or 625,000 MWhs,
due to weak power prices that made the plants uneconomic to dispatch. Coal generation
at the Indian River plant declined 65%, or 536,000 MWhs, due to a combination of
weakened demand for power, low gas prices and higher cost of production from compliance
with RGGI and the NOx rules contained in CAIR resulting in increased hours
where the units were uneconomic to dispatch. The Somerset plant experienced similar
weakened demand and low gas prices, with generation down 95%, or 174,000 MWh. The
decline in oil and gas generation is attributable to fewer reliability run hours at the
Connecticut plants and a planned major maintenance outage at the Arthur Kill plant
during February through May 2009. |
|
|
|
Other revenues decreased by $18 million due to $10 million lower allocations of net
physical gas sales and $8 million due to decreased activity in the trading of emission
allowances. |
These decreases were offset by:
|
|
|
Risk management activities gains of $51 million were recorded for the three months
ending June 30, 2009, compared to losses of $146 million during the same period in 2008.
The $51 million gain included $46 million of unrealized mark-to-market losses and $97
million in gains on settled transactions, or financial income, compared to $111 million in
unrealized mark-to-market losses and $35 million in financial losses during the same period
in 2008. The $46 million unrealized loss is the net effect of a $10 million loss from
economic hedge positions, the reversal of $33 million of mark-to-market gains on economic
hedges, the reversal of $9 million of mark-to-market gains on trading activities and $6
million in unrealized mark-to-market gains on trading activity. Gains and losses are
driven by changes in power and gas prices. |
Cost of Energy
|
|
|
Cost of energy decreased by $133 million for the three months ended June 30, 2009,
compared to the same period in 2008, due to: |
|
o |
|
Natural gas and oil costs decreased by $78 million, or 74%, due to 41% lower
generation and 68% lower average natural gas prices. |
|
|
o |
|
Coal costs decreased by $48 million, or 57%, due to lower coal generation of
51% as discussed in energy revenues above. |
|
|
o |
|
Fuel risk management activities decreased by $10 million due to a $12 million
mark-to-market gain on fuel hedges which were discontinued from NPNS to mark-to-market
in the first quarter of 2009 offset by a $2 million loss on settled fuel hedges. |
These decreases were offset by:
|
o |
|
Carbon emissions expense increased by $3 million due to the January 1, 2009
implementation of RGGI and the recognition of carbon compliance cost under this program. |
85
Year-to-Date Results
Operating Income
Operating income increased by $248 million for the six months ended June 30, 2009, compared to
the same period in 2008 due to:
|
|
|
Cost of energy decreased by $184 million due to lower generation and fuel costs. |
|
|
|
|
Operating revenues increased by $76 million due to favorable impact of risk
management activities, offset by lower energy revenues. |
Operating Revenues
Operating revenues increased by $76 million for the six months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Risk management activities gains of $233 million were recorded for the six months
ending June 30, 2009, compared to losses of $184 million during the same period in 2008.
The $233 million gain included $77 million of unrealized mark-to-market gains and $156
million in gains on settled transactions, or financial income, compared to $160 million in
unrealized mark-to-market losses and $24 million in financial losses during the same period
in 2008. The $77 million unrealized gain is the net effect of a $159 million gain from
economic hedge positions and $4 million in unrealized mark-to-market gains on trading
activity offset by the reversal of $63 million of mark-to-market gains on economic hedges
and the reversal of $23 million of mark-to-market gains on trading activities. Gains and
losses are driven by changes in power and gas prices. |
This increase was offset by:
|
|
|
Energy revenues decreased by $289 million due to: |
|
o |
|
Energy prices decreased by $113 million reflecting an average 32% decline in
merchant energy prices. This decrease was partially offset by higher net contract
revenues of $35 million driven by lower net costs incurred in meeting obligations under
load serving contracts in the PJM market. |
|
|
o |
|
Generation decreased by $212 million due to a 38% decrease in generation in
2009 compared to 2008, driven by a 37% decrease in coal generation and a 40% decrease in
oil and gas generation. Coal generation in western New York declined 30% or 921,000
MWhs due to weak power prices that made the plants uneconomic to dispatch. Coal
generation at the Indian River plant declined 48% or 953,000 MWhs due to a combination
of weakened demand for power, low gas prices and higher cost of production from the
introduction of RGGI and NOx rules contained in CAIR resulting in increased
hours where the units were uneconomic to dispatch. The Somerset plant experienced
similar weakened demand and low gas prices, with generation down 78% or 297,000 MWh.
The decline in oil and gas generation is attributable to fewer reliability run hours at
the Connecticut plants and a planned major maintenance outage at the Arthur Kill plant
during February through May of 2009. |
|
|
|
Capacity revenues decreased by $15 million due to: |
|
o |
|
NYISO capacity revenues decreased by $15 million due to unfavorable prices.
The lower capacity market prices are a result of NYISOs reductions in Installed Reserve
Margins and ICAP in-city mitigation rules effective March 2008. |
|
|
o |
|
PJM capacity revenues decreased by $4 million due to lower capacity prices. |
|
|
o |
|
NEPOOL capacity revenues increased by $4 million due to higher volume of
Locational Forward Reserve Market, or LFRM, revenues on the Cos Cob repowered units
which entered service in June 2008. |
|
|
|
Other revenues decreased by $37 million due to $21 million lower allocations of net
physical gas sales and $14 million due to decreased activity in the trading of emission
allowances. |
86
Cost of Energy
|
|
|
Cost of energy decreased by $184 million for the six months ended June 30, 2009,
compared to the same period in 2008, due to: |
|
o |
|
Natural gas and oil costs decreased by $107 million, or 63%, due to 40% lower
generation and 56% lower average natural gas prices. |
|
|
o |
|
Coal costs decreased by $69 million, or 38%, due to lower coal generation of
37% as discussed in energy revenues above. |
|
|
o |
|
Fuel risk management activities decreased by $15 million due to a $20 million
mark-to-market gains on fuel hedges which were discontinued from NPNS to mark-to-market
in the first quarter of 2009 offset by a $5 million loss on settled fuel hedges. |
These decreases were offset by:
|
o |
|
Carbon emissions expense increased by $8 million due to the January 1, 2009
implementation of RGGI and the recognition of carbon compliance cost under this program. |
87
South Central Region
For
a discussion of the business profile of the South Central region, see
pages 30-31 of NRG
Energy, Inc.s 2008 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) |
|
2009 |
|
|
2008 |
|
|
Change |
% |
|
2009 |
|
|
2008 |
|
|
Change |
% |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
81 |
|
|
$ |
130 |
|
|
|
(38 |
)% |
|
$ |
177 |
|
|
$ |
230 |
|
|
|
(23 |
)% |
Capacity revenue |
|
|
65 |
|
|
|
58 |
|
|
|
12 |
|
|
|
133 |
|
|
|
115 |
|
|
|
16 |
|
Risk management activities |
|
|
(12 |
) |
|
|
(23 |
) |
|
|
(48 |
) |
|
|
(19 |
) |
|
|
(10 |
) |
|
|
90 |
|
Contract amortization |
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
11 |
|
|
|
11 |
|
|
|
|
|
Other revenues |
|
|
|
|
|
|
2 |
|
|
|
100 |
|
|
|
(1 |
) |
|
|
5 |
|
|
|
(120 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
139 |
|
|
|
172 |
|
|
|
(19 |
) |
|
|
301 |
|
|
|
351 |
|
|
|
(14 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management activities) |
|
|
92 |
|
|
|
116 |
|
|
|
(21 |
) |
|
|
202 |
|
|
|
204 |
|
|
|
(1 |
) |
Other operating expenses |
|
|
27 |
|
|
|
33 |
|
|
|
(18 |
) |
|
|
49 |
|
|
|
55 |
|
|
|
(11 |
) |
Depreciation and amortization |
|
|
17 |
|
|
|
17 |
|
|
|
|
|
|
|
34 |
|
|
|
34 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
3 |
|
|
$ |
6 |
|
|
|
(50 |
) |
|
$ |
16 |
|
|
$ |
58 |
|
|
|
(72 |
) |
MWh sold (in thousands) |
|
|
2,792 |
|
|
|
2,977 |
|
|
|
(6 |
) |
|
|
5,961 |
|
|
|
6,065 |
|
|
|
(2 |
) |
MWh generated (in thousands) |
|
|
2,386 |
|
|
|
2,616 |
|
|
|
(9 |
) |
|
|
5,093 |
|
|
|
5,641 |
|
|
|
(10 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
32.21 |
|
|
|
84.82 |
|
|
|
(62 |
) |
|
|
34.75 |
|
|
|
76.28 |
|
|
|
(54 |
) |
Cooling Degree Days, or CDDs(a) |
|
|
582 |
|
|
|
546 |
|
|
|
7 |
|
|
|
588 |
|
|
|
550 |
|
|
|
7 |
|
CDDs 30 year average |
|
|
458 |
|
|
|
458 |
|
|
|
|
|
|
|
489 |
|
|
|
489 |
|
|
|
|
|
Heating Degree Days, or HDDs(a) |
|
|
289 |
|
|
|
319 |
|
|
|
(9 |
)% |
|
|
2,094 |
|
|
|
2,223 |
|
|
|
(6 |
) |
HDD 30 year average |
|
|
299 |
|
|
|
299 |
|
|
|
|
|
|
|
2,194 |
|
|
|
2,213 |
|
|
|
(1 |
)% |
|
|
|
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD represents
the number of degrees that the mean temperature for a particular day is above 65 degrees
Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period
of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly Results
Operating income decreased by $3 million for the three months ended June 30, 2009, compared to
the same period in 2008, primarily due to:
|
|
|
Operating revenues decreased by $33 million due to a decreases in energy revenue
offset by increases in risk management activities and capacity revenue. |
|
|
|
|
Cost of energy decreased by $24 million due to lower purchased energy costs
reflecting lower fuel and energy prices and lower transmission costs, offset by fuel risk
management activities. |
|
|
|
|
Other Operating Expenses decreased by $6 million because of lower operations and
maintenance and general and administrative costs. |
88
Operating Revenues
Operating revenues decreased by $33 million for the three months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Energy revenues decreased by $49 million due to a $27 million decline in contract
revenue coupled with a decrease of $22 million in merchant energy revenues. Total MWh
sales to the regions contract customers were down 12% while the average realized price on
contract energy sales was $22.98 per MWh in 2009 compared to $30.23 per MWh in 2008. The
decline in contract energy price was driven by a $9 million decrease in fuel cost pass
through from the cooperatives. Also contributing to the decline in contract revenue was $18
million due to the expiration of a contract with a regional utility. The expiration of the
contract allowed more energy to be sold into the merchant market, but at lower average
prices resulting in a $22 million decline in revenue. Megawatt hours sold to the merchant
market increased by 43% as increased use of the regions tolled facility provided
additional energy to the merchant market while prices fell by 61%. |
|
|
|
|
Risk Management Activities losses of $12 million were recognized during the second
quarter 2009 compared to losses of $23 million recognized during the same period in 2008.
The $12 million loss included $10 million in unrealized losses and $2 million in realized
losses compared to $18 million in unrealized losses and $4 million in realized losses for
the same period in 2008. The $10 million unrealized loss was the net effect of a $2
million unrealized mark-to-market gain from trading activity and the reversal of $12
million of mark-to-market gains on trading activity. |
|
|
|
|
Capacity revenues capacity revenue increased by $7 million due to a $9 million
increase from a new capacity agreement and a $2 million increase in capacity revenue from
the regions Rockford plants which dispatch into the PJM market, offset by a decrease in
contract capacity of $4 million. |
Cost of Energy
Cost of energy decreased by $24 million for the three months ended June 30, 2009, compared to
the same period in 2008, due to:
|
|
|
Purchased energy Total purchased energy and capacity decreased by $30 million.
Purchased energy costs decreased by $29 million even though MWhs purchased increased by 8%,
reflecting lower fuel costs associated with energy from the regions tolled facility and
lower costs of market purchases. |
|
|
|
|
Transmission expense decreased by $3 million due to outages on transmission lines in
neighboring systems limiting their use to move power and incur cost. |
These decreases were offset by:
|
|
|
Fuel risk management activities increased by $8 million. In the first quarter 2009,
all NPNS coal contracts were discontinued and
reclassified into mark-to-market accounting,
which resulted in unrealized losses of $10 million on coal commodity hedging activities.
Hedging activities related to fuel transportation resulted in $4 million of unrealized
gains and $2 million of realized losses. |
Other Operating Expenses
Other operating expense decreased by $6 million for the three months ended June 30, 2009,
compared to the same period in 2008, due to:
|
|
|
Operations and Maintenance expense decreased by $4 million because the spring outage
in 2009 was performed on a jointly owned unit, while 2008 outages were on NRG-owned units. |
|
|
|
|
General and Administrative expense declined by $2 million due to lower corporate
allocations as such costs are spread over a wider base following the Reliant Energy acquisition. |
89
Year-to-Date Results
Operating income decreased by $42 million for the six months ended June 30, 2009, compared to
the same period in 2008, primarily due to:
|
|
|
Operating revenues decreased by $50 million due to decreases in energy revenue, risk
management activities, and other revenue. These decreases were offset by an increase in
capacity revenue |
|
|
|
|
Cost of energy decreased by $2 million due to lower purchased energy costs reflecting
lower fuel and energy prices, lower transmission expense and lower coal cost offset by
higher expenses associated with fuel risk management activities. |
|
|
|
|
Other Operating Expenses decreased by $6 million because of lower operations and
maintenance and general and administrative costs. |
Operating Revenues
Operating revenues decreased by $50 million for the six months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Energy revenues decreased by $53 million due to a $42 million decline in contract
revenue coupled with an $11 million decrease in merchant energy revenues. Contract
customer sales volumes were down 11% while the average realized price on contract energy
sales was $23.17 per MWh in 2009 compared to $28.72 per MWh in 2008. The decline in
contract energy price was driven by a $7 million decrease in fuel cost pass through to the
cooperatives. Also contributing to the decline in contract revenue was $31 million due to
the expiration of a contract with a regional utility. The expiration of the contract
allowed more energy to be sold into the merchant market, but at lower average prices
resulting in an $11 million decline in revenue. Megawatt hours sold to the merchant market
increased by 51%, while prices fell by 42%. Increased use of the regions tolled facility
provided additional energy to the merchant market. |
|
|
|
|
Risk Management Activities losses of $19 million were recognized during the second
half of 2009 compared to losses of $10 million recognized during the same period in 2008.
The $19 million loss included $30 million in unrealized losses offset by realized gains of
$11 million compared to $10 million in unrealized losses for the same period in 2008. The
$30 million unrealized loss was the net effect of a $8 million unrealized mark-to-market
gain from trading activity and the reversal of $38 million of mark-to-market losses on
trading activity. |
|
|
|
|
Other Revenue declined by $6 million due to $3 million in lower physical coal and
natural gas sales and $3 million in reduced intercompany emission allowance sales. |
These decreases were offset by:
|
|
|
Capacity revenues increased by $18 million due to a $17 million increase from a new
capacity agreement with a regional utility and a $5 million increase in capacity revenue
from the regions Rockford plants which dispatch into the PJM market, offset by lower
contract capacity revenue of $4 million. |
Cost of Energy
Cost of energy decreased by $2 million for the six months ended June 30, 2009, compared to the
same period in 2008, due to:
|
|
|
Purchased energy decreased by $16 million while purchased capacity increased by $3
million. The lower purchased energy reflects lower fuel costs
associated with the regions
tolled facility and lower market energy prices. The energy declines were offset by higher
capacity payments of $3 million on tolled facilities. |
|
|
|
|
Transmission expense decreased by $4 million due to outages on transmission lines in
neighboring systems limiting their use to move power and incur costs. |
|
|
|
|
Coal costs decreased by $2 million due to a 10% reduction in coal generation and a
decrease in fuel transportation surcharges offset by a contractual increase in rail
contract base rates and higher coal commodity costs. |
90
These decreases were offset by:
|
|
|
Fuel risk management activities increased by $16 million in the first quarter of
2009, all normal purchase and sale coal contracts were discontinued and
reclassified into mark-to-market accounting, which resulted in unrealized losses of $7 million on coal commodity hedging
activities. Hedging activities related to fuel transportation resulted in $3 million of
unrealized losses and $6 million of realized losses. |
Other Operating Expenses
Other operating expense decreased by $6 million for the three months ended June 30, 2009,
compared to the same period in 2008, due to:
|
|
|
Operations and Maintenance expense decreased by $4 million because the spring outage
in 2009 was performed on a jointly owned unit, while 2008 outages were on NRG-owned units. |
|
|
|
|
General and Administrative expense declined by $2 million due to lower corporate
allocations as such costs are spread over a wider base following the Reliant Energy
acquisition. |
91
West Region
For a discussion of the business profile of the West region, see pages 31-33 of NRG Energy,
Inc.s 2008 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) |
|
2009 |
|
|
2008 |
|
|
Change |
% |
|
2009 |
|
|
2008 |
|
|
Change |
% |
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
5 |
|
|
$ |
13 |
|
|
|
(62 |
)% |
|
$ |
7 |
|
|
$ |
13 |
|
|
|
(46 |
)% |
Capacity revenue |
|
|
31 |
|
|
|
31 |
|
|
|
|
|
|
|
60 |
|
|
|
69 |
|
|
|
(13 |
) |
Risk management activities |
|
|
6 |
|
|
|
|
|
|
|
N/A |
|
|
|
3 |
|
|
|
|
|
|
|
N/A |
|
Other revenues |
|
|
|
|
|
|
5 |
|
|
|
(100 |
) |
|
|
|
|
|
|
5 |
|
|
|
(100 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
42 |
|
|
|
49 |
|
|
|
(14 |
) |
|
|
70 |
|
|
|
87 |
|
|
|
(20 |
) |
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy (including risk management activities) |
|
|
3 |
|
|
|
12 |
|
|
|
(75 |
) |
|
|
7 |
|
|
|
14 |
|
|
|
(50 |
) |
Other operating expenses |
|
|
21 |
|
|
|
20 |
|
|
|
5 |
|
|
|
46 |
|
|
|
38 |
|
|
|
21 |
|
Depreciation and amortization |
|
|
2 |
|
|
|
3 |
|
|
|
(33 |
) |
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
16 |
|
|
$ |
14 |
|
|
|
14 |
|
|
$ |
13 |
|
|
$ |
31 |
|
|
|
(58 |
) |
MWh sold (in thousands) |
|
|
182 |
|
|
|
327 |
|
|
|
(44 |
) |
|
|
352 |
|
|
|
468 |
|
|
|
(25 |
) |
MWh generated (in thousands) |
|
|
182 |
|
|
|
327 |
|
|
|
(44 |
) |
|
|
352 |
|
|
|
468 |
|
|
|
(25 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
33.14 |
|
|
|
97.54 |
|
|
|
(66 |
) |
|
|
36.80 |
|
|
|
88.92 |
|
|
|
(59 |
) |
Cooling Degree Days, or CDDs(a) |
|
|
144 |
|
|
|
205 |
|
|
|
(30 |
) |
|
|
144 |
|
|
|
205 |
|
|
|
(30 |
) |
CDDs 30 year average |
|
|
150 |
|
|
|
150 |
|
|
|
|
|
|
|
157 |
|
|
|
157 |
|
|
|
|
|
Heating Degree Days, or HDDs(a) |
|
|
470 |
|
|
|
576 |
|
|
|
(18 |
)% |
|
|
1,880 |
|
|
|
2,096 |
|
|
|
(10 |
) |
HDDs 30 year average |
|
|
556 |
|
|
|
556 |
|
|
|
|
|
|
|
1,975 |
|
|
|
1,990 |
|
|
|
(1 |
)% |
|
|
|
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD represents
the number of degrees that the mean temperature for a particular day is above 65 degrees
Fahrenheit in each region. An HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period
of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly Results
Operating Income
Operating income increased by $2 million for the three months ended June 30, 2009, compared to
the same period in 2008, due to:
|
|
|
Operating revenues decreased by $7 million due to decreases in capacity revenue,
energy revenue, and other revenues. These decreases were offset by a gain on risk
management activities. Lower demand and lower merchant power prices contributed to the
decrease. |
|
|
|
|
Cost of energy decreased by $9 million due to lower generation and lower natural gas
prices. |
Operating Revenues
Operating revenues decreased by $7 million for the three months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Energy revenues
decreased by $8 million primarily due to a 33% decline in merchant
energy prices and a 31% decrease in generation in 2009 compared to 2008. |
|
|
|
|
Other revenue decreased by $5 million due to a reduced allocation of emission
allowances sales. |
|
|
|
|
Risk Management Activities unrealized mark-to-market gains of $6 million on asset
backed hedges were recognized during the second quarter of 2009. There was no asset backed
hedging activity in 2008. |
92
Cost of Energy
Cost of energy decreased by $9 million for the three months ended June 30, 2009, compared to
the same period in 2008, due to a 67% decrease in average natural gas prices per MMBtu and an 11%
decrease in natural gas consumption.
Year-to-Date Results
Operating income decreased by $18 million for the six months ended June 30, 2009, compared to
the same period in 2008, due to:
|
|
|
Operating revenues decreased by $17 million due to decreases in capacity revenue,
energy revenue, and other revenues. These decreases were offset by a gain on risk
management activities. Lower demand and lower merchant power prices contributed to the
decrease. |
|
|
|
|
Cost of energy and other operating expenses increased by $1 million due to lower
generation and lower natural gas prices offset by higher major maintenance expense. |
Operating Revenues
Operating revenues decreased by $17 million for the six months ended June 30, 2009, compared
to the same period in 2008, due to:
|
|
|
Capacity revenues decreased by $9 million primarily due to expiration of a two year
tolling agreement at the El Segundo facility in April 2008, which was replaced by resource
adequacy and capacity contracts at lower prices. |
|
|
|
|
Energy revenues decreased by $6 million primarily due to a 27% decline in merchant
energy prices and a 15% decrease in generation in 2009 compared to 2008. |
|
|
|
|
Other revenue decreased by $5 million primarily due to a reduced allocation of
emission allowances sales. |
|
|
|
|
Risk Management Activities gain of $3 million was recognized during the first half of
2009 compared to no gain during the same period in 2008. The $3 million gain included $6
million in unrealized mark-to-market gains offset by realized losses of $3 million for
natural gas hedges. |
Cost of Energy and Other Operating Expenses
Cost of energy and other operating expenses increased by $1 million for the six months ended
June 30, 2009, compared to the same period in 2008, due to:
|
|
|
Cost of energy decreased by $7 million due to a 66% decline in average natural gas
prices per MMBtu and a 17% decrease in natural gas consumption. This
decrease was partially
offset by a $3 million increase in fuel oil expense resulting from a write-down to market
of fuel oil inventory no longer used in the production of energy. |
|
|
|
|
Other operating expenses increased by $8 million due to higher major maintenance
expense associated with an El Segundo major overhaul and major maintenance at Long Beach. |
93
Liquidity and Capital Resources
Liquidity Position
As of June 30, 2009, and December 31, 2008, NRGs liquidity, excluding collateral received,
was approximately $4.0 billion and $3.4 billion, respectively, comprised of the following:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
(In millions) |
|
2009 |
|
2008 |
|
Cash and cash equivalents |
|
$ |
2,282 |
|
|
|
$ 1,494 |
|
Funds deposited by counterparties |
|
|
468 |
|
|
|
754 |
|
Restricted cash |
|
|
19 |
|
|
|
16 |
|
|
Total cash |
|
|
2,769 |
|
|
|
2,264 |
|
Synthetic Letter of Credit Facility availability |
|
|
784 |
|
|
|
860 |
|
Revolver Credit Facility availability |
|
|
941 |
|
|
|
1,000 |
|
|
Total liquidity |
|
|
4,494 |
|
|
|
4,124 |
|
Less: Funds deposited as collateral by hedge counterparties |
|
|
(468 |
) |
|
|
(760 |
) |
|
Total liquidity, excluding collateral received |
|
$ |
4,026 |
|
|
|
$ 3,364 |
|
|
For the six months ended June 30, 2009, total liquidity, excluding collateral received,
increased by $662 million due to a higher cash balance of $788 million and reduced funds deposited
as collateral by hedged counterparties of $292 million. These increases were partially offset by a
lower funds deposited of $286 million, as well as decreased availability of the synthetic letter of
credit and the revolving credit facility of $76 million and $59 million, respectively. Changes in
cash balances are further discussed below under the heading Cash Flow Discussion. Cash and cash
equivalents and funds deposited by counterparties at June 30, 2009, 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 consists of cash collateral received from
hedge counterparties in support of energy risk management activities, and it is the Companys
intention as of June 30, 2009, to limit the use of these funds. The decrease in these amounts from
December 31, 2008 was due to cash collateral moved from NRG to Merrill Lynch in connection with
novations under the CSRA (see Note 3 Business Acquisition), offset by an increase of
in-the-money positions as a result of decreasing forward prices. Depending on market fluctuation
and the settlement of the underlying contracts, the Company will refund this collateral to the
counterparties pursuant to the terms and conditions of the underlying trades. The Companys
balance sheet reflects a liability for cash collateral received within current liabilities.
Management believes that the Companys liquidity position and cash flows from operations will
be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRGs
preferred shareholders and other liquidity commitments. Management continues to regularly monitor
the Companys ability to finance the needs of its operating, financing and investing activity in a
manner consistent with its intention to maintain a net debt to capital ratio in the range of
45-60%.
SOURCES OF FUNDS
The principal sources of liquidity for NRGs future operating and capital expenditures are
expected to be derived from new and existing financing arrangements, asset sales, existing cash on
hand and cash flows from operations.
Financing Arrangements
Senior Credit Facility
As of June 30, 2009, NRG had a Senior Credit Facility which is comprised of a senior first
priority secured term loan, or the Term Loan Facility, a $1.0 billion senior first priority secured
revolving credit facility, or the Revolving Credit Facility, and a $1.3 billion senior first
priority secured synthetic letter of credit facility, or the Synthetic Letter of Credit Facility.
The Senior Credit Facility was last amended on June 8, 2007. On July 23, 2009, Moodys upgraded
the Senior Credit Facility to Baa3 due to the underlying value that the capital structure provides
to secured creditors. As of June 30, 2009, NRG had issued $516 million of letters of credit under
the Synthetic Letter of Credit Facility, leaving $784 million available for future issuances.
Under the Revolving Credit Facility, as of June 30, 2009, NRG had issued a letter of credit of $59
million which supports the tax exempt bonds issued by Dunkirk Power LLC as described in Note 7,
LongTerm Debt.
94
2019 Senior Notes
On June 5, 2009, NRG completed the issuance of $700 million aggregate principal amount of 8.5%
Senior Notes due 2019, or 2019 Senior Notes as described in Note 7, LongTerm Debt. The net
proceeds of $678 million are intended to be used to facilitate the early termination of NRGs
obligations pursuant to the CSRA, anticipated in the late third or early fourth quarter 2009.
Prior to the termination, or in the event NRG does not reach agreement on acceptable terms with
either Merrill Lynch or its counterparties, the net proceeds will be available for general
corporate purposes.
Merrill Lynch Credit Sleeve Facility
Merrill Lynch, through the CSRA with NRG, has provided the Company as of June 30, 2009, with
$630 million in financial support that significantly reduces the liquidity requirements and
substantially eliminates collateral postings for Reliant Energy. See discussion in Note 3,
Business Acquisition, regarding the CSRA as a result of the acquisition of Reliant Energy on May 1,
2009.
TANE Facility
On February 24, 2009, NINA executed an 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, 2009, no amounts had been borrowed under the TANE
Facility. NINA will be required to repay all outstanding amounts associated with its existing $20
million revolving credit facility before borrowing under the TANE Facility.
Dunkirk Power LLC Tax-Exempt Bonds
On April 15, 2009, NRG executed a $59 million tax-exempt bond financing through its wholly
owned subsidiary, Dunkirk Power LLC. The bonds were issued by the County of Chautauqua Industrial
Development Agency and will be applied towards construction of emission control equipment on the
Dunkirk Generating Station in Dunkirk, NY. The bonds initially bear weekly interest based on the
SIFMA rate, have a maturity date of April 1, 2042, and are enhanced by a letter of credit under the
Companys Revolving Credit Facility covering amounts drawn on the facility. The proceeds received
through June 30, 2009, were $34 million with the remaining balance being released over time as
construction costs are paid.
GenConn Energy LLC related financings
On April 27, 2009, a wholly owned subsidiary of NRG closed on an equity bridge loan facility,
or EBL, in the amount of $121.5 million from a syndicate of banks. The purpose of the EBL is to
fund the Companys proportionate share of the project construction costs required to be contributed
into GenConn Energy LLC, or GenConn, a 50% equity method investment of the Company. The EBL, which
is fully collateralized with a letter of credit issued under the Companys Synthetic Letter of
Credit Facility, covering amounts drawn on the facility, will bear interest at a rate of LIBOR plus
2% on drawn amounts. The EBL will mature on the earlier of the commercial operations date of the
Middletown project or July 26, 2011. The EBL also requires mandatory prepayment of the portion of
the loan utilized to pay costs of the Devon project, of approximately $56 million, on the earlier
of Devons commercial operations date or January 27, 2011. The proceeds of the EBL received
through June 30, 2009 were $70 million and the remaining amounts will be drawn as necessary to fund
construction costs.
In April 2009, GenConn secured financing for 50% of the Devon and Middletown project
construction costs through a 7-year term loan facility, and also entered into a 5-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.
95
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, 2009, and July 23, 2009, 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 forecasted baseload capacity under the first and
second lien structure as of July 23, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales Secured by First and Second Lien Structure (a) |
|
2009 |
|
2010 |
|
2011 |
|
2012 |
|
2013 |
|
|
|
|
4,851 |
|
|
|
5,029 |
|
|
|
3,711 |
|
|
|
2,066 |
|
|
|
801 |
|
As a percentage of total forecasted baseload capacity (c)
|
|
|
70% |
|
|
|
74% |
|
|
|
55% |
|
|
|
31% |
|
|
|
12% |
|
|
|
|
|
(a) |
|
Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. |
(b) |
|
2009 MW value consists of August through December positions only. |
(c) |
|
Forecasted baseload capacity under the first and second lien structure represents 80% of the total Companys baseload assets. |
Asset Sales Disposition of MIBRAG Investment
MIBRAG On June 10, 2009, NRG completed the sale of its 50% ownership interest in Mibrag
B.V. to a consortium of Severočeské doly Chomutov, a member of the CEZ Group, and J&T Group.
Mibrag B.V.s principal holding is MIBRAG, which is jointly owned by NRG and URS Corporation. As
part of the transaction, URS Corporation also entered into an agreement to sell its 50% stake in
MIBRAG.
For its share, NRG received EUR 203 million ($284 million at an exchange rate of 1.40
US$/EUR), net of transaction costs. During the three and six months ended June 30, 2009, NRG
recognized a pre-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. The foreign currency forward
contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200 million in exchange
for $255 million on June 15, 2009. 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
(loss)/income, net.
96
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, 2009, commercial
operations had total cash collateral outstanding of $214 million, and $292 million outstanding in
letters of credit to third parties primarily to support its economic hedging activities. As of
June 30, 2009, total collateral held from counterparties was $468 million and $11 million of
letters of credit. These collateral amounts do not include collateral postings by Merrill Lynch
under the CSRA.
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 2009, NRG made and the lenders accepted a repayment of
approximately $197 million for the mandatory annual offer relating to 2008.
As of June 30, 2009, NRG had issued approximately $5.4 billion in aggregate principal amount
of unsecured high yield notes or Senior Notes, had approximately $2.4 billion in principal amount
outstanding under the Term Loan Facility, and had issued $516 million of letters of credit under
the Companys $1.3 billion Synthetic Letter of Credit Facility and $59 million of letters of credit
under the Companys Revolving Credit Facility. The Revolving Credit Facility matures on February
2, 2011, and the Synthetic Letter of Credit Facility matures on February 1, 2013.
Capital Expenditures
For the six months ended June 30, 2009, the Companys capital expenditures, including
accruals, were approximately $366 million, of which $173 million was related to RepoweringNRG
projects. The following table summarizes the Companys capital expenditures for the six months
ended June 30, 2009, and the estimated capital expenditure and repowering investments forecast for
the remainder of 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Maintenance |
|
Environmental |
|
Repowering |
|
Total |
|
Northeast |
|
$ |
17 |
|
|
$ |
86 |
|
|
$ |
5 |
|
|
$ |
108 |
|
Texas |
|
|
78 |
|
|
|
|
|
|
|
89 |
|
|
|
167 |
|
South Central |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
West |
|
|
3 |
|
|
|
|
|
|
|
1 |
|
|
|
4 |
|
Reliant Energy |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Nuclear development |
|
|
|
|
|
|
|
|
|
|
78 |
|
|
|
78 |
|
Other |
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
5 |
|
|
Total |
|
$ |
107 |
|
|
$ |
86 |
|
|
$ |
173 |
|
|
$ |
366 |
|
|
Estimated capital expenditures for the remainder of 2009 |
|
$ |
184 |
|
|
$ |
149 |
|
|
$ |
178 |
|
|
$ |
511 |
|
|
RepoweringNRG capital expenditures and investments RepoweringNRG project capital
expenditures consisted of approximately $62 million related to the Companys Langford wind farm
project which is currently under construction. In addition, the Companys RepoweringNRG capital
expenditures included $27 million for the construction of Cedar Bayou Unit 4 in Texas and $78
million for the development of STP Units 3 and 4 in Texas.
The Companys estimated repowering capital expenditures for the remainder of 2009 are expected
to be approximately $178 million. Of this amount, $115 million is estimated for STP Units 3 and 4
without giving effect to any partner contributions or potential equity sell down and approximately
$47 million to complete the construction of the Langford wind farm.
97
Major maintenance and environmental capital expenditures The Companys baghouse projects at
western New York facilities resulted in environmental capital expenditures of $79 million for the
six months ended June 30, 2009. In addition, the Companys
maintenance capital expenditures were
$107 million of which $78 million was primarily related to the Texas regions baseload assets which
included approximately $25 million in nuclear fuel expenditures related STP units 1 and 2.
NRG anticipates funding its maintenance capital projects primarily with funds generated from
operating activities. In addition, on April 15, 2009, the Company executed a $59 million
tax-exempt bond financing through its wholly owned subsidiary, Dunkirk Power LLC, with the bonds
issued by the County of Chautauqua Industrial Development Agency. These funds are expected to fund
environmental capital expenditures at the Dunkirk Generating facility.
Loans to affiliates The Company had funded approximately $48 million in interest bearing
loans to GenConn Energy LLC, a 50/50 joint venture vehicle of NRG and the United Illuminating
Company as part of the Devon and Middletown plant repowering projects prior to the closing of the
EBL and GenConn Facility. At the time of closing, $39 million was repaid with proceeds from the
EBL financing. Except for a balance of less than $1 million that will be repaid during the third
quarter of 2009, this loan was repaid during the second quarter 2009. Subsequent to the financing,
the equity portion of construction costs for GenConn are funded through the EBL of NRG Connecticut
Peaking and United Illuminating. These funds are made available to GenConn through convertible
interest bearing promissory notes that convert upon repayment of the EBL loans by NRG and UI. As
of June 30, 2009, there was $70 million outstanding under the loan from NRG.
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that environmental capital
expenditures to be incurred during the remainder of 2009 through 2013 to meet NRGs environmental
commitments will be approximately $1.1 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, 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. This estimate reflects anticipated
schedules and controls related to CAIR, 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.
Capital Allocation
In addition to the aforementioned planned investments in maintenance and environmental capital
expenditures and RepoweringNRG in 2009, and the 2009 repayment of Term Loan Facility debt to the
first lien lenders, the Companys Capital Allocation Plan includes the completion of the 2008
Capital Allocation Plan with the planned purchase of $30 million of common stock as well as the
purchase of an additional $300 million in common stock under the previously announced 2009 Capital
Allocation Plan, with such purchases to be made from time to time and subject to market conditions
and other factors, including as permitted by U.S. securities laws. On July 8, 2009, the Company
announced an increase in planned purchases of $170 million under the 2009 Capital Allocation plan.
NRG intends to complete the $500 million of share repurchases by the end of 2009, subject to market
prices and as permitted by securities laws and other requirements.
Preferred Stock Dividend Payments
For
the six months ended June 30, 2009, NRG paid approximately $6 million, $9 million, and $6
million in dividend payments to holders of the Companys 5.75%, 4%, and 3.625% Preferred Stock,
respectively. On March 16, 2009, the outstanding shares of the 5.75% Preferred Stock converted
into common stock and, as a result, there will be no further dividends paid with respect to this
series of preferred stock.
98
CSF Share Lending Arrangement
On February 20, 2009, CSF I and CSF II, wholly-owned unrestricted subsidiaries of the Company,
entered into Share Lending Agreements with affiliates of Credit Suisse Group, or CS, relating to
the shares of NRG common stock currently held by CSF I and II in connection with the CSF I and CSF
II issued notes and preferred interests agreements, or CSF Debt, originally entered into during the
third quarter 2006, by and between CSF I and II and affiliates of CS. The Company entered into
Share Lending Agreements due to the current lack of liquidity in the stock borrow market for NRG
shares and in order to maintain the intended economic benefits of the CSF Debt agreements. As of
June 30, 2009, CSF I and II have lent affiliates of CS 12,000,000 shares of the 21,970,903 shares
of NRG common stock held by CSF I and II. The Share Lending Agreements permit affiliates of CS to
borrow up to the total number of shares of NRG common stock held by CSF I and II.
Benefit Plans Obligations
As of June 30, 2009, NRG contributed $14 million towards its three defined benefit pension
plans to meet the Companys 2009 benefit obligation. The Companys expected contribution to the
plans is $16 million during the remainder of 2009. The total 2009 planned contribution of $30
million is a decrease of $30 million from the expected contributions as disclosed in Part II, Item
7 Managements Discussion and Analysis of Financial Condition and Results of Operations,
Liquidity and Capital Resources, in the Companys Annual Report on Form 10-K for the year ended
December 31, 2008. This decrease in the 2009 expected contributions is due to the adoption by the
Company in March 2009 of the new funding method options now available. The new methods were made
allowable under new IRS guidance on the application of recent Congressional legislation on funding
requirements.
Reliant Energy Customer Deposits
Changes in the Texas law will require customer deposits and advance payments to be held in a
segregated cash account on or before May 21, 2010. The amount of deposits subject to segregation
at June 30, 2009, was approximately $58 million.
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, |
|
2009 |
|
2008 |
|
Change |
|
Net cash provided by operating activities |
|
$ |
722 |
|
|
$ |
436 |
|
|
$ |
286 |
|
Net cash used by investing activities |
|
|
(500 |
) |
|
|
(122 |
) |
|
|
(378 |
) |
Net cash provided by/(used by) financing activities |
|
|
565 |
|
|
|
(233 |
) |
|
|
798 |
|
|
Net Cash Provided By Operating Activities
For the six months ended June 30, 2009, net cash provided by operating activities increased by
$286 million compared to the same period in 2008. The difference was due to:
|
|
|
Collateral deposits and
option premiums In 2009, the changes in both collateral
deposits and option premiums paid and collected increased cash from
operations by $232 million
due to close out of commercial trade positions and lower commodity prices. |
|
|
|
Working capital
In 2009, the cash from working capital items increased by $54
million due to various changes in assets and liabilities. |
99
Net Cash Used By Investing Activities
For the six months ended June 30, 2009, net cash used in investing activities was $378 million
higher than the same period in 2008. This was due to:
|
|
|
Acquisition of Reliant Energy During the six months ended June 30, 2009, the Company
paid $345 million, net of cash acquired of $6 million, towards its acquisition of Reliant
Energy. This amount was comprised of approximately $288 million paid at closing, and $63
million paid on June 11, 2009 as an initial remittance of the approximately $82 million of
acquired working capital to be remitted to RRI over the 8 months following the closing. |
|
|
|
Trading of emission allowances Net purchases and sales of emission allowances resulted
in a decrease in cash of $94 million for 2009 as compared to 2008. |
|
|
|
Proceeds from sale of equity method investment and discontinued operations
Net proceeds from investing activities increased by $55 million in 2009 as compared to 2008 due to the sale of MIBRAG in June 2009
for net proceeds of $284 and the sale of ITISA for proceeds, net of divested cash, of $229 million in the first half of 2008.
|
Net Cash Used By Financing Activities
For the six months ended June 30, 2009, net cash provided by financing activities increased by
$798 million compared to 2008, due to:
|
|
|
Issuance of debt 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. During 2008, the Company received $10 million in proceeds
from borrowings. |
|
|
|
|
Deferred financing costs
During 2009, the Company paid deferred financing costs of
$15 million related to the Reliant Energy CSRA, $10 million related to the 2019 Senior Notes, and $2 million related to the Dunkirk bonds and
the Reliant Energy working capital facility. |
|
|
|
Term Loan Facility debt
payment In 2009, the Company paid down $213 million of its
Term Loan Facility, including the payment of excess cash flow, as discussed above under
Debt Service Obligations. The Company paid down $158 million of its Term Loan Facility
during 2008 which resulted in a net cash decrease of $55 million for the six months ended
2009 as compared to the same period in 2008. |
|
|
|
Share repurchase During 2009, the Company did not repurchase any common stock during
the first half in 2009, compared to $55 million for 2008. |
|
|
|
Payment of financing element of acquired derivatives In 2009, the Company paid a net of $22
million for the settlement of gas swaps related to Reliant Energy and Texas Genco compared to a payment of $28 million for 2008 related to Texas Genco for an increase in cash of $6 million. |
|
|
|
Exercise of stock options The Company received proceeds of $8 million from the
exercise of stock options for the first half of 2008. |
100
NOLs, Deferred Tax Assets and FIN 48 Implications
As of June 30, 2009, the Company had generated total domestic pre-tax book income of $936
million and foreign continuing pre-tax book income of $142 million. In addition, NRG has
cumulative foreign NOL carryforwards of $276 million, of which $78 million will expire starting in
2011 through 2018 and of which $198 million do not have an expiration date.
In addition to these amounts, the Company has net operating losses for tax return purposes but have been
classified as capital loss carryforwards for financial statements purposes and for which a full
valuation allowance has been established. As a result of the Companys tax position, and based on
current forecasts, the Company anticipates income tax payments of up to $100 million during 2009.
However, as the position remains uncertain, the Company has recorded a non-current tax liability of $463 million and may accrue
the remaining balance as an increase to non-current liabilities until final resolution with the
related taxing authority. The $463 million non-current tax liability for unrecognized tax benefits
is due to taxable earnings for which there are no NOLs available to offset for financial statement
purposes.
The Company continues to be under examination by the Internal Revenue Service.
New and On-going Company Initiatives
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 2009 FORNRG goal is a 20 basis point improvement in ROIC which corresponds to
approximately $30 million in cash flow. As of June 30, 2009, the Company has exceeded its 2009
goal with a 22.9 basis point improvement in ROIC, which is equivalent to approximately $34 million
in cash flows. The performance of the plants coupled with strategic projects undertaken by
corporate functions is evidenced in the overall corporate performance.
Nuclear Innovation North America
NINA is an NRG subsidiary focused on marketing, siting, developing, financing and investing in
new advanced design nuclear projects in select markets across North America, including the planned
STP Units 3 and 4 that NRG is developing on a 50/50 basis with City of San Antonios agent City
Public Service Board of San Antonio, or CPS Energy, at the STP nuclear power station site. TANE, a
wholly owned subsidiary of Toshiba Corporation, owns a non-controlling interest in NINA. On May 1,
2009, TANE made the second of its scheduled $50 million contributions to NINA.
The Department of Energy, or DOE, has confirmed that the South Texas Project expansion, or STP
Units 3 and 4, is one of four projects selected for further due diligence and negotiation leading
to a conditional commitment under the DOE loan guarantee program. NINA will now begin discussions
with the DOE on the specific terms and amount to be loaned for the project. NRG believes DOE loan
guarantee support is critical to new nuclear development projects. In addition to U.S. loan
guarantees, NINA is seeking to diversify financing by actively pursuing additional loan guarantees
through the Japanese government. Due diligence by Japanese financing agencies is in progress and
represents an important step in Japanese loan support.
101
On February 24, 2009, NINA executed an EPC agreement with TANE to build the STP expansion.
The EPC agreement is structured so as to assure that the new plant is constructed on time, on
budget and to exacting standards. In accordance with the EPC agreement, TANE will provide
engineering and development services prior to Full Notice to Proceed, or FNTP, on a time and
materials basis. Upon the New Source Reviews, or NRC approval of the STP Units 3 and 4 combined
license and the owners decision to issue the FNTP, the EPC converts to a lump-sum turnkey contract
with customary warranties, performance and schedule guarantees, and liquidated damage provisions.
TANEs obligations are backed by a guaranty from its ultimate parent, the Toshiba Corporation.
Concurrent with the execution of the EPC agreement, NINA entered into a $500 million credit
facility with TANE to finance the cost of material and equipment commitments prior to FNTP for STP
Units 3 and 4.
In light of the progress made by the project in terms of regulatory schedule, DOE loan
guarantee process, and the conclusion of the EPC agreement, NINA has initiated a partial sell down
process in the STP expansion. NINA has Memorandums of Understanding with a mix of investment grade
rated load serving entities and industrial customers for all offtake from NINAs anticipated 40%
ownership interest in STP Units 3 and 4s generation. Currently, NINA and CPS Energy each own 50%
of the 2,700 megawatt planned expansion of the South Texas Project nuclear facility. After the
sell down, it is expected that each would own 40% and a new owner(s) would have a 20% equity
interest although other ownership outcomes may arise. The ownership interests of STP Units 1 and
2, (NRG 44%, CPS Energy 40% and Austin Energy 16%) are not affected by this proposed sale.
A request to intervene in the Combined License, or COL, proceeding was submitted by several
individuals and public interest groups on April 21, 2009. An Atomic Safety and Licensing Board, or
ASLB, panel heard oral arguments on a request for a hearing in the South Texas Project COL
proceeding on June 23 and 24, 2009 in Bay City, Texas. The ASLB is the NRCs quasi-judicial arm
dealing with licensing matters. The oral argument addressed the admissibility of the issues raised
by Petitioners in their filing. The ASLB is expected to issue its findings as to whether or not a
hearing should be granted during the month of August.
Agreement with eSolar
On June 1, 2009, NRG completed an agreement with eSolar, a leading provider of modular,
scalable solar thermal power technology, to acquire the development rights for up to 465
MW of solar thermal power plants at sites in California and the Southwest. The first plant is
anticipated to begin producing electricity as early as 2011, subject to certain technology
demonstration milestones being pursued by eSolar. At closing, NRG invested approximately $5
million for an equity interest in eSolar and $5 million for deposits and land purchase options
associated with development rights for three projects on sites in south central California and the
Southwest U.S. as well as a portfolio of PPAs to develop, build, own and operate up to 11 eSolar
modular solar generating units at these sites. These development assets will use eSolars
concentrating solar power, or CSP, technology to sell renewable electricity under contracted PPAs
with local utilities.
NRG
New Mexico SunTower On June 11, 2009, NRG announced the execution of a 20-year solar power
purchase agreement with El Paso Electric for the full capacity of a 92 MW solar power plant to be
built on a 450 acre site located about 10 miles from El Paso, Texas near the City of Sunland Park,
New Mexico. The Company anticipates the plant to be in commercial operation by the second quarter
2011.
Alpine SunTower On June 25, 2009, NRG, through its wholly owned subsidiary, Alpine Sun
Tower, LLC, announced the execution of a solar power purchase agreement with Pacific Gas and
Electric Company for the full capacity of a 92 MW solar power plant to be built in Lancaster,
California. The Company anticipates the plant to be in commercial operation by 2012.
102
RepoweringNRG Update
Currently, NRG has several projects in varying stages of development that include a biomass
project at the Montville Generating Station, a new generating unit at the Limestone power station
and the repowering of Big Cajun I and El Segundo sites. The following is a summary of repowering
projects that are under construction. In addition, NRG continues to participate in active bids in
response to requests for proposals in markets in which it operates.
Plants Completed and Operating
Cedar Bayou Generating Station On June 24, 2009, NRG and Optim Energy, LLC, or Optim Energy,
completed construction and began commercial operation of a new natural gas-fueled combined cycle
generating plant at NRGs Cedar Bayou Generating Station in Chambers County, Texas. NRG and Optim
Energy have a 50/50 undivided interest basis in the 550 MW generating plant. NRG is the operator
of the plant and Optim Energy is acting as energy manager for Cedar Bayou unit 4. Cedar Bayou unit
4 is providing the Company a net capacity of 275 MW given NRGs 50% ownership.
Plants under Construction
GenConn Energy LLC In a procurement process conducted by the Department of Public Utility
Control, or DPUC, and finalized in 2008, GenConn Energy, a 50/50 joint venture of NRG and The
United Illuminating Company, secured contracts in 2008 with Connecticut Light & Power, or CL&P, for
the construction and operation of two 200 MW peaking facilities, at NRGs Devon and Middletown
sites in Connecticut. The contracts, which are structured as contracts for differences for the
operation of the new power plants, have a 30-year term and call for commercial operation of the
Devon project by June 1, 2010, and the Middletown project by June 1, 2011. GenConn has secured all
state permits required for the projects and has entered into contracts for engineering,
construction and procurement of the eight GE LM6000 combustion turbines required for the projects.
Construction has begun at the Devon site while construction at Middletown is expected to commence
in the first quarter of 2010.
On April 27, 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 year to date draw downs
on the equity bridge loan of $70 million as of June 30, 2009.
Langford Wind Project On March 16, 2009, NRG, through its wholly owned subsidiary, Padoma
Wind Power LLC, began construction on a 150 MW wind farm located in Tom Green, Irion, and
Schleicher Counties, Texas. The Langford Wind Project will utilize 100 General Electric 1.5 MW
wind turbines. The project is scheduled to reach commercial operation by the end of 2009.
103
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 17, Guarantees, to this Form 10-Q for additional discussion.
See discussion in Note 3, Business Acquisition, regarding the CSRA as a result of the
acquisition of Reliant Energy on May 1, 2009.
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 SFAS 133. Although it is considered an embedded derivative, it is exempt from
derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of SFAS 133. As
of June 30, 2009, based on the Companys stock price, the embedded derivative was out-of-the-money
and had no redemption value.
The Companys unrestricted wholly-owned subsidiary, CSF II, has outstanding notes and
preferred interests that contain a feature considered an embedded derivative per SFAS 133.
Although it is considered a derivative, it is exempt from derivative accounting as it is excluded
from the scope pursuant to paragraph 11(a) of SFAS 133. As of June 30, 2009, based on the
Companys stock price, the CSF II 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, 2009, NRG has several investments
with an ownership interest percentage of 50% or less in energy and energy-related entities that are
accounted for under the equity method of accounting. One of these investments, GenConn, is a
variable interest entity for which NRG is not the primary beneficiary.
NRGs pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately
$68 million as of June 30, 2009. This indebtedness may restrict the ability of these subsidiaries
to issue dividends or distributions to NRG.
Letter of Credit Facilities The Companys $1.3 billion Synthetic Letter of Credit Facility
is unfunded by NRG and is secured by a $1.3 billion cash deposit at Deutsche Bank AG, New York
Branch that was funded using proceeds from the Term Loan Facility investors who participated in the
facility syndication. Under the Synthetic Letter of Credit Facility, NRG is allowed to issue
letters of credit for general corporate purposes including posting collateral to support the
Companys commercial operations activities.
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent
prospective cash requirements in addition to the Companys capital expenditure programs, as
disclosed in the Companys Form 10-K. Also see Note 14, Commitments and Contingencies, to the
condensed consolidated financial statements of this Form 10-Q for a discussion of new commitments
and contingencies that also include contractual obligations and commercial commitments that
occurred during the first half of 2009.
104
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 U.S. The preparation of these financial statements and
related disclosures in compliance with generally accepted accounting principles, or GAAP, requires
the application of appropriate technical accounting rules and guidance as well as the use of
estimates and judgments that affect the reported amounts of assets, liabilities, revenues and
expenses, and related disclosures of contingent assets and liabilities. The application of these
policies necessarily involves judgments regarding future events, including the likelihood of
success of particular projects, legal and regulatory challenges. These judgments, in and of
themselves, could materially affect the financial statements and disclosures based on varying
assumptions, which may be appropriate to use. In addition, the financial and operating environment
may also have a significant effect, not only on the operation of the business, but on the results
reported through the application of accounting measures used in preparing the financial statements
and related disclosures, even if the nature of the accounting policies have not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience,
consultation with experts and other methods the Company considers reasonable. In any event, actual
results may differ substantially from the Companys estimates. 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 revenue
recognition and derivative accounting, income taxes and valuation allowance for deferred taxes,
evaluation of assets for impairment and other than temporary decline in value, goodwill and other
intangible assets, and contingencies.
In connection with the Reliant Energy acquisition, the Company will record additional
intangible assets. See Note 3 Business Acquisition.
The following represents new critical estimates of revenues and cost of energy related to the
Companys Reliant Energy segment that would have a material impact on the segments financial
condition or results of operations:
|
|
|
Accrued Unbilled Revenues Accrued unbilled revenues are critical accounting estimates
as volumes are not precisely known at the end of each reporting period and the revenue
amounts are material. Accrued unbilled revenues of $433 million as of June 30, 2009 which
represents 11% of the Companys consolidated revenues for the six months ended June 30,
2009 and 37% of Reliant Energys revenues for the two months ended June 30, 2009. |
|
|
|
Estimated Energy Supply Costs Reliant Energy record energy supply costs for
electricity sales and services to retail customers based on estimated supply volumes for
the applicable reporting period. This is a critical accounting estimate as volumes are not
known at the end of each reporting period and the purchased power amounts are material.
Reliant Energys energy supply costs of $93 million as of June 30, 2009 consist of
estimated transmission and distribution charges not yet billed by the transmission and
distribution utilities. |
|
|
|
In estimating supply volumes, the Company considers the effects of historical customer
volumes, weather factors and usage by customer class. The Company estimates transmission and
distribution delivery fees using the same method that is used for electricity sales and
services to retail customers. In addition, NRG estimates ERCOT ISO fees based on historical
trends, estimated supply volumes and initial ERCOT ISO settlements. Volume estimates are
then multiplied by the supply rate and recorded as purchased power in the applicable
reporting period. Changes in the Companys volume usage would result in a similar offsetting
change in billed volumes, thus partially mitigating the Company energy supply costs. |
|
|
|
Dependence on ERCOT ISO Settlement Procedures Preliminary settlement information is
due from the ERCOT ISO within two months after electricity is delivered. Final settlement
information is due from the ERCOT ISO within six months after electricity is delivered.
The six month settlement received from ERCOT is considered final as ERCOT will only
resettle if there are data errors greater than 2% of that days transaction dollars or if
alternate dispute resolutions are granted. The Company records estimated supply costs and
related fees using estimated supply volumes, as discussed above, and adjust those costs
upon receipt of the ERCOT ISO information. Delays in settlements could materially affect
the accuracy of NRGs recorded energy supply costs and related fees. |
105
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. |
As a result of the acquisition of Reliant Energy, NRGs portfolio consists of generation
assets and full requirement 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, Intercontinental Exchange, or ICE, and Chicago Climate Exchange, or CCX, as
well as over-the-counter financial markets. The portion of forecasted transactions hedged may vary
based upon managements assessment of market, weather, operations and other factors.
While some of the contracts the Company uses to manage risk represent commodities or
instruments for which prices are available from external sources, other commodities and certain
contracts are not actively traded and are valued using other pricing sources and modeling
techniques to determine expected future market prices, contract quantities, or both. NRG uses the
Companys best estimates to determine the fair value of commodity and derivative contracts held and
sold. These estimates consider various factors, including closing exchange and over-the-counter
price quotations, time value, volatility factors and credit exposure. However, it is likely that
future market prices could vary from those used in recording mark-to-market derivative instrument
valuation, and such variations could be material.
NRG measures the risk of the Companys portfolio using several analytical methods, including
sensitivity tests, scenario tests, stress tests, position reports, and Value at Risk, or VaR. VaR
is a statistical concept that defines risk of loss, at a certain confidence level, over a
designated horizon due to changes in market prices over that horizon. Currently, the company
estimates VaR using a Monte Carlo simulation of prices. NRGs total portfolio includes
mark-to-market and non-mark-to-market energy assets and liabilities.
NRG uses a diversified VaR model to calculate an estimate of the potential loss in the fair
value of the Companys energy assets and liabilities, which includes generation assets, load
obligations, and bilateral physical and financial transactions. The key assumptions for the
Companys diversified model include: (i) a lognormal distribution of prices; (ii) one-day holding
period; (iii) a 95% confidence interval; (iv) a rolling 36-month forward looking period; and (v)
market implied volatilities and historical price correlations.
106
As of June 30, 2009, the VaR for NRGs commodity portfolio, including generation assets, load
obligations and bilateral physical and financial transactions calculated using the diversified VaR
model was $49 million. The inclusion of the Reliant Energy retail portfolio, comprised of
contracted load and related supply, did not materially affect the VaR measure as the portfolio is
currently hedged.
The following table summarizes average, maximum and minimum VaR for NRG for the three and six
months ended June 30, 2009, and 2008:
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
VAR |
|
2009 |
|
|
2008 |
|
|
Three months ended June 30: |
|
$ |
49 |
|
|
$ |
58 |
|
Average |
|
|
35 |
|
|
|
50 |
|
Maximum |
|
|
54 |
|
|
|
63 |
|
Minimum |
|
|
28 |
|
|
|
39 |
|
|
Six months ended June 30: |
|
$ |
49 |
|
|
$ |
58 |
|
Average |
|
|
38 |
|
|
|
52 |
|
Maximum |
|
|
54 |
|
|
|
65 |
|
Minimum |
|
|
28 |
|
|
|
35 |
|
|
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, 2009, for the entire term of
these instruments entered into for both asset management and trading, was approximately $42 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.
As of June 30, 2009, the Company had various interest rate swap agreements with notional
amounts totaling approximately $3.3 billion. If the swaps had been discontinued on June 30, 2009,
the Company would have owed the counterparties approximately $120 million. Based on the investment
grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance
by counterparties to its hedge contracts to be insignificant.
NRG has both long and short-term debt instruments that subject the Company to the risk of loss
associated with movements in market interest rates. As of June 30, 2009, a 1% change in interest
rates would result in a $13 million change in interest expense on a rolling twelve month basis.
As of June 30, 2009, the Companys long-term debt fair value was $8.3 billion and the carrying
amount was $8.6 billion. NRG estimates that a 1% decrease in market interest rates would have
increased the fair value of the Companys long-term debt by $456 million.
107
Liquidity Risk
Liquidity risk arises from the general funding needs of NRGs activities and in the management
of the Companys assets and liabilities. NRGs liquidity management framework is intended to
maximize liquidity access and minimize funding costs. Through active liquidity management, the
Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the
Company to replace maturing obligations when due and fund assets at appropriate maturities and
rates. To accomplish this task, management uses a variety of liquidity risk measures that take
into consideration market conditions, prevailing interest rates, liquidity needs, and the desired
maturity profile of liabilities.
Based on a sensitivity analysis for power and gas positions under marginable contracts
excluding all non-affiliate third party positions under the CSRA, a $1 per MMBtu increase or
decrease in natural gas prices across the term of the marginable contracts would cause a change in
margin collateral outstanding of approximately $65 million as of June 30, 2009, and a 0.25
MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin
collateral of approximately $63 million as of June 30, 2009. This analysis uses simplified
assumptions and is calculated based on portfolio composition and margin-related contract provisions
as of June 30, 2009.
Under the second lien, NRG is required to post certain letter of credits as credit support for
changes in commodity prices. As of June 30, 2009, no letters of credit are outstanding to second
lien counterparties. With changes in commodity prices, the letters of credit could grow to
$87 million, the cap under the agreements.
Credit Risk
Credit risk relates to the risk of loss resulting from non-performance or non-payment by
counterparties pursuant to the terms of their contractual obligations. The Company monitors and
manages credit risk through credit policies that include: (i) an established credit approval
process; (ii) a daily monitoring of counterparties credit limits; (iii) the use of credit
mitigation measures such as margin, collateral, credit derivatives or prepayment arrangements;
(iv) the use of payment netting agreements; and (v) the use of master netting agreements that allow
for the netting of positive and negative exposures of various contracts associated with a single
counterparty. Risks surrounding counterparty performance and credit could ultimately impact the
amount and timing of expected cash flows. The Company seeks to mitigate counterparty risk with a
diversified portfolio of counterparties, including ten participants under its first and second lien
structure. The Company also has credit protection within various agreements to call on additional
collateral support if and when necessary. Cash margin is collected and held at NRG to cover the
credit risk of the counterparty until positions settle.
Under the current economic downturn in the U.S. and overseas, the Company has heightened its
management and mitigation of counterparty credit risk by using credit limits, netting agreements,
collateral thresholds, volumetric limits and other mitigation measures, where available. NRG
avoids concentration of counterparties whenever possible and applies credit policies that include
an evaluation of counterparties financial condition, collateral requirements and the use of
standard agreements that allow for netting and other security.
As of June 30, 2009, total credit exposure to substantially all counterparties was
$2.1 billion and NRG held collateral (cash and letters of credit) against those positions of $469
million resulting in a net exposure of $1.7 billion compared
with a net exposure of $1.3 billion as of March 31, 2009. This
increase is due to Merrill Lynchs position as credit provider
to Reliant Energy and the exposure resulting from novated trades that
were completed as part of the acquisition of Reliant Energy, as
discussed Note 3 Business Acquistion. Total credit exposure is discounted at the
risk free rate.
108
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 normal purchase and sale, and non-derivative transactions. The
exposure is shown net of collateral held, includes amounts net of receivables or payables and
excludes non-affiliate third party exposure under the CSRA.
|
|
|
|
|
|
|
Net Exposure(a) (b) as of |
|
|
June 30, 2009 |
Category |
|
(% of Total) |
|
Financial institutions |
|
|
82 |
% |
Utilities, energy, merchants, marketers and other |
|
|
14 |
|
Coal suppliers |
|
|
2 |
|
ISOs |
|
|
2 |
|
|
Total |
|
|
100 |
% |
|
|
|
|
Net Exposure(a) (b) as of |
|
|
June 30, 2009 |
Category |
|
(% of Total) |
|
Investment grade |
|
|
94 |
% |
Non-Investment grade |
|
|
|
|
Non-rated |
|
|
6 |
|
|
Total |
|
|
100 |
% |
|
|
|
|
(a) |
|
Credit exposure excludes California tolling,
uranium, coal transportation, New England Reliability Must-Run, 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, or credit risks for certain contracts are not readily
measurable due to a lack of market reference prices. |
|
(b) |
|
The exposure amounts presented in the above table
do not include non-affiliate third party exposure
under the CSRA. The gross credit exposure to third
parties under the CSRA is $410 million, and the cash
collateral held by Merrill Lynch against this exposure
is $312 million. |
NRG
has credit risk exposure to certain counterparties representing more than 10% of
total net exposure and the aggregate of such counterparties was $707 million. NRG has significant
credit risk concentration with Merrill Lynch primarily due to cash collateral held by Merrill Lynch
for positions under the CSRA. NRG expects this risk to be significantly reduced when the Company
unwinds the CSRA. Approximately 85% of NRGs positions relating to credit risk roll-off by the end
of 2011. Changes in hedge positions and market prices will affect credit exposure and counterparty
concentration. 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 a counterparty.
NRG
is exposed to retail credit risk through our competitive electricity supply business,
which serves commercial and industrial 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 arrangement.
Retail credit risk is dependent on the overall economy, but is minimized due to the fact that NRGs
portfolio of retail customers is largely diversified, with no significant single name
concentration.
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, to hedge fuel requirements at generation
facilities, hedge supplies for retail operations and protect fuel
inventories. In addition, in order to mitigate interest rate risk associated with the issuance of
the Companys variable rate and fixed rate debt, NRG enters into interest rate swap agreements.
NRGs trading activities include contracts to profit from market price changes as opposed to
hedging an exposure, and are subject to limits in accordance with the Companys risk management
policy. These contracts are recognized on the balance sheet at fair value and changes in the fair
value of these derivative financial instruments are recognized in earnings. These trading
activities are a complement to NRGs energy marketing portfolio.
109
The tables below disclose the activities that include both exchange and non-exchange traded
contracts accounted for at fair value. Specifically, these tables disaggregate realized and
unrealized changes in fair value; identify changes in fair value attributable to changes in
valuation techniques; disaggregate estimated fair values at June 30, 2009, based on whether fair
values are determined by quoted market prices or more subjective means; and indicate the maturities
of contracts at June 30, 2009. Also, in connection with the Companys acquisition of Reliant
Energy, NRG acquired retail load and supply contracts. The table below also includes the fair
value of supply contracts under mark-to-market accounting treatment as of May 1, 2009.
|
|
|
|
|
Derivative Activity Gains/(Losses) |
|
(In millions) |
|
Fair value of contracts as of December 31, 2008 |
|
$ |
996 |
|
Contracts realized or otherwise settled during the period |
|
|
(322 |
) |
Contracts acquired in conjunction with Reliant Energy |
|
|
(1,054 |
) |
Changes in fair value |
|
|
860 |
|
|
Fair value of contracts as of June 30, 2009 |
|
$ |
480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of June 30, 2009 |
|
|
Maturity |
|
|
|
|
|
|
|
|
|
Maturity |
|
|
(In millions) |
|
Less Than |
|
Maturity |
|
Maturity |
|
in Excess |
|
Total Fair |
Sources of Fair Value Gains/(Losses) |
|
1 Year |
|
1-3 Years |
|
4-5 Years |
|
4-5 Years |
|
Value |
|
Prices actively quoted |
|
$ |
11 |
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
20 |
|
Prices provided by other external sources |
|
|
130 |
|
|
|
131 |
|
|
|
179 |
|
|
|
(30 |
) |
|
|
410 |
|
Prices provided by models and other valuation methods |
|
|
57 |
|
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
50 |
|
|
Total |
|
$ |
198 |
|
|
$ |
133 |
|
|
$ |
179 |
|
|
$ |
(30 |
) |
|
$ |
480 |
|
|
A small portion of NRGs contracts are exchange-traded contracts with readily available quoted
market prices. The majority of NRGs contracts are non-exchange-traded contracts valued using
prices provided by external sources, primarily price quotations available through brokers or
over-the-counter and on-line exchanges. For the majority of NRG markets, the Company receives
quotes from multiple sources. To the extent that NRG receives multiple quotes, the Companys
prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG
believes provide the most liquid market for the commodity. If the Company receives one quote then
the mid-point of the bid-ask spread for that quote is used. The terms for which such price
information is available vary by commodity, region and product. The remainder of the assets and
liabilities 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 under a specific master
agreement is an asset, the Company is using the counterpartys default swap rate. If the exposure
under a specific master agreement is a liability, the Company is using NRGs default swap rate.
The credit reserve is added to the discounted fair value to reflect the exit price that a market
participant would be willing to receive to assume NRGs liabilities or that a market participant
would be willing to pay for NRGs assets. As of June 30, 2009, the credit reserve resulted in a
$23 million increase in fair value which is composed of a $1 million loss in OCI and a $24 million
gain in derivative revenue and cost of operations.
The fair values in each category reflect the level of forward prices and volatility factors as
of June 30, 2009, 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.
110
The Company has elected to disclose derivative activity on a trade-by-trade basis and does not
offset amounts at the counterparty master agreement level. Consequently, the magnitude of the
changes in individual current and non-current derivative assets or liabilities is higher than the
underlying credit and market risk of the Companys portfolio. As discussed in Item 7A Commodity
Price Risk in the Companys Annual Report on Form 10-K for the fiscal year ended December 31, 2008,
NRG measures the sensitivity of the Companys portfolio to potential changes in market prices using
Value at Risk, or VAR, a statistical model which attempts to predict risk of loss based on market
price and volatility. NRGs risk management policy places a limit on one-day holding period VAR,
which limits the Companys net open position. As the Companys trade-by-trade derivative
accounting results in a gross-up of the Companys derivative assets and liabilities, the net
derivative assets and liability position is a better indicator of NRGs hedging activity. As of
June 30, 2009, NRGs net derivative asset was $480 million, a decrease to total fair value of $516
million as compared to December 31, 2008. This decrease was primarily driven by the acquisition of
Reliant Energys retail portfolio offset by increase in fair value due to the decreases in gas and
power prices and the roll-off of trades that settled during the period.
Currency Exchange Risk
NRG may be subject to foreign currency risk as a result of the Company entering into purchase
commitments with foreign vendors for the purchase of major equipment associated with RepoweringNRG
initiatives. To reduce the risks to such foreign currency exposure, the Company may enter into
transactions to hedge its foreign currency exposure using currency options and forward contracts.
As of June 30, 2009, there were no foreign currency options and forward contracts outstanding for
purchase commitments.
In connection with the MIBRAG sale transaction, NRG entered into a foreign currency forward
contract to hedge the impact of exchange rate fluctuations on the sale proceeds. The foreign
currency forward contract had a fixed exchange rate of 1.277 and required NRG to deliver EUR 200
million in exchange for $255 million on June 15, 2009. 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).
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 three months ended June 30, 2009.
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 Rules 13a-15(f) under the Exchange Act) that occurred in the second quarter of
2009 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.
111
PART II OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through June 30,
2009, see Note 14, Commitments and Contingencies, to the condensed consolidated financial
statements of this Form 10-Q.
ITEM 1A RISK FACTORS
In addition to the revised risk factors below, information regarding risk factors appears in
Part I, Item 1A, Risk Factors in NRGs Annual Report on Form 10-K for the fiscal year ended
December 31, 2008 and Part II, Item 1A, Risk Factors in NRGs Quarterly Report on Form 10-Q for the
quarter ended March 31, 2009.
Risks Related to the Reliant Energy Retail Business
NRG may have to post significant amounts of collateral, which could adversely affect its
liquidity, financial position and business.
In connection with any unwind of the Companys credit-enhanced retail structure with Merrill
Lynch, NRG will have to post collateral for new retail supply and hedging transactions in
connection with Reliant Energys retail business. The Companys levels of collateral postings
would be determined and impacted by the terms and timing of the unwind, the nature and volume of
the Companys commodity hedging agreements, commodity prices and other strategic alternatives that
NRG may undertake. While NRG intends to (i) become the primary provider of Reliant Energys supply
requirements; and (ii) use a portion of the net proceeds of the 8.50% Senior Notes to the cash
collateralize Reliant Energys obligations under the credit sleeve arrangements (assuming NRG can
reach an agreement with Merrill Lynch on terms acceptable to the Company), depending on the
specific timing and the movement in underlying commodity prices, NRG could incur significant
collateral posting obligations that may require the Company to seek additional sources of
liquidity, including additional debt. The covenants in NRGs senior secured credit facility and
credit sleeve arrangements with Merrill Lynch restrict the Companys ability to, among other
things, obtain additional financing. If NRG were unable to generate sufficient cash flows from
operations or raise cash from other sources, NRG may not be able to meet the Companys collateral
posting obligations. These situations could result from further adverse developments in the
energy, fuel or capital markets, a disruption in NRGs operations or those of third parties or
other events adversely affecting NRGs cash flows and financial performance. NRG cannot make any
assurances that it would be able to obtain such additional liquidity on commercially reasonable
terms or at all.
Volatile power supply costs and demand for power could adversely affect the financial performance
of NRGs retail business.
Although NRG has begun the process of becoming the primary provider of Reliant Energys supply
requirements, Reliant Energy presently purchases a substantial portion of its supply requirements
from third parties. As a result, Reliant Energys financial performance depends on its ability to
obtain adequate supplies of electric generation from third parties at prices below the prices it
charges its customers. Consequently, the Companys earnings and cash flows could be adversely
affected in any period in which Reliant Energys power supply costs rise at a greater rate than the
rates it charges to customers. The price of power supply purchases associated with Reliant
Energys energy commitments can be different than that reflected in the rates charged to customers
due to, among other factors:
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varying supply procurement contracts used and the timing of entering into related
contracts; |
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subsequent changes in the overall price of natural gas; |
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daily, monthly or seasonal fluctuations in the price of natural gas relative to the
12-month forward prices; |
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transmission constraints and the Companys ability to move power to its customers; and |
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changes in market heat rate (i.e., the relationship between power and natural gas
prices). |
The Companys earnings and cash flows could also be adversely affected in any period in which
the demand for power significantly varies from the forecasted supply, which could occur due to,
among other factors, weather events, competition and economic conditions.
112
NRG depends on the Electric Reliability Council of Texas, or ERCOT, to communicate operating and
system information in a timely and accurate manner. Information that is not timely or accurate
can have an impact on the Companys current and future reported financial results.
ERCOT communicates information relating to a customers choice of retail electric provider and
other data needed for servicing the customer accounts of the Companys retail electric providers.
Any failure to perform these tasks will result in delays and other problems in enrolling, switching
and billing customers. Information that is not timely or accurate may adversely impact the
Companys ability to serve load in the optimum manner.
NRG could be liable for a share of the payment defaults of other market participants.
If a market participant defaults on its payment obligations to an independent system operator,
or ISO, the Company, together with other market participants, are liable for a portion of the
default obligation that is not otherwise covered by the defaulting market participant. Each ISO
establishes credit requirements applicable to market participants and the basis for allocating
payment default amounts to market participants. In ERCOT, the allocation is based on share of the
total load.
Significant events beyond the Companys control, such as hurricanes and other weather-related
problems or acts of terrorism, could cause a loss of load and customers and thus have a material
adverse effect on the Companys business.
The uncertainty associated with events beyond the Companys control, such as significant
weather events and the risk of future terrorist activity, could cause a loss of load and customers
and may affect the Companys results of operations and financial condition in unpredictable ways.
In addition, significant weather events or terrorist actions could damage or shut down the power
transmission and distribution facilities upon which the retail business is dependent. Power supply
may be sold at a loss if these events cause a significant loss of retail customer load.
ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
ITEM 3 DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5 OTHER INFORMATION
None.
113
ITEM 6 EXHIBITS
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Exhibits |
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4.1
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Sixteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
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4.2
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Seventeenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
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4.3
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Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
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4.4
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Nineteenth Supplemental Indenture, dated May 8, 2009, 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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4.5
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Twentieth Supplemental Indenture, dated May 8, 2009, 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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Twenty-First Supplemental Indenture, dated May 8, 2009, 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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4.7
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Twenty-Second Supplemental Indenture, dated June 5, 2009, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.(3) |
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4.8
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Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.(4) |
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10.1A
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Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1, 2009, among Reliant Energy Power
Supply, LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE
Retail Receivables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc. (5) |
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10.1B
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Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1, 2009
(Portions of this Exhibit have been omitted pursuant to a request for confidential treatment). (5) |
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10.2
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Contingent Contribution Agreement, dated May 1, 2009, among NRG Energy, Inc., NRG Retail LLC, RERH Holdings, LLC,
Reliant Energy Retail Holdings, LLC and Merrill Lynch Commodities, Inc. (5) |
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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) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on May 4, 2009 |
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(2) |
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Incorporated herein by
reference to NRG Energy, Incs current report on Form 8-K filed on May 14, 2009 |
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(3) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on June 5, 2009 |
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(4) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on July 15, 2009 |
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(5) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on May 7, 2009 |
114
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
Chief Executive Officer
(Principal Executive Officer)
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/s/ ROBERT C. FLEXON |
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Robert C. Flexon
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: July 30, 2009
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Chief Accounting Officer |
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(Principal Accounting Officer) |
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115
EXHIBIT INDEX
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Exhibits |
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|
|
|
|
4.1
|
|
Sixteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.2
|
|
Seventeenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
|
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|
4.3
|
|
Eighteenth Supplemental Indenture, dated April 28, 2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiary named therein and Law Debenture Trust Company of New York. (1) |
|
|
|
4.4
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|
Nineteenth Supplemental Indenture, dated May 8, 2009, 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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4.5
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Twentieth Supplemental Indenture, dated May 8, 2009, 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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Twenty-First Supplemental Indenture, dated May 8, 2009, 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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4.7
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Twenty-Second Supplemental Indenture, dated June 5, 2009, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.(3) |
|
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4.8
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|
Twenty-Third Supplemental Indenture, dated July 14, 2009, among NRG Energy, Inc., the guarantors named therein and
Law Debenture Trust Company of New York.(4) |
|
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10.1A
|
|
Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1, 2009, among Reliant Energy Power
Supply, LLC, RERH Holdings, LLC, Reliant Energy Retail Holdings, LLC, Reliant Energy Retail Services, LLC, RE
Retail Receivables, LLC, Merrill Lynch Commodities, Inc. and Merrill Lynch & Co., Inc. (5) |
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10.1B
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Schedules and Exhibits to the Amended and Restated Credit Sleeve and Reimbursement Agreement, dated May 1, 2009
(Portions of this Exhibit have been omitted pursuant to a request for confidential treatment). (5) |
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10.2
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Contingent Contribution Agreement, dated May 1, 2009, among NRG Energy, Inc., NRG Retail LLC, RERH Holdings, LLC,
Reliant Energy Retail Holdings, LLC and Merrill Lynch Commodities, Inc. (5) |
|
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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. |
|
|
|
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) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on May 4, 2009 |
|
(2) |
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Incorporated herein by
reference to NRG Energy, Incs current report on Form 8-K filed on May 14, 2009 |
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(3) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on June 5, 2009 |
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(4) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on July 15, 2009 |
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(5) |
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Incorporated herein by reference to NRG Energy, Incs current report on Form 8-K filed on May 7, 2009 |
116