e10vk
UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year ended December 31,
2009.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the Transition period
from to .
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Commission file
No. 001-15891
NRG Energy, Inc.
(Exact name of registrant as
specified in its charter)
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Delaware
(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)
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(609) 524-4500
(Registrants telephone
number, including area code:)
Securities registered pursuant
to Section 12(b) of the Act:
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Title of Each Class
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Name of Exchange on Which Registered
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Common Stock, par value $0.01
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New York Stock Exchange
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Securities registered pursuant
to Section 12(g) of the Act:
Common Stock, par value $0.01
per share
Indicate by check mark if the registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes þ No o
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Exchange
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports) and (2) has been subject
to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(§ 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of the registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, a non-accelerated
filer, or a smaller reporting company. See the definitions of
large accelerated filer, accelerated
filer and smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one):
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Large
accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting
company o
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(Do not check if a smaller
reporting company)
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
As of the last business day of the most recently completed
second fiscal quarter, the aggregate market value of the common
stock of the registrant held by non-affiliates was approximately
$6,803,812,501 based on the closing sale price of $25.96 as
reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the
registrants classes of common stock as of the latest
practicable date.
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Class
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Outstanding at February 17, 2010
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Common Stock, par value $0.01 per share
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261,898,178
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Documents
Incorporated by Reference:
Portions
of the Proxy Statement for the 2010 Annual Meeting of
Stockholders
are
incorporated by reference into Part III of this
Form 10-K
TABLE OF
CONTENTS
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Glossary of Terms
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3
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PART I
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9
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Item 1 Business
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9
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Item 1A Risk Factors Related to NRG Energy,
Inc.
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44
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Item 1B Unresolved Staff Comments
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58
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Item 2 Properties
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59
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Item 3 Legal Proceedings
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60
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PART II
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64
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Item 4 Market for Registrants Common
Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities
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64
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Item 5 Selected Financial Data
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67
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Item 6 Managements Discussion and
Analysis of Financial Condition and Results of Operations
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69
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Item 6A Quantitative and Qualitative
Disclosures about Market Risk
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130
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Item 7 Financial Statements and
Supplementary Data
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134
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Item 8 Changes in and Disagreements with
Accountants on Accounting and Financial Disclosures
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134
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Item 8A Controls and Procedures
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134
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Item 8B Other Information
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135
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PART III
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136
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Item 9 Directors, Executive Officers and
Corporate Governance
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136
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Item 10 Executive Compensation
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136
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Item 11 Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder
Matters
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136
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Item 12 Certain Relationships and Related
Transactions, and Director Independence
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136
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Item 13 Principal Accounting Fees and
Services
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136
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PART IV
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137
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Item 14 Exhibits and Financial Statement
Schedules
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137
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EXHIBIT INDEX
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237
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2
Glossary
of Terms
When the following terms and abbreviations appear in the text of
this report, they have the meanings indicated below:
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AB32
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Assembly Bill 32 California Global Warming
Solutions Act of 2006
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APB
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Accounting Principles Board
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ARO
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Asset Retirement Obligation
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ASC
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The FASB Accounting Standards Codification, which the FASB has
established as the source of authoritative U.S. GAAP
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ASU
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Accounting Standards Updates updates to the ASC
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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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BACT
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Best Available Control Technology
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BTU
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British Thermal Unit
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CAA
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Clean Air Act
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CAGR
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Compound annual growth rate
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CAIR
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Clean Air Interstate Rule
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CAISO
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California Independent System Operator
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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/institutional
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CL&P
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The Connecticut Light & Power Company
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CO2
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Carbon dioxide
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COLA
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Combined Construction and Operating License Application
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CPS
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CPS Energy
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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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CSF CAGRs
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Embedded derivatives within the CSF Debt, individually referred
to as CSF I CAGR and CSF II CAGR
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CSF Debt
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CSF I and CSF II issued notes and preferred interest,
individually referred to as CSF I Debt and CSF II Debt
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CSRA
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Credit Sleeve Reimbursement Agreement with Merrill Lynch in
connection with acquisition of Reliant Energy, as hereinafter
defined
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CSRA Amendment
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Amendment of the existing CSRA with Merrill Lynch which became
effective October 5, 2009
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DNREC
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Delaware Department of Natural Resources and Environmental
Control
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DOE
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Department of Energy
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DPUC
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Department of Public Utility Control
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EAF
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Annual Equivalent Availability Factor, which measures the
percentage of maximum generation available over time as the
fraction of net maximum generation that could be provided over a
defined period of time after all types of outages and deratings,
including seasonal deratings, are taken into account
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EITF
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Emerging Issues Task Force
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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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EWG
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Exempt Wholesale Generator
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Exchange Act
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The Securities Exchange Act of 1934, as amended
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Expected Baseload Generation
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The net baseload generation limited by economic factors
(relationship between cost of generation and market price) and
reliability factors (scheduled and unplanned outages)
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FASB
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Financial Accounting Standards Board the
designated organization for establishing standards for financial
accounting and reporting
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FCM
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Forward Capacity Market
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3
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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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FPA
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Federal Power Act
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Fresh Start
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Reporting requirements as defined by ASC-852,
Reorganizations
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FSP
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FASB Staff Position
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GHG
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Greenhouse Gases
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Heat Rate
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A measure of thermal efficiency computed by dividing the total
BTU content of the fuel burned by the resulting kWhs
generated. Heat rates can be expressed as either gross or net
heat rates, depending whether the electricity output measured is
gross or net generation and is generally expressed as BTU per
net kWh
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Hedge Reset
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Net settlement of long-term power contracts and gas swaps by
negotiating prices to current market completed in November 2006
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IGCC
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Integrated Gasification Combined Cycle
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ISO
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Independent System Operator, also referred to as Regional
Transmission Organizations, or RTO
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ISO-NE
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ISO New England Inc.
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ITISA
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Itiquira Energetica S.A.
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kV
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Kilovolts
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kW
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Kilowatts
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kWh
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Kilowatt-hours
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LFRM
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Locational Forward Reserve Market
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LIBOR
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London Inter-Bank Offer Rate
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LMP
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Locational Marginal Prices
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LTIP
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Long-Term Incentive Plan
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MACT
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Maximum Achievable Control Technology
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Mass
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Residential and small business
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Merit Order
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A term used for the ranking of power stations in order of
ascending marginal cost
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MIBRAG
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Mitteldeutsche Braunkohlengesellschaft mbH
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MMBtu
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Million British Thermal Units
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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
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Net Baseload Capacity
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Nominal summer net megawatt capacity of power generation
adjusted for ownership and parasitic load, and excluding
capacity from mothballed units as of December 31, 2009
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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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NYSDEC
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New York Department of Environmental Conservation
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4
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OCI
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Other Comprehensive Income
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Phase II 316(b) Rule
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A section of the Clean Water Act regulating cooling water intake
structures
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PJM
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PJM Interconnection, LLC
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PJM market
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The wholesale and retail electric market operated by PJM
primarily in all or parts of Delaware, the District of Columbia,
Illinois, Maryland, New Jersey, Ohio, Pennsylvania, Virginia and
West Virginia
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PML
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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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PPM
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Parts per Million
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PSD
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Prevention of Significant Deterioration
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PUCT
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Public Utility Commission of Texas
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PUHCA of 2005
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Public Utility Holding Company Act of 2005
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PURPA
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Public Utility Regulatory Policy Act of 2005
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QF
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Qualifying Facility under PURPA
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Reliant Energy
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NRGs retail business in Texas purchased on May 1, 2009,
from Reliant Energy, Inc. which is now known as RRI Energy,
Inc., or RRI
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Repowering
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Technologies utilized to replace, rebuild, or redevelop major
portions of an existing electrical generating facility, not only
to achieve a substantial emissions reduction, but also to
increase facility capacity, and improve system efficiency
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RepoweringNRG
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NRGs program designed to develop, finance, construct and
operate new, highly efficient, environmentally responsible
capacity
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REPS
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Reliant Energy Power Supply, LLC
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RERH
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RERH Holding, LLC and its subsidiaries
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Revolving Credit Facility
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NRGs $1 billion senior secured credit facility which
matures on February 2, 2011
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RGGI
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Regional Greenhouse Gas Initiative
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RMR
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Reliability Must-Run
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ROIC
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Return on invested capital
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RPM
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Reliability Pricing Model term for capacity market
in PJM market
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RRI
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RRI Energy, Inc.
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RTO
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Regional Transmission Organization, also referred to as an
Independent System Operators, or ISO
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Sarbanes-Oxley
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Sarbanes Oxley Act of 2002, as amended
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Schkopau
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Kraftwerk Schkopau Betriebsgesellschaft mbH, an entity in which
NRG has a 41.9% interest
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SCR
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Selective Catalytic Reduction
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SEC
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United States Securities and Exchange Commission
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Securities Act
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The Securities Act of 1933, as amended
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Senior Credit Facility
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NRGs senior secured facility, which is comprised of a Term
Loan Facility and a $1.3 billion Synthetic Letter of Credit
Facility which matures on February 1, 2013, and a $1 billion
Revolving Credit Facility, which matures on February 2, 2011
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SIFMA
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Securities Industry and Financial Markets Association
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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 and $1.1
billion of 7.375% senior notes due 2017 and $700 million of
8.5% senior notes due 2019
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SERC
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Southeastern Electric Reliability Council/Entergy
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SFAS
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Statement of Financial Accounting Standards issued by the FASB
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SO2
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Sulfur dioxide
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SOP
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Statement of Position issued by the American Institute of
Certified Public Accountants
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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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5
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Synthetic Letter of Credit Facility
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NRGs $1.3 billion senior secured synthetic letter of
credit facility which matures on February 1, 2013
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TANE
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Toshiba American Nuclear Operating Company
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TANE Facility
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NINAs $500 million credit facility with TANE which matures
on February 24, 2012
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Term Loan Facility
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A senior first priority secured term loan which matures on
February 1, 2013, and is included as part of NRGs Senior
Credit Facility.
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Texas Genco
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Texas Genco LLC, now referred to as the Companys Texas
Region
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Tonnes
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Metric tonnes, which are units of mass or weight in the metric
system each equal to 2,205 lbs and are the global measurement
for GHG
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TWh
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Terawatt hour
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U.S.
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United States of America
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U.S. EPA
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United States Environmental Protection Agency
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U.S. GAAP
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Accounting principles generally accepted in the United States
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VaR
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Value at Risk
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WCP
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WCP (Generation) Holdings, Inc.
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6
ACCOUNTING
PRONOUNCEMENTS
The following ASC topics are referenced in this report. In
addition, certain U.S. GAAP standards and interpretations
were adopted by the Company in 2009 prior to the July 1,
2009, effective date of the ASC, and were subsequently
incorporated into one or more ASC topics. Further, certain
U.S. GAAP standards were ratified by the FASB in 2009 prior
to July 1, 2009, but are not yet effective and have
therefore not yet been incorporated into the ASC. This glossary
includes the definition of these legacy standards
and interpretations under the ASC topic or topics in which they
have been, or are expected to be, fully or partially
incorporated.
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ASC 105
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ASC-105, Generally Accepted Accounting Principles;
incorporates:
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SFAS No. 168, The FASB
Accounting Standards Codification and the Hierarchy of Generally
Accepted Accounting Principles
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ASC 270
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ASC-270, Interim Reporting; incorporates:
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FSP FAS 107-1 and APB 28-1,
Interim Disclosures about Fair Value of Financial
Instruments
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ASC 275
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ASC-275, Risks and Uncertainties; incorporates:
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FSP FAS 142-3, Determination of
the Useful Life of Intangible Assets
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ASC 320
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ASC-320, Investments-Debt and Equity Securities;
incorporates:
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FSP FAS 115-2 and FAS 124-2,
Recognition and Presentation of Other-Than-Temporary
Impairments
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ASC 323
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ASC-323, Investments-Equity Method and Joint Ventures;
incorporates:
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EITF 08-6, Equity Method
Investment Accounting Considerations
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APB Opinion No. 18, The Equity
Method of Accounting for Investments in Common Stock
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ASC 350
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ASC-350, Intangibles-Goodwill and Others; incorporates:
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FSP FAS 142-3, Determination of
the Useful Life of Intangible Assets
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SFAS No. 142, Goodwill and
Other Intangible Assets
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ASC 360
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ASC-360, Property, Plant, and Equipment; incorporates:
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SFAS No. 144, Accounting for
the Impairment or Disposal of Long-Lived Assets
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ASC 410
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ASC-410, Asset Retirement and Environmental Obligations;
incorporates:
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SFAS No. 143, Accounting for
Asset Retirement Obligations
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ASC 450
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ASC-450, Contingencies; incorporates:
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SFAS No. 5, Accounting for
Contingencies
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ASC 460
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ASC-460, Guarantees; incorporates:
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FIN No. 45, Guarantors
Accounting and Disclosure Requirements of Guarantees, Including
Indirect Guarantees of Indebtedness of Others
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ASC 470
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ASC-470, Debt; incorporates:
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FSP APB 14-1, Accounting for
Convertible Debt Instruments That May Be Settled in Cash upon
Conversion (Including Partial Cash Settlement)
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ASC 715
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ASC-715, Compensation-Retirement Benefits; incorporates:
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FSP FAS 132(R)-1,
Employers Disclosures about Postretirement Benefit Plan
Assets
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SFAS No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement
Plans an amendment of FASB Statements No. 87, 88,
106 and 132 (R)
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ASC 718
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ASC-718, Compensation-Stock Compensation; incorporates:
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EITF 07-5, Determining Whether
an Instrument (or Embedded Feature) Is Indexed to an
Entitys Own Stock
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ASC 740
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ASC-740, Income Taxes; incorporates:
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FIN No. 48, Accounting for
Uncertainty in Income Taxes
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SFAS No. 109, Accounting for
Income Taxes
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APB Opinion No. 23 Accounting
for Income Taxes Special Areas
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7
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ASC 805
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ASC-805, Business Combinations; incorporates:
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SFAS 141(R), Business
Combinations
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FSP FAS 141(R)-1, Accounting
for Assets Acquired and Liabilities Assumed in a Business
Combination That Arise from Contingencies
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ASC 810
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ASC-810, Consolidation; incorporates:
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SFAS 160, Noncontrolling
Interests in Consolidated Financial Statements an
amendment of ARB No. 51, Consolidated Financial Statements
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ASC 815
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ASC-815, Derivatives and Hedging; incorporates:
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SFAS 161, Disclosures About
Derivative Instruments and Hedging Activities
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EITF 07-5, Determining Whether
an Instrument (or Embedded Feature) Is Indexed to an
Entitys Own Stock
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EITF 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes
and Contracts Involved in Energy Trading and Risk Management
Activities
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ASC 820
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ASC-820, Fair Value Measurements and Disclosures;
incorporates:
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FSP FAS 157-2, Effective Date
of FASB Statement No. 157
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FSP 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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EITF 08-5, Issuers
Accounting for Liabilities Measured at Fair Value with a
Third-Party Credit Enhancement
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ASC 825
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ASC-825, Financial Instruments; incorporates:
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FSP APB 14-1, Accounting for
Convertible Debt Instruments That May Be Settled in Cash upon
Conversion (Including Partial Cash Settlement)
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FSP FAS 107-1 and APB 28-1,
Interim Disclosures about Fair Value of Financial
Instruments
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ASC 852
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ASC-852, Reorganizations; incorporates:
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Statement of Position 90-7,
Financial Reporting by Entities in Reorganization Under the
Bankruptcy Code
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ASC 855
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ASC-855, Subsequent Events; incorporates:
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SFAS 165, Subsequent Events
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ASC 980
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ASC-980, Regulated Operations; incorporates:
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SFAS No. 71, Accounting for the
Effects of Certain Types of Regulation
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ASU 2009-5
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ASU 2009-5, Fair Value Measurement and Disclosures: Measuring
Liabilities at Fair Value
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ASU 2009-15
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ASU 2009-15, Accounting for Own-Share Lending Arrangements in
Contemplation of Convertible Debt Issuance or Other Financing;
incorporates:
|
|
|
EITF 09-1, Accounting for
Own-Share Lending Arrangements in Contemplation of Convertible
Debt Issuance or Other Financing
|
ASU 2009-17
|
|
ASU No. 2009-17, Consolidations: Improvements to Financial
Reporting by Enterprises Involved with Variable Interest
Entities; incorporates:
|
|
|
SFAS 167, Amendments to FASB
Interpretations No. 46 (R)
|
ASU 2010-02
|
|
ASU No. 2010-02, Consolidation (Topic 810): Accounting and
Reporting for Decreases in Ownership of a Subsidiarya
Scope Clarification
|
ASU 2010-06
|
|
ASU No. 2010-06, Fair Value Measurement and Disclosures:
Improving Disclosures about Fair Value Measurements
|
8
PART I
General
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 U.S., as well as a
major retail electricity franchise in the Electric Reliability
Council of Texas, or ERCOT, 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 U.S. and select international
markets, and the supply of electricity and energy services to
retail electricity customers in the Texas market.
As of December 31, 2009, NRG had a total global generation
portfolio of 187 active operating fossil fuel and nuclear
generation units, at 44 power generation plants, with an
aggregate generation capacity of approximately 24,115 MW,
and approximately 400 MW under construction which includes
partner interests of 200 MW. In addition to its fossil fuel
plant ownership, NRG has ownership interests in operating
renewable facilities with an aggregate generation capacity of
365 MW, consisting of three wind farms representing an
aggregate generation capacity of 345 MW (which includes
partner interest of 75 MW) and a solar facility with an
aggregate generation capacity of 20 MW. Within the U.S.,
NRG has large and diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 23,110 MW of fossil fuel and nuclear
generation capacity in 179 active generating units at 42 plants.
The Companys power generation facilities are most heavily
concentrated in Texas (approximately 11,340 MW, including
345 MW from three wind farms), the Northeast (approximately
7,015 MW), South Central (approximately 2,855 MW), and
West (approximately 2,150 MW, including 20 MW from a
solar farm) regions of the U.S., with approximately 115 MW
of additional generation capacity from the Companys
thermal assets. In addition, through certain foreign
subsidiaries, NRG has investments in power generation projects
located in Australia and Germany with approximately
1,005 MW of generation capacity.
NRGs principal domestic power plants consist of a mix of
natural gas-, coal-, oil-fired, nuclear and renewable
facilities, representing approximately 46%, 32%, 16%, 5% and 1%
of the Companys total domestic generation capacity,
respectively. In addition, 9% 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
the Merit Order, and include thermal energy production plants.
The sale of capacity and power from baseload generation
facilities accounts for the majority of the Companys
revenues and provides a stable source of cash flow. In addition,
NRGs generation portfolio provides the Company with
opportunities to capture additional revenues by selling power
during periods of peak demand, offering capacity or similar
products to retail electric providers and others, and providing
ancillary services to support system reliability.
On May 1, 2009, NRG acquired Reliant Energy, which is the
second largest electricity provider to residential and small
business, or Mass, customers in Texas. Reliant Energy is also
the largest electricity and energy services provider, based on
load, to commercial, industrial and governmental/institutions,
or C&I, customers in Texas. Based on metered locations, as
of December 31, 2009, Reliant Energy had approximately
1.5 million Mass customers and approximately
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.
Furthermore, NRG is focused on the development and investment in
energy-related new businesses and new technologies where the
benefits of such investments represent significant commercial
opportunities and create a comparative advantage for the
Company. These investments include low or no Greenhouse Gas, or
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.
9
NRGs
Business Strategy
NRGs business strategy is intended to maximize shareholder
value through production and the sale of safe, reliable and
affordable power to its customers and in the markets served by
the Company, while aggressively positioning the Company to meet
the markets increasing demand for sustainable and low
carbon energy solutions, such as nuclear, renewable, electric
vehicle and smart grid services. The Company believes that
success in providing energy solutions that address
sustainability and climate change concerns will not only reduce
the carbon and capital intensity of the Companys financial
performance in the future, it also will reduce the real and
perceived linkage between the Companys financial
performance and prospects, and volatile commodity prices
particularly natural gas.
In support of this strategy and NRGs core business
strengths, the Company will continue to maintain its focus and
execution 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) 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; and (v) pursuit of selective acquisitions,
joint ventures, divestitures and investments in energy-related
new businesses and new technologies in order to enhance the
Companys asset mix and competitive position in its core
markets, both with respect to its traditional core business and
in respect of opportunities associated with the new energy
economy.
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:
Operational Performance The Company is
focused on increasing value from its existing assets. Through
the FORNRG 2.0 initiative, NRG will continue its
companywide effort to focus on extracting value from its
portfolio by improving plant performance, reducing costs and
harnessing the Companys advantages of scale in the
procurement of fuels and other commodities, parts and services,
and in doing so improving the Companys return on invested
capital, or ROIC.
In addition to the FORNRG initiative, the Company seeks
to maximize profitability and manage cash flow volatility
through the Companys commercial operations strategy by
leveraging its: (i) expertise in marketing power and
ancillary services; (ii) its knowledge of markets;
(iii) its balanced financial structure; and (iv) its
diverse portfolio of power generation assets in the execution of
asset-based risk management, hedging, marketing and trading
strategies within well-defined risk and liquidity guidelines.
The Companys marketing and hedging philosophy is centered
on generating stable returns from its portfolio of baseload
power generation assets while preserving an ability to
capitalize on strong spot market conditions and to capture the
extrinsic value of the Companys intermediate and peaking
facilities and portions of its baseload fleet.
The Company also seeks to achieve synergies between the
Companys retail and wholesale business in Texas through
its complementary generation portfolio in the Texas region,
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, credit exposures, and collateral
postings. In addition, with Reliant Energys base of retail
customers, NRG now has a customer interface with the scale that
is important to the successful deployment of consumer-facing
energy technologies and services.
Finally, NRG remains focused on cash flow and maintaining
appropriate levels of liquidity, debt and equity in order to
ensure continued access, through all economic and financial
cycles, to capital for investment, to enhance risk-adjusted
returns and to provide flexibility in executing NRGs
business strategy, including a regular return of capital to its
debt and equity holders.
10
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, as well as
clean coal and the retrofit of post-combustion
carbon capture technologies. Primarily through the
RepoweringNRG and econrg initiatives, NRG intends to
invest in its existing assets through plant improvements,
repowerings, brownfield development and site expansions to meet
anticipated requirements for additional capacity in NRGs
core markets, with an emphasis on new capacity that is supported
by long-term power sales agreements and financed with limited or
non-recourse project financing, and the demonstration and
deployment of green technologies.
RepoweringNRG is a comprehensive portfolio redevelopment
program designed to develop, construct and operate new
multi-fuel, multi-technology, highly efficient and
environmentally responsible generation capacity in locations
where the Company anticipates retiring certain existing units
and adding new generation to meet growing demand in the
Companys core markets. econrg represents NRGs
commitment to environmentally responsible power generation by
addressing the challenges of climate change, clean air and
water, and conservation of natural resources while taking
advantage of business opportunities that may inure to NRG. 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 reduced
environmental impacts, including facilities that either have
near zero GHG emissions or can be equipped to capture and
sequester GHG emissions. In addition, 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 as well
as other government incentive packages. NRG has several
applications pending or contemplated.
New Businesses and New
Technology NRG is focused on the
development and investment in energy-related new businesses and
new technologies, including low or no GHG emitting energy
generating sources, such as nuclear, wind, solar thermal, and
photovoltaic, as well as other endeavors where the benefits of
such investments represent significant commercial opportunities
and create a comparative advantage for the Company, such as
smart meters, electric vehicle ecosystems, and distributed
clean solutions. The Company has made a series of
recent advancements in these initiatives, including:
(i) the acquisition of Bluewater Wind, an offshore wind
development company; (ii) the acquisition of Blythe Solar,
the largest photovoltaic solar power facility in California;
(iii) the commercial operation of the Langford Wind Farm,
the Companys third wind farm to be brought online;
(iv) a partnership between Reliant Energy and the City of
Houston and a partnership between Reliant Energy and Nissan to
make Houston, Texas a launch city for the use of electric
vehicles; and (v) the use of smart meters for
Reliant Energy customers. Furthermore, the Company, supported by
the econrg initiative, intends to capitalize on the high growth
opportunities presented by government-mandated renewable
portfolio standards, tax incentives and loan guaranties for
renewable energy projects, and new technologies and expected
future carbon regulation.
Company-Wide
Initiatives In addition, the
Companys overall strategy is also supported by Future NRG
and NRG Global Giving initiatives. Future NRG is the
Companys workforce planning and development initiative and
represents NRGs strong commitment to planning for future
staffing requirements to meet the on-going needs of the
Companys current operations and initiatives. NRG Global
Giving is designed to enhance respect for the community, which
is one of NRGs core values. The Global Giving Program
invests NRGs resources to strengthen the communities where
NRG does business and seeks to make community investments in
four focus areas: community and economic development, education,
environment and human welfare.
Competition
Wholesale power generation is a capital-intensive,
commodity-driven business with numerous industry participants.
NRG competes on the basis of the location of its plants and
ownership of multiple plants in various regions, which increases
the stability and reliability of its energy supply. Wholesale
power generation is basically a local business that is currently
highly fragmented relative to other commodity industries and
diverse in terms of industry structure. As such, there is a wide
variation in terms of the capabilities, resources, nature and
identity of the companies NRG competes with depending on the
market.
The deregulated retail energy business in ERCOT is a competitive
business. In general, competition in the retail energy business
is on the basis of price, service, brand image, product
offerings and market perceptions of
11
creditworthiness. Reliant Energy sells electricity pursuant to
fixed price or indexed products, and customers elect terms of
service typically ranging from one month to five years. Reliant
Energys rates are market-based rates, and not subject to
traditional
cost-of-service
regulation by the Public Utility Commission of Texas, or PUCT.
Non-affiliated transmission and distribution service companies
provide, on a non-discriminatory basis, the wires and metering
services necessary to access customers.
Competitive
Strengths
Scale and diversity of assets NRG has one of
the largest and most diversified power generation portfolios in
the U.S., with approximately 23,110 MW of fossil fuel and
nuclear generation capacity in 179 active generating units at 42
plants and 365 MW renewable generation capacity which
consists of ownership interests in three wind farms and a solar
facility as of December 31, 2009. The Companys power
generation assets are diversified by fuel-type, dispatch level
and region, which help mitigate the risks associated with fuel
price volatility and market demand cycles. As of
December 31, 2009, the Companys power generation
assets consisted of approximately 10,660 MW of gas-fired;
7,560 MW of coal-fired; 3,715 MW of oil-fired;
1,175 MW of nuclear and 365 MW of renewable generating
capacity in the U.S.
NRG has a significant power generation presence in major
competitive power markets of the U.S. as set forth in the
map below:
|
|
|
(1)
|
|
Includes 115 MW as part of
NRGs Thermal assets. For combined scale, approximately
2,095 MW is dual-fuel capable. Reflects only domestic
generation capacity as of December 31, 2009.
|
The Companys U.S. power generation portfolio by
dispatch level is comprised of approximately 37% baseload, 37%
intermediate, 25% peaking and 1% intermittent units. NRGs
U.S. baseload facilities, which consist of approximately
8,735 MW of generation capacity measured as of
December 31, 2009, provide the Company with a significant
source of stable cash flow, while its intermediate and peaking
facilities, with approximately 14,375 MW of generation
capacity as of December 31, 2009, provide NRG with
opportunities to capture the significant upside potential that
can arise from time to time during periods of high demand. In
addition, approximately 9% of the Companys domestic
generation facilities have dual or multiple fuel capability,
12
which allows most of these plants to dispatch with the lowest
cost fuel option. In 2009, NRG completed the construction of the
Cedar Bayou Generating Station (520 MW including partner
interests of 260 MW) and the Langford wind farm
(150 MW), which provide electricity to the Companys
core region. In addition, the Company acquired Blythe Solar
(20 MW) in November 2009, which provides electricity to the
Companys West region.
The following chart demonstrates the diversification of
NRGs domestic power generation assets as of
December 31, 2009:
|
|
|
|
|
Approximate North America
Portfolio Net Capacity by Fuel
Type
|
|
Approximate North America
Portfolio Net Capacity by Dispatch
Level
|
|
Approximate North America
Portfolio Net Capacity by
Region
|
Reliability of future cash flows NRG has
hedged a significant portion of its expected baseload generation
capacity with decreasing hedged levels through 2014. NRG also
has cooperative load contract obligations in South Central
region which expire over various dates through 2026. The Company
has the capacity and intent to enter into additional hedges when
market conditions are favorable. In addition, as of
December 31, 2009, the Company had purchased fuel forward
under fixed price contracts, with contractually-specified price
escalators, for approximately 47% of its expected baseload coal
requirement from 2010 to 2014. The hedge percentage is
reflective of the current agreement of the Jewett mine in which
NRG has the contractual ability to adjust volumes in future
years. These forward positions provide a stable and reliable
source of future cash flow for NRGs investors, while
preserving a portion of its generation portfolio for
opportunistic sales to take advantage of market dynamics.
With its complementary generation portfolio, the Texas region is
a supplier of power to Reliant Energy, thereby creating the
potential for more stable, reliable cash flows. 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
lower transaction costs and credit exposures. This combination
of generation and retail allows for a reduction in actual and
contingent collateral, initially through offsetting transactions
and over time by reducing the need to hedge the retail power
supply through third parties.
Favorable cost dynamics for baseload power plants
In 2009, approximately 87% of the Companys domestic
generation output was from plants fueled by coal or nuclear
fuel. In many of the competitive markets where NRG operates, the
price of power is typically set by the marginal costs of natural
gas-fired and oil-fired power plants that historically have
higher variable costs than solid-fuel baseload power plants. As
a result of NRGs lower marginal cost for baseload coal and
nuclear generation assets, the Company expects the baseload
assets in ERCOT to generate power the majority of the time they
are available.
Locational advantages Many of NRGs
generation assets are located within densely populated areas
that are characterized by significant constraints on the
transmission of power from generators outside the particular
region. Consequently, these assets are able to benefit from the
higher prices that prevail for energy in these markets during
periods of transmission constraints. NRG has generation assets
located within Houston, New York City, southwestern Connecticut
and the Los Angeles and San Diego load basins; all areas
which experience, from
time-to-time
and to varying degrees, of constraints on the transmission of
electricity. This gives the Company the opportunity to capture
additional revenues by offering capacity to retail electric
providers and others, selling power at prevailing market prices
during periods of peak demand and providing ancillary services
in support of system
13
reliability. Also, these facilities are often ideally situated
for repowering or the addition of new capacity, because their
location and existing infrastructure give them significant
advantages over developed sites in their regions that do not
have process infrastructure.
Performance
Metrics
The following table contains a summary of NRGs operating
revenues by segment for the years ended December 31, 2009,
2008 and 2007, as discussed in Item 14
Note 18, Segment Reporting, to the Consolidated
Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Energy
|
|
|
Capacity
|
|
|
Retail
|
|
|
Management
|
|
|
Contract
|
|
|
Thermal
|
|
|
Other
|
|
|
Operating
|
|
|
|
|
Region
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Activities
|
|
|
Amortization
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
|
|
|
|
(In millions)
|
|
|
Reliant
Energy(a)
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,440
|
|
|
$
|
|
|
|
$
|
(258)
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
4,182
|
|
|
|
|
|
Texas
|
|
|
2,439
|
|
|
|
193
|
|
|
|
|
|
|
|
229
|
|
|
|
57
|
|
|
|
|
|
|
|
28
|
|
|
|
2,946
|
|
|
|
|
|
Northeast
|
|
|
489
|
|
|
|
407
|
|
|
|
|
|
|
|
277
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
1,201
|
|
|
|
|
|
South Central
|
|
|
360
|
|
|
|
269
|
|
|
|
|
|
|
|
(71)
|
|
|
|
22
|
|
|
|
|
|
|
|
1
|
|
|
|
581
|
|
|
|
|
|
West
|
|
|
34
|
|
|
|
122
|
|
|
|
|
|
|
|
(8)
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
150
|
|
|
|
|
|
International
|
|
|
52
|
|
|
|
79
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
144
|
|
|
|
|
|
Thermal
|
|
|
7
|
|
|
|
7
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
100
|
|
|
|
17
|
|
|
|
135
|
|
|
|
|
|
Corporate and Eliminations
|
|
|
(350
|
)
|
|
|
(47)
|
|
|
|
|
|
|
|
(13)
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
(387)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
3,031
|
|
|
$
|
1,030
|
|
|
$
|
4,440
|
|
|
$
|
418
|
|
|
$
|
(179)
|
|
|
$
|
100
|
|
|
$
|
112
|
|
|
$
|
8,952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
For the period May 1, 2009 to
December 31, 2009.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
Risk
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Energy
|
|
|
Capacity
|
|
|
Management
|
|
|
Contract
|
|
|
Thermal
|
|
|
Other
|
|
|
Operating
|
|
|
|
|
Region
|
|
Revenues
|
|
|
Revenues
|
|
|
Activities
|
|
|
Amortization
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
|
|
|
|
(In millions)
|
|
|
Texas
|
|
$
|
2,870
|
|
|
$
|
493
|
|
|
$
|
318
|
|
|
$
|
255
|
|
|
$
|
|
|
|
$
|
90
|
|
|
$
|
4,026
|
|
|
|
|
|
Northeast
|
|
|
1,064
|
|
|
|
415
|
|
|
|
85
|
|
|
|
|
|
|
|
|
|
|
|
66
|
|
|
|
1,630
|
|
|
|
|
|
South Central
|
|
|
478
|
|
|
|
233
|
|
|
|
10
|
|
|
|
23
|
|
|
|
|
|
|
|
2
|
|
|
|
746
|
|
|
|
|
|
West
|
|
|
39
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
171
|
|
|
|
|
|
International
|
|
|
56
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
158
|
|
|
|
|
|
Thermal
|
|
|
12
|
|
|
|
7
|
|
|
|
5
|
|
|
|
|
|
|
|
114
|
|
|
|
16
|
|
|
|
154
|
|
|
|
|
|
Corporate and Eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,519
|
|
|
$
|
1,359
|
|
|
$
|
418
|
|
|
$
|
278
|
|
|
$
|
114
|
|
|
$
|
197
|
|
|
$
|
6,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
Risk
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
Energy
|
|
|
Capacity
|
|
|
Management
|
|
|
Contract
|
|
|
Thermal
|
|
|
Other
|
|
|
Operating
|
|
|
|
|
Region
|
|
Revenues
|
|
|
Revenues
|
|
|
Activities
|
|
|
Amortization
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
|
|
|
|
(In millions)
|
|
|
Texas
|
|
$
|
2,698
|
|
|
$
|
363
|
|
|
$
|
(33)
|
|
|
$
|
219
|
|
|
$
|
|
|
|
$
|
40
|
|
|
$
|
3,287
|
|
|
|
|
|
Northeast
|
|
|
1,104
|
|
|
|
402
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
|
72
|
|
|
|
1,605
|
|
|
|
|
|
South Central
|
|
|
404
|
|
|
|
221
|
|
|
|
10
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
658
|
|
|
|
|
|
West
|
|
|
4
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
127
|
|
|
|
|
|
International
|
|
|
42
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
140
|
|
|
|
|
|
Thermal
|
|
|
13
|
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
125
|
|
|
|
16
|
|
|
|
159
|
|
|
|
|
|
Corporate and Eliminations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
4,265
|
|
|
$
|
1,196
|
|
|
$
|
4
|
|
|
$
|
242
|
|
|
$
|
125
|
|
|
$
|
157
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
In understanding NRGs wholesale generation business, the
Company believes that certain performance metrics are
particularly important. These are industry statistics defined by
the North American Electric Reliability Council, or NERC, and
are more fully described below:
Annual Equivalent Availability Factor, or EAF
Measures the percentage of maximum generation available over
time as the fraction of net maximum generation that could be
provided over a defined period of time after all types of
outages and deratings, including seasonal deratings, are taken
into account.
Net heat rate The net heat rate for the
Companys fossil-fired power plants represents the total
amount of fuel in BTU required to generate one net kWh provided.
Net Capacity Factor The net amount of
electricity that a generating unit produces over a period of
time divided by the net amount of electricity it could have
produced if it had run at full power over that time period. The
net amount of electricity produced is the total amount of
electricity generated minus the amount of electricity used
during generation.
In addition, the Company believes that retail customer counts
and weighted average retail customer counts are particularly
important performance metrics when evaluating this segment. For
further results of Reliant Energys business metrics see
Item 6 Managements Discussion and
Analysis of Financial Conditions and Results of Operation.
The tables below present the North American power generation
performance metrics for the Companys power plants
discussed above for the years ended December 31, 2009, and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
Net
|
|
Equivalent
|
|
Average Net
|
|
|
|
|
Net Owned
|
|
Generation
|
|
Availability
|
|
Heat Rate
|
|
Net Capacity
|
Region
|
|
Capacity (MW)
|
|
(MWh)
|
|
Factor
|
|
Btu/kWh
|
|
Factor
|
|
|
(In thousands of MWh)
|
|
Texas(a)
|
|
|
11,340
|
|
|
|
44,993
|
|
|
|
88.2
|
%
|
|
|
10,200
|
|
|
|
38.4
|
%
|
Northeast(b)
|
|
|
7,015
|
|
|
|
9,220
|
|
|
|
89.2
|
|
|
|
10,900
|
|
|
|
13.5
|
|
South Central
|
|
|
2,855
|
|
|
|
10,398
|
|
|
|
89.6
|
|
|
|
10,500
|
|
|
|
41.1
|
|
West
|
|
|
2,150
|
|
|
|
1,279
|
|
|
|
86.5
|
%
|
|
|
12,300
|
|
|
|
8.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
Net
|
|
Equivalent
|
|
Average Net
|
|
|
|
|
Net Owned
|
|
Generation
|
|
Availability
|
|
Heat Rate
|
|
Net Capacity
|
Region
|
|
Capacity (MW)
|
|
(MWh)
|
|
Factor
|
|
Btu/kWh
|
|
Factor
|
|
|
(In thousands of MWh)
|
|
Texas(a)
|
|
|
11,010
|
|
|
|
46,937
|
|
|
|
88.1
|
%
|
|
|
10,300
|
|
|
|
49.6
|
%
|
Northeast(b)
|
|
|
7,202
|
|
|
|
13,349
|
|
|
|
88.8
|
|
|
|
10,800
|
|
|
|
19.9
|
|
South Central
|
|
|
2,845
|
|
|
|
11,148
|
|
|
|
93.4
|
|
|
|
10,300
|
|
|
|
47.6
|
|
West
|
|
|
2,130
|
|
|
|
1,532
|
|
|
|
91.5
|
%
|
|
|
11,800
|
|
|
|
10.2
|
%
|
|
|
|
(a)
|
|
Net generation (MWh) does not
include Sherbino I Wind Farm LLC, which is accounted for under
the equity method.
|
(b)
|
|
Factor data and heat rate do not
include the Keystone and Conemaugh facilities.
|
Employees
As of December 31, 2009, NRG had 4,607 employees,
approximately 1,640 of whom were covered by U.S. bargaining
agreements. During 2009, the Company did not experience any
labor stoppages or labor disputes at any of its facilities. The
increase in the number of employees is primarily due to the
Companys acquisition of Reliant Energy in May 2009.
Commercial
Operations Overview
NRG seeks to maximize profitability and manage cash flow
volatility through the marketing, trading and sale of energy,
capacity and ancillary services into spot, intermediate and
long-term markets and through the active management and trading
of emissions allowances, fuel supplies and
transportation-related services. The Companys
15
principal objectives are the realization of the full market
value of its asset base, including the capture of its extrinsic
value, the management and mitigation of commodity market risk
and the reduction of cash flow volatility over time.
NRG enters into power sales and hedging arrangements via a wide
range of products and contracts, including power purchase
agreements, fuel supply contracts, capacity auctions, natural
gas swap agreements and other financial instruments. The PPAs
that NRG enters into require the Company to deliver MWh of power
to its counterparties. In addition, because changes in power
prices in the markets where NRG operates are generally
correlated to changes in natural gas prices, NRG uses hedging
strategies which may include power and natural gas forward sales
contracts to manage the commodity price risk primarily
associated with the Companys baseload generation assets.
The objective of these hedging strategies is to stabilize the
cash flow generated by NRGs portfolio of assets.
The following table summarizes NRGs U.S. baseload
capacity and the corresponding revenues and average natural gas
prices resulting from baseload hedge agreements extending beyond
December 31, 2010, and through 2014:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average for
|
|
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2010-2014
|
|
|
|
|
(Dollars in millions unless otherwise stated)
|
|
Net Baseload Capacity
(MW) (a)
|
|
|
8,557
|
|
|
|
8,477
|
|
|
|
8,450
|
|
|
|
8,450
|
|
|
|
8,295
|
|
|
|
8,446
|
|
|
|
|
|
Forecasted Baseload Capacity
(MW) (b)
|
|
|
7,217
|
|
|
|
7,065
|
|
|
|
7,272
|
|
|
|
7,268
|
|
|
|
7,138
|
|
|
|
7,192
|
|
|
|
|
|
Total Baseload Sales
(MW)(c)(h)
|
|
|
7,175
|
|
|
|
4,882
|
|
|
|
3,229
|
|
|
|
1,951
|
|
|
|
797
|
|
|
|
3,607
|
|
|
|
|
|
Percentage Baseload Capacity Sold
Forward(d)
|
|
|
99%
|
|
|
|
69%
|
|
|
|
44%
|
|
|
|
27%
|
|
|
|
11%
|
|
|
|
50
|
%
|
|
|
|
|
Total Forward Hedged
Revenues(e)(f)(g)
|
|
$
|
3,535
|
|
|
$
|
2,246
|
|
|
$
|
1,688
|
|
|
$
|
944
|
|
|
$
|
345
|
|
|
$
|
1,752
|
|
|
|
|
|
Weighted Average Hedged Price ($ per
MWh)(e)
|
|
$
|
56
|
|
|
$
|
53
|
|
|
$
|
60
|
|
|
$
|
55
|
|
|
$
|
49
|
|
|
$
|
55
|
|
|
|
|
|
Weighted Average Hedged Price ($ per MWh) excluding South
Central
region(f)
|
|
$
|
59
|
|
|
$
|
55
|
|
|
$
|
68
|
|
|
$
|
71
|
|
|
$
|
|
|
|
$
|
60
|
|
|
|
|
|
Average Equivalent Natural Gas Price ($ per MMBtu)
|
|
$
|
7.57
|
|
|
$
|
7.15
|
|
|
$
|
7.91
|
|
|
$
|
7.44
|
|
|
$
|
7.18
|
|
|
$
|
7.49
|
|
|
|
|
|
Average Equivalent Natural Gas Price ($ per MMBtu) excluding
South Central region
|
|
$
|
7.67
|
|
|
$
|
7.18
|
|
|
$
|
8.51
|
|
|
$
|
8.71
|
|
|
$
|
|
|
|
$
|
7.73
|
|
|
|
|
|
|
|
|
(a)
|
|
Nameplate capacity net of station
services reflecting unit retirement schedule.
|
(b)
|
|
Expected generation dispatch output
(MWh) based on budget forward price curve, which is then divided
by 8,760 hours (8,784 hours in 2012) to arrive at
MW capacity. The dispatch takes into account planned and
unplanned outage assumptions.
|
(c)
|
|
Includes amounts under power sales
contracts and natural gas hedges. The forward natural gas
quantities are reflected in equivalent MWh based on forward
market implied heat rate as of December 31, 2009 and then
combined with power sales to arrive at equivalent MWh hedged
which is then divided by 8,760 hours (8,784 hours in
2012) to arrive at MW hedged.
|
(d)
|
|
Percentage hedged is based on total
MW sold as power and natural gas converted using the method as
described in (c) above divided by the forecasted baseload
capacity.
|
(e)
|
|
Represents all North American
baseload sales, including energy revenue and demand charges.
|
(f)
|
|
The South Central regions
weighted average hedged prices ranges from $43/MWh
$50/MWh. These prices include demand charges and an estimated
energy charge.
|
(g)
|
|
Include frozen OCI primarily from
Merrill Lynch CSRA sleeve unwind.
|
(h)
|
|
Include the inter-company sales
from wholesale business to Reliant Energys retail business.
|
Reliant Energy sells electricity on fixed price or indexed
products, and these contracts have terms typically ranging from
one month to five years. In a typical year, the Company sells
approximately 50 TWh of load (comprised of approximately 40% to
Mass customers and approximately 60% to C&I customers), but
this amount can be affected by weather, economic conditions and
competition. The wholesale supply is typically purchased as the
load is contracted in order to secure profit margin. The
wholesale supply is purchased from a combination of NRGs
wholesale portfolio and other third parties, depending on the
existing hedge position for the NRG wholesale portfolio at the
time.
Capacity
Revenue Sources
NRG revenues and free cash flows benefit from capacity/demand
payments originating from either market clearing capacity
prices, Reliability Must-Run, or RMR, Resource Adequacy, or RA,
contracts and tolling arrangements as many of NRGs plants
are well situated within load pockets and make critical
contributions to system stability. Specifically, in the
Northeast, the Companys largest sources for capacity
revenues are derived
16
either from market capacity auctions including New York, PJM
Interconnection LLC, or PJM and New England auctions
and/or RMRs.
In South Central, NRG earns significant capacity revenue from
its long-term full-requirements load contracts with 10 Louisiana
distribution cooperatives, which are not unit specific. Of the
ten contracts, seven expire in 2025 and account for 50% of the
contract load, while the remaining three expire in 2014 and
comprise 40% of contract load. Capacity revenues from these long
terms contracts are tied to summer peak demand as well as
provide a mechanism for recovering a portion of the costs for
mandated environmental projects over the remaining life of the
contract. In West, most of the Companys sites benefit from
either tolling agreements
and/or RA
contracts. Texas, does not have a capacity market; Texas
capacity revenues reflect bilateral transactions. Prior to
NRGs acquisition of Texas Genco, the PUCT regulations
required that Texas generators sell 15% of their capacity by
auction at reduced rates. The Company was subsequently released
from this obligation and the legacy capacity contracts expired
in 2009. See each of the Regional Business Descriptions
Market Framework below for further discussion of the plants
and relevant capacity revenue eligibility.
Fuel
Supply and Transportation
NRGs fuel requirements consist primarily of nuclear fuel
and various forms of fossil fuel including oil, natural gas and
coal, including lignite. The prices of oil, natural gas and coal
are subject to macro- and micro-economic forces that can change
dramatically in both the short- and long-term. The Company
obtains its oil, natural gas and coal from multiple suppliers
and transportation sources. Although availability is generally
not an issue, localized shortages, transportation availability
and supplier financial stability issues can and do occur. The
preceding factors related to the sources and availability of raw
materials are fairly uniform across the Companys business
segments.
Coal The Company is largely
hedged for its domestic coal consumption over the next few
years. Coal hedging is dynamic and is based on forecasted
generation and market volatility. As of December 31, 2009,
NRG had purchased forward contracts to provide fuel for
approximately 47% of the Companys requirements from 2010
through 2014. NRG arranges for the purchase, transportation and
delivery of coal for the Companys baseload coal plants via
a variety of coal purchase agreements, rail/barge transportation
agreements and rail car lease arrangements. The Company
purchased approximately 34 million tons of coal in 2009, of
which 96% is Powder River Basin coal and lignite. The Company is
one of the largest coal purchasers in the U.S.
The following table shows the percentage of the Companys
coal and lignite requirements from 2010 through 2014 that have
been purchased forward:
|
|
|
|
|
|
|
Percentage of
|
|
|
Companys
|
|
|
Requirement(a)(b)
|
|
2010
|
|
|
93
|
%
|
2011
|
|
|
60
|
%
|
2012
|
|
|
51
|
%
|
2013
|
|
|
15
|
%
|
2014
|
|
|
16
|
%
|
|
|
|
(a)
|
|
The hedge percentages reflect the
current plan for the Jewett mine. NRG has the contractual
ability to change volumes and may do so in the future.
|
(b)
|
|
Does not include coal inventory.
|
As of December 31, 2009, NRG had approximately 6,280
privately leased or owned rail cars in the Companys
transportation fleet. NRG has entered into rail transportation
agreements with varying tenures that provide for substantially
all of the Companys rail transportation requirements up to
the next five years.
Natural Gas NRG operates a fleet
of natural gas plants in the Texas, Northeast, South Central and
West regions which are primarily comprised of peaking assets
that run in times of high power demand. Due to the uncertainty
of their dispatch, the fuel needs are managed on a spot basis as
it is not prudent to forward purchase fixed price natural gas
for units that may not run. The Company contracts for natural
gas storage services as well as natural gas transportation
services to ensure delivery of natural gas when needed.
Nuclear Fuel South Texas
Projects, or STPs, owners satisfy STPs fuel
supply requirements by: (i) acquiring uranium concentrates
and contracting for conversion of the uranium concentrates into
uranium
17
hexafluoride; (ii) contracting for enrichment of uranium
hexafluoride; and (iii) contracting for fabrication of
nuclear fuel assemblies. NRG is party to a number of long-term
forward purchase contracts with many of the worlds largest
suppliers covering STP requirements for uranium and conversion
services for the next five years, and with substantial portions
of STPs requirements procured thereafter. NRG is party to
long-term contracts to procure STPs requirements for
enrichment services and fuel fabrication for the life of the
operating license.
Seasonality
and Price Volatility
Annual and quarterly operating results of the Companys
wholesale power generation segments can be significantly
affected by weather and energy commodity price volatility.
Significant other events, such as the demand for natural gas,
interruptions in fuel supply infrastructure and relative levels
of hydroelectric capacity can increase seasonal fuel and power
price volatility. NRG derives a majority of its annual revenues
in the months of May through October, when demand for
electricity is at its highest in the Companys core
domestic markets. Further, power price volatility is generally
higher in the summer months, traditionally NRGs most
important season. The Companys second most important
season is the winter months of December through March when
volatility and price spikes in underlying delivered fuel prices
have tended to drive seasonal electricity prices. The preceding
factors related to seasonality and price volatility are fairly
uniform across the Companys wholesale generation business
segments.
The sale of electric power to retail customers is also a
seasonal business with the demand for power peaking during the
summer months. Weather may impact operating results and extreme
weather conditions could materially affect results of
operations. The rates charged to retail customers may be
impacted by fluctuations in the price of natural gas,
transmission constraints, competition, and changes in market
heat rates.
Regional
Business Descriptions
NRG is organized into business segments, with each of the
Companys core regions operating as a separate business
segment as discussed below.
RELIANT
ENERGY
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, and maintains call centers to provide customer service. In
addition, Reliant Energy is focused on developing innovative
energy solutions including the infrastructure for electric
vehicles and energy efficiency tools and services for consumers
to manage their energy usage. NRG presently purchases a
substantial portion of Reliant Energys supply requirements
from third parties such as generation companies and power
marketers and has begun the process of becoming the primary
provider for their supply requirements. 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.
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 1.5 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.
|
|
|
|
C&I 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.
|
18
Market
Framework
In the ERCOT market, Reliant Energy is certified by the PUCT as
a retail energy provider, or REP, to contract with end-users to
sell electricity and provide other value enhancing services. In
addition, Reliant Energy contracts with transmission and
distribution service providers, or TDSPs, to arrange for
transportation to the customer. Reliant Energy activities in
Texas are subject to standards and regulations adopted by the
PUCT and ERCOT. Reliant Energy operates within the same ERCOT
market as the Companys Texas region. For further
discussion of the Texas market framework, which includes overall
market structure in addition to items specific to the generation
business, see Texas region Market Framework discussion, below.
For further discussion of the Companys Reliant Energy
operations, see Item 14 Note 3,
Business Acquisitions, to the Consolidated Financial
Statements.
TEXAS
NRGs largest business segment is located in Texas and is
comprised of investments in generation facilities located in the
physical control areas of the ERCOT market. As of
December 31, 2009, NRGs generation assets in the
Texas region consisted of approximately 5,355 MW of
baseload generation assets, approximately 345 MW of
intermittent wind generation assets, excluding partner interests
of 75 MW, in addition to approximately 5,640 MW of
intermediate and peaking natural gas-fired assets. NRG realizes
a substantial portion of its revenue and cash flow from the sale
of power from the Companys three baseload power plants
located in the ERCOT market that use solid-fuel: W.A. Parish
which uses coal, Limestone which use lignite and coal, and an
undivided 44% interest in two nuclear generating units at STP.
In addition, in June 2009, NRG completed construction and began
commercial operations of the 520 MW Cedar Bayou 4 natural
gas-fueled combined cycle generating plant at NRGs Cedar
Bayou Generating Station in Chambers County, Texas, of which NRG
holds a 50% undivided interest. Also in 2009, NRG completed
construction and began commercial operations of the 150 MW
Langford wind farm located in west Texas. Both Cedar Bayou 4 and
Langford are located in the ERCOT market. Power plants are
generally dispatched in order of lowest operating cost and as of
December 2009, approximately 59% of the net generation capacity
in the ERCOT market was natural gas-fired. Generally, NRGs
three solid-fuel baseload facilities and three wind farms have
significantly lower operating costs than natural gas plants. NRG
expects these three solid-fuel facilities to operate the
majority of the time when available, subject to planned and
forced outages.
Operating
Strategy
NRGs operating strategy to maximize value and opportunity
across these assets is to (i) ensure the availability of
the baseload plants to fulfill their commercial obligations
under long-term forward sales contracts already in place;
(ii) manage the natural gas assets for profitability while
ensuring the reliability and flexibility of power supply to the
Houston market; (iii) take advantage of the skill sets and
market or regulatory knowledge to grow the business through
incremental capacity uprates and repowering development of
solid-fuel baseload and gas-fired units; and (iv) play a
leading role in the development of the ERCOT market by active
membership and participation in market and regulatory issues.
NRGs strategy is to sell forward a majority of its
solid-fuel baseload capacity in the ERCOT market under long-term
contracts or to enter into hedges by using natural gas as a
proxy for power prices. Accordingly, the Companys primary
focus will be to keep these solid-fuel baseload units running
efficiently. With respect to gas-fired assets, NRG will continue
contracting forward a significant portion of gas-fired capacity
one to two years out while holding a portion for
back-up in
case there is an operational issue with one of the baseload
units and to provide upside for expanding heat rates. For the
gas-fired capacity sold forward, the Company will offer a range
of products specific to customers needs. For the gas-fired
capacity that NRG will continue to sell commercially into the
market, the Company will focus on making this capacity available
to the market whenever it is economical to run.
19
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
30,023
|
|
|
|
32,825
|
|
|
|
32,648
|
|
|
|
|
|
Gas(a)
|
|
|
5,224
|
|
|
|
4,647
|
|
|
|
5,407
|
|
|
|
|
|
Nuclear(b)
|
|
|
9,396
|
|
|
|
9,456
|
|
|
|
9,724
|
|
|
|
|
|
Wind
|
|
|
350
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
44,993
|
|
|
|
46,937
|
|
|
|
47,779
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
MWh information reflects the
undivided interest in total MWh generation from Cedar Bayou 4
beginning June 2009.
|
(b)
|
|
MWh information reflects the
undivided interest in total MWh generated by STP.
|
Generation
Facilities
As of December 31, 2009, NRGs generation facilities
in Texas consisted of approximately 11,340 MW of generation
capacity. The following table describes NRGs electric
power generation plants and generation capacity as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)(c)
|
|
|
Fuel-type
|
|
Solid-Fuel Baseload Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A.
Parish(a)
|
|
Thompsons, TX
|
|
|
100.0
|
|
|
|
2,490
|
|
|
|
Coal
|
|
Limestone
|
|
Jewett, TX
|
|
|
100.0
|
|
|
|
1,690
|
|
|
|
Lignite/Coal
|
|
South Texas
Project(b)
|
|
Bay City, TX
|
|
|
44.0
|
|
|
|
1,175
|
|
|
|
Nuclear
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Solid-Fuel Baseload
|
|
|
|
|
|
|
|
|
5,355
|
|
|
|
|
|
Intermittent Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Elbow Creek
|
|
Howard County, TX
|
|
|
100.0
|
|
|
|
120
|
|
|
|
Wind
|
|
Sherbino
|
|
Pecos County, TX
|
|
|
50.0
|
|
|
|
75
|
|
|
|
Wind
|
|
Langford
|
|
Christoval, TX
|
|
|
100.0
|
|
|
|
150
|
|
|
|
Wind
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Intermittent Baseload
|
|
|
|
|
|
|
|
|
345
|
|
|
|
|
|
Operating Natural Gas-Fired Units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cedar Bayou
|
|
Baytown, TX
|
|
|
100.0
|
|
|
|
1,495
|
|
|
|
Natural Gas
|
|
Cedar Bayou 4
|
|
Baytown, TX
|
|
|
50.0
|
|
|
|
260
|
|
|
|
Natural Gas
|
|
T. H. Wharton
|
|
Houston, TX
|
|
|
100.0
|
|
|
|
1,025
|
|
|
|
Natural Gas
|
|
W. A.
Parish(a)
|
|
Thompsons, TX
|
|
|
100.0
|
|
|
|
1,175
|
|
|
|
Natural Gas
|
|
S. R. Bertron
|
|
Deer Park, TX
|
|
|
100.0
|
|
|
|
765
|
|
|
|
Natural Gas
|
|
Greens Bayou
|
|
Houston, TX
|
|
|
100.0
|
|
|
|
760
|
|
|
|
Natural Gas
|
|
San Jacinto
|
|
LaPorte, TX
|
|
|
100.0
|
|
|
|
160
|
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Natural Gas-Fired
|
|
|
|
|
|
|
|
|
5,640
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Operating Capacity
|
|
|
|
|
|
|
|
|
11,340
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
W. A. Parish has nine units, four
of which are baseload coal-fired units and five of which are
natural gas-fired units.
|
(b)
|
|
Generation capacity figure consists
of the Companys 44.0% undivided interest in the two units
at STP.
|
(c)
|
|
Actual capacity can vary depending
on factors including weather conditions, operational conditions
and other factors. The ERCOT requires periodic demonstration of
capability, and the capacity may vary individually and in the
aggregate from time to time.
|
The following is a description of NRGs most significant
revenue generating plants in the Texas region:
W.A. Parish NRGs W.A. Parish plant is
one of the largest fossil-fired plants in the U.S. based on
total MWs of generation capacity. This plants power
generation units include four coal-fired steam generation units
with an aggregate generation capacity of 2,490 MW as of
December 31, 2009. Two of these units are 650 MW and
655 MW steam units that were placed in commercial service
in December 1977 and December 1978, respectively. The other two
units are 575 MW and 610 MW steam units that were
placed in commercial service in June 1980 and December 1982,
respectively. Each of the four coal-fired units have
low-NOx
burners and Selective Catalytic Reduction
20
systems, or SCRs, installed to reduce
NOx
emissions and baghouses to reduce particulates. In addition,
W.A. Parish Unit 8 has a scrubber installed to reduce
SO2
emissions.
Limestone NRGs Limestone plant is a
lignite and coal-fired plant located approximately
140 miles northwest of Houston. This plant includes two
steam generation units with an aggregate generation capacity of
1,690 MW as of December 31, 2009. The first unit is an
830 MW steam unit that was placed in commercial service in
1985. The second unit is an 860 MW steam unit that was
placed in commercial service in December 1986. Limestone burns
lignite from an adjacent mine, but also burns low sulfur coal
and petroleum coke. This serves to lower average fuel costs by
eliminating fuel transportation costs, which can represent up to
two-thirds of delivered fuel costs for plants of this type. Both
units have installed
low-NOx
burners to reduce
NOx
emissions and scrubbers to reduce
SO2
emissions.
The lignite used to fuel the Texas regions Limestone
facility is obtained from a surface mine, or the Jewett mine,
adjacent to the Limestone facility under a long-term contract
with Texas Westmoreland Coal Co., or TWCC. The contract is based
on a cost-plus arrangement with incentives and penalties to
ensure proper management of the mine. NRG has the flexibility to
increase or decrease lignite purchases with adequate notice. The
mining period was extended through 2018 with an option to extend
the mining period by two five-year intervals. The agreement
ensures lignite supply to NRG and confirms NRGs
responsibility for the final reclamation at the mine. Subject to
the terms of the contract, NRG has the ability to step in and
operate the mine under certain circumstances.
STP Electric Generating Station STP is one of
the newest and largest nuclear-powered generation plants in the
U.S. based on total megawatts of generation capacity. This
plant is located approximately 90 miles south of downtown
Houston, near Bay City, Texas and consists of two generation
units each representing approximately 1,335 MW of
generation capacity. STPs two generation units commenced
operations in August 1988 and June 1989, respectively. For the
year ended December 31, 2009, STP had a zero percent forced
outage rate and a 98% net capacity factor.
STP is currently owned as a tenancy in common between NRG and
two other co-owners. NRG owns a 44%, or approximately
1,175 MW, interest in STP, the City of San Antonio
owns a 40% interest and the City of Austin owns the remaining
16% interest. Each co-owner retains its undivided ownership
interest in the two nuclear-fueled generation units and the
electrical output from those units. Except for certain plant
shutdown and decommissioning costs and United States Nuclear
Regulatory Commission, or NRC, licensing liabilities, NRG is
severally liable, but not jointly liable, for the expenses and
liabilities of STP. The four original co-owners of STP organized
STPNOC to operate and maintain STP. STPNOC is managed by a board
of directors composed of one director appointed by each of the
three co-owners, along with the chief executive officer of
STPNOC. STPNOC is the NRC-licensed operator of STP. No single
owner controls STPNOC and most significant commercial as well as
asset investment decisions for the existing units must be
approved by two or more owners who collectively control more
than 60% of the interests.
The two STP generation units operate under licenses granted by
the NRC that expire in 2027 and 2028, respectively. These
licenses may be extended for additional
20-year
terms if the project satisfies NRC requirements. Adequate
provisions exist for long-term
on-site
storage of spent nuclear fuel throughout the remaining life of
the existing STP plant licenses.
Market
Framework
The ERCOT market is one of the nations largest and
historically fastest growing power markets. It represents
approximately 85% of the demand for power in Texas and covers
the entire state, with the exception of the far west
(El Paso), a large part of the Texas Panhandle, and two
small areas in the eastern part of the state. For 2009, hourly
demand ranged from a low of 21,350 MW to a high of
63,534 MW. The ERCOT market has limited interconnections
compared to other markets in the U.S. currently
limited to 1,086 MW of generation capacity, and wholesale
transactions within the ERCOT market are not subject to
regulation by the Federal Energy Regulatory Commission, or FERC.
Any wholesale producer of power that qualifies as a power
generation company under the Texas electric restructuring law
and that accesses the ERCOT electric power grid is allowed to
sell power in the ERCOT market at unregulated rates.
21
As of December 2009, installed generation capacity of
approximately 84,000 MW existed in the ERCOT market,
including 3,000 MW of generation that has suspended
operations, or been mothballed. Natural gas-fired
generation represents approximately 50,000 MW, or 59%.
Approximately 24,000 MW, or 29%, was lower marginal cost
generation capacity such as coal, lignite and nuclear plants.
NRGs coal and nuclear fuel baseload plants represent
approximately 5,355 MW net, or 22%, of the total solid-fuel
baseload net generation capacity in the ERCOT market.
Additionally, NRG commenced commercial operations of the
520 MW Cedar Bayou 4 natural gas-fueled combined cycle
generating plant at NRGs Cedar Bayou Generating Station in
Chambers County, Texas, of which NRG holds a 50% undivided
interest. Also in 2009, NRG commenced commercial operations of
the 150 MW Langford wind farm located in west Texas. Both
Cedar Bayou 4 and Langford are located in the ERCOT market.
The ERCOT market has established a target equilibrium reserve
margin level of approximately 12.5%. The reserve margin for 2009
was 16.8% forecast to increase to 21.8% for 2010 per
ERCOTs latest Capacity Demand and Reserve Report. There
are currently plans being considered by the PUCT to build a
significant amount of transmission from west Texas and
continuing across the state to enable wind generation to reach
load. The ultimate impact on the reserve margin and wholesale
dynamics from these plans are unknown.
In the ERCOT market, buyers and sellers enter into bilateral
wholesale capacity, power and ancillary services contracts or
may participate in the centralized ancillary services market,
including balancing energy, with the ERCOT administers.
Published in August 2009, the 2008 State of the Market
Report for the ERCOT Wholesale Electricity Markets from
the Independent Market Monitor indicated that natural gas is
typically the marginal fuel in the ERCOT market. As a result of
NRGs lower marginal cost for baseload coal and nuclear
generation assets, the Company expects these ERCOT assets to
generate power the majority of the time they are available.
The ERCOT market is currently divided into four regions or
congestion zones, namely: North, Houston, South and West, which
reflect transmission constraints that are commercially
significant and which have limits as to the amount of power that
can flow across zones. NRGs W.A. Parish plant, STP and all
its natural gas-fired plants are located in the Houston zone.
NRGs Limestone plant is located in the North zone while
the Elbow Creek, Langford, and Sherbino wind farms are located
in the West Zone.
The ERCOT market operates under the reliability standards set by
the North American Electric Reliability Council. The PUCT has
primary jurisdiction over the ERCOT market to ensure the
adequacy and reliability of power supply across Texass
main interconnected power transmission grid. The ERCOT is
responsible for facilitating reliable operations of the bulk
electric power supply system in the ERCOT market. Its
responsibilities include ensuring that power production and
delivery are accurately accounted for among the generation
resources and wholesale buyers and sellers. Unlike power pools
with independent operators in other regions of the country, the
ERCOT market is not a centrally dispatched power pool and the
ERCOT does not procure power on behalf of its members other than
to maintain the reliable operations of the transmission system.
The ERCOT also serves as an agent for procuring ancillary
services for those who elect not to provide their own ancillary
services.
Power sales or purchases from one location to another may be
constrained by the power transfer capability between locations.
Under the current ERCOT protocol, the commercially significant
constraints and the transfer capabilities along these paths are
reassessed every year and congestion costs are directly assigned
to those parties causing the congestion. This has the potential
to increase power generators exposure to the congestion
costs associated with transferring power between zones.
The PUCT has adopted a rule directing the ERCOT to develop and
to implement a wholesale market design that, among other things,
includes a day-ahead energy market and replaces the existing
zonal wholesale market design with a nodal market design that is
based on Locational Marginal Prices, or LMP, for power. See also
Regional Regulatory Developments Texas Region. One
of the stated purposes of the proposed market restructuring is
to reduce local (intra-zonal) transmission congestion costs. The
market redesign project is now proposed to take effect in
December 2010. NRG expects that implementation of any new market
design will require modifications to its existing procedures and
systems.
22
NORTHEAST
NRGs second largest asset base is located in the Northeast
region of the U.S. with generation assets within the
control areas of the New York Independent System Operator, or
NYISO, the Independent System Operator
New England, or ISO-NE, and the PJM. As of
December 31, 2009, NRGs generation assets in the
Northeast region consisted of approximately 1,870 MW of
baseload generation assets and approximately 5,145 MW of
intermediate and peaking assets.
Operating
Strategy
The Northeast regions strategy is focused on optimizing
the value of NRGs broad and varied generation portfolio in
the three interconnected and actively traded competitive
markets: the NYISO, the ISO-NE and the PJM. In the Northeast
markets, load-serving entities generally lack their own
generation capacity, with much of the generation base aging and
the current ownership of the generation highly disaggregated.
Thus, commodity prices are more volatile on an as-delivered
basis than in other NRG regions due to the distance and
occasional physical constraints that impact the delivery of fuel
into the region. In this environment, NRG seeks both to enhance
its ability to be the low cost wholesale generator capable of
delivering wholesale power to load centers within the region
from multiple locations using multiple fuel sources, and to be
properly compensated for delivering such wholesale power and
related services.
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
7,945
|
|
|
|
11,506
|
|
|
|
11,527
|
|
Oil
|
|
|
134
|
|
|
|
349
|
|
|
|
1,169
|
|
Gas
|
|
|
1,141
|
|
|
|
1,494
|
|
|
|
1,467
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
9,220
|
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Certain of the Northeast region assets are located in or near
load centers and inside transmission constraints such as New
York City, southwestern Connecticut and the Delmarva Peninsula.
Assets in these areas tend to attract higher capacity revenues
and higher energy revenues and thus present opportunities for
repowering these sites. The Company has benefited from the
introduction of capacity market reforms in both the New England
Power Pool, or NEPOOL, and PJM. The Locational Forward Reserve
Markets, or LFRM, in the NEPOOL, became effective
October 1, 2006, and the transition capacity payments
preceding the Forward Capacity Market, or FCM, were effective
December 1, 2006. In all seven LFRM auctions to date, the
market has cleared at the administratively set price of $14/kw
month reflecting the shortage of peaking generation especially
in the Connecticut zone. The LFRM and interim capacity payments
serve as a prelude to the full implementation of the FCM which
begins June 1, 2010. PJMs Reliability Pricing Model,
or RPM, became effective June 1, 2007, and the Company has
participated in auctions providing capacity price certainty
through May 2012.
RMR Agreements Certain of the Northeast
regions Connecticut assets have been designated as
required to be available to ensure reliability to ISO-NE. These
assets are subject to RMR agreements, which are contracts under
which NRG agrees to maintain its facilities to be available to
run when needed, and are paid to provide these capability
services based on the Companys costs. During 2009,
Middletown, Montville and Norwalk Power (Units 1 and
2) were covered by RMR agreements. Unless terminated
earlier, these agreements will terminate on June 1, 2010,
which coincides with the commencement of the FCM in NEPOOL.
23
Generation
Facilities
As of December 31, 2009, NRGs generation facilities
in the Northeast region consisted of approximately 7,015 MW
of generation capacity and are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
Capacity
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
(MW)
(c)
|
|
Fuel-type
|
Oswego
|
|
Oswego, NY
|
|
|
100.0
|
|
|
|
1,635
|
|
|
Oil
|
Arthur Kill
|
|
Staten Island, NY
|
|
|
100.0
|
|
|
|
865
|
|
|
Natural Gas
|
Middletown
|
|
Middletown, CT
|
|
|
100.0
|
|
|
|
770
|
|
|
Oil
|
Indian
River(b)
|
|
Millsboro, DE
|
|
|
100.0
|
|
|
|
740
|
|
|
Coal
|
Astoria Gas Turbines
|
|
Queens, NY
|
|
|
100.0
|
|
|
|
550
|
|
|
Natural Gas
|
Huntley
|
|
Tonawanda, NY
|
|
|
100.0
|
|
|
|
380
|
|
|
Coal
|
Dunkirk
|
|
Dunkirk, NY
|
|
|
100.0
|
|
|
|
530
|
|
|
Coal
|
Montville
|
|
Uncasville, CT
|
|
|
100.0
|
|
|
|
500
|
|
|
Oil
|
Norwalk Harbor
|
|
So. Norwalk, CT
|
|
|
100.0
|
|
|
|
340
|
|
|
Oil
|
Devon
|
|
Milford, CT
|
|
|
100.0
|
|
|
|
135
|
|
|
Natural Gas
|
Vienna
|
|
Vienna, MD
|
|
|
100.0
|
|
|
|
170
|
|
|
Oil
|
Somerset
Power(a)
|
|
Somerset, MA
|
|
|
100.0
|
|
|
|
125
|
|
|
Coal
|
Connecticut Remote Turbines
|
|
Four locations in CT
|
|
|
100.0
|
|
|
|
145
|
|
|
Oil/Natural Gas
|
Conemaugh
|
|
New Florence, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone
|
|
Shelocta, PA
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Northeast Region
|
|
|
|
|
|
|
|
|
7,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
In 2003, Somerset entered into an
agreement with the Massachusetts Department of Environmental
Protection, or MADEP, to retire or repower 100MW Unit 6, the
remaining coal-fired unit at Somerset, by the end of 2009. In
connection with a repowering proposal approved by the MADEP, the
date for the shut-down of the unit was extended to
September 30, 2010. Subsequently, NRG requested of ISO-NE
that it be allowed to place Unit 6 on deactivated reserve
effective January 2, 2010, in advance of the required
shut-down date. On December 21, 2009, ISO-NE granted
NRGs request.
|
(b)
|
|
Indian River Unit 2 will be retired
May 1, 2010 and Indian River Unit 1 will be retired
May 1, 2011. In addition, NRG and DNREC announced a
proposed plan, subject to definitive documentation, that would
shut down Indian River Unit 3 by December 31, 2013.
|
(c)
|
|
Actual capacity can vary depending
on factors including weather conditions, operational conditions
and other factors.
|
The table below reflects the plants and relevant capacity
revenue sources for the Northeast region:
|
|
|
|
|
|
|
|
|
Sources of
|
|
|
|
|
Capacity Revenue:
|
|
|
|
|
Market Capacity,
|
|
|
|
|
RMR and Tolling
|
Region, Market and Facility
|
|
Zone
|
|
Arrangements
|
Northeast Region:
|
|
|
|
|
NEPOOL (ISO-NE):
|
|
|
|
|
Devon
|
|
SWCT
|
|
LFRM/FCM
|
Connecticut Jet Power
|
|
SWCT
|
|
LFRM/FCM
|
Montville
|
|
CT ROS
|
|
RMR(a)/FCM
|
Somerset
|
|
SE MASS
|
|
LFRM/FCM
|
Middletown
|
|
CT ROS
|
|
RMR(a)/FCM
|
Norwalk Harbor
|
|
SWCT
|
|
RMR(a)/FCM
|
PJM:
|
|
|
|
|
Indian River
|
|
PJM East
|
|
DPL South
|
Vienna
|
|
PJM East
|
|
DPL South
|
Conemaugh
|
|
PJM West
|
|
PJM MAAC
|
Keystone
|
|
PJM West
|
|
PJM MAAC
|
New York (NYISO):
|
|
|
|
|
Oswego
|
|
Zone C
|
|
UCAP ROS
|
Huntley
|
|
Zone A
|
|
UCAP ROS
|
Dunkirk
|
|
Zone A
|
|
UCAP ROS
|
Astoria Gas Turbines
|
|
Zone J
|
|
UCAP NYC
|
Arthur Kill
|
|
Zone J
|
|
UCAP NYC
|
|
|
|
(a)
|
|
Per the terms of the RMR agreement,
any FCM transition capacity payments are offset against approved
RMR payment. RMR agreements will expire June 1, 2010, the
first day of the First Installed Capacity Commitment Period of
the FCM.
|
24
The following is a description of NRGs most significant
revenue generating plants in the Northeast region:
Arthur Kill NRGs Arthur Kill plant is a
natural gas-fired power plant consisting of three units and is
located on the west side of Staten Island, New York. The plant
produces an aggregate generation capacity of 865 MW from
two intermediate load units (Units 20 and 30) and one peak
load unit (Unit GT-1). Unit 20 produces an aggregate generation
capacity of 350 MW and was installed in 1959. Unit 30
produces an aggregate generation capacity of 505 MW and was
installed in 1969. Both Unit 20 and Unit 30 were converted from
coal-fired to natural gas-fired facilities in the early 1990s.
Unit GT-1 produces an aggregate generation capacity of
10 MW and is activated when Consolidated Edison issues a
maximum generation alarm on hot days and during thunderstorms.
Astoria Gas Turbine Located in Astoria,
Queens, New York, the NRG Astoria Gas Turbine facility occupies
approximately 15 acres within the greater Astoria
Generating complex which includes several competing generating
facilities. NRGs Astoria Gas Turbine facility has an
aggregate generation capacity of approximately 550 MW from
19 operational combustion turbine generators classified into
three types of turbines. The first group consists of 12
gas-fired Pratt & Whitney GG-4 Twin Packs in Buildings
2, 3 and 4, which have a net generation capacity of 145 MW
per building. The second group consists of Westinghouse
Industrial Combustion Turbines #191A in Buildings 5, 7 and
8 that fire on liquid distillate with a net generation capacity
of approximately 12 MW per building. The third group
consists of Westinghouse Industrial Gas Turbines #251GG
located in Buildings 10, 11, 12 and 13 and fire on liquid
distillate with a net generation capacity of 20 MW per
building. The Astoria units also supply Black Start Service to
the NYISO. The site also contains tankage for distillate fuel
with a capacity of 86,000 barrels.
Dunkirk The Dunkirk plant is a coal-fired
plant located on Lake Erie in Dunkirk, New York. This plant
produces an aggregate generation capacity of 530 MW from
four baseload units. Units 1 and 2 produce up to 75 MW each
and were put in service in 1950, and Units 3 and 4 produce
approximately 190 MW each and were put in service in 1959
and 1960, respectively. In a settlement agreement reached with
the New York Department of Environmental Conservation, or
NYSDEC, in January 2005, NRG committed to reducing
SO2
emissions from Dunkirk and Huntley stations by 86.8% below
baseline emissions of 107,144 by 2013 and
NOx
emissions by 80.9% below baseline emission of 17,005 by 2012. In
order to comply with the NYSDEC settlement agreement, as well as
with various federal and state emissions standards, the Company
installed back-end control facilities at Dunkirk in 2009. All
units have returned to service and the fabric filters are
functioning as designed.
Huntley The Huntley plant is a coal-fired
plant consisting of six units and is located in Tonawanda,
New York, approximately three miles north of Buffalo. The
plant has a net generation capacity of 380 MW from two
baseload units (Units 67 and 68). Units 67 and 68 generate a net
capacity of approximately 190 MW each, and were put in
service in 1957 and 1958, respectively. Units 63 and 64 are
inactive and were officially retired in May 2006. To comply with
the January 2005 NYSDEC settlement agreement referenced above,
NRG retired Units 65 and 66 effective June 3, 2007, and in
January 2009, Huntley Units 67 and 68 fabric filters were placed
in service and they are functioning as designed.
Indian River The Indian River Power plant is
a coal-fired plant located in southern Delaware on a
1,170 acre site. The plant consists of four coal-fired
electric steam units (Units 1 through 4) and one 15 MW
combustion turbine, bringing total plant capacity to
approximately 740 MW. Units 1 and 2 are each 80 MW of
capacity and were placed in service in 1957 and 1959,
respectively. Unit 3 is 155 MW of capacity and was placed
in service in 1970, while Unit 4 is 410 MW of capacity and
was placed in service in 1980. Units 1, 2, 3 and 4 are equipped
with selective non-catalytic reduction systems, for the
reduction of
NOx
emissions. All four units are equipped with electrostatic
precipitators to remove fly ash from the flue gases as well as
low
NOx
burners with over fired air to control
NOx
emissions and activated carbon injection systems to control
mercury. Units 1, 2 and 3 are fueled with eastern bituminous
coal, while Unit 4 is fueled with low sulfur compliance coal.
Pursuant to a consent order dated September 25, 2007,
between NRG and the Delaware Department of Natural Resources and
Environmental Control, or DNREC, NRG agreed to operate the units
in a manner that would limit the emissions of
NOx,
SO2
and mercury. Further, the Company agreed to mothball unit 2 by
May 1, 2010, and unit 1 by May 1, 2011, and has
notified PJM of the plan to mothball these units. In the absence
of the appropriate control technology installed at this
facility, Units 3 and 4 totaling approximately 565 MW,
could not operate beyond December 31, 2011, per terms of
the consent order. On February 3, 2010, the Company
together with DNREC announced a proposed plan to retire the
25
155 MW unit 3 by December 31, 2013. The plan, subject
to definitive documentation, extends the operable period of the
plant two years beyond the December 31, 2011 date and
avoids the incremental cost of control technology. The
410 MW unit 4 is not affected by this proposal, and in
2009, the Company began construction to install selective
catalytic reduction systems, scrubbers and fabric filters on
this unit. These controls are scheduled to be operational at the
end of 2011.
Market
Framework
Although each of the three Northeast Independent Systems
Operators, or ISOs, and their respective energy markets are
functionally, administratively and operationally independent,
they all follow, to a certain extent, similar market designs.
Each ISO dispatches power plants to meet system energy and
reliability needs, and settles physical power deliveries at LMPs
which reflect the value of energy at a specific location at the
specific time it is delivered. This value is determined by an
ISO-administered auction process, which evaluates and selects
the least costly supplier offers or bids to create a reliable
and least-cost dispatch. The ISO-sponsored LMP energy markets
consist of two separate and characteristically distinct
settlement time-frames. The first time-frame is a financially
firm, day-ahead unit commitment market. The second time-frame is
a financially settled, real-time dispatch and balancing market.
Prices paid in these LMP energy markets, however, are affected
by, among other things, market mitigation measures, which can
result in lower prices associated with certain generating units
that are mitigated because they are deemed to have locational
market power.
SOUTH
CENTRAL
NRG is the third largest generator in the South Central region
of the U.S. with generation assets within the control areas
of the Southeastern Electric Reliability Council/Entergy, or
SERC-Entergy, region. As of December 31, 2009, the
Companys generation assets in Louisiana consist of its
primary asset, Big Cajun II, a coal-fired plant located near
Baton Rouge, Louisiana which has approximately 1,495 MW of
baseload capacity and 905 MW of intermediate and peaking
assets. A significant portion of the regions generation
capacity has been sold to ten cooperatives within the region
through 2026. From time to time, the Company may contract for
intermediate generation capacity to support its load
obligations. In addition, the region also operates 455 MW
of peaking generation in Rockford, Illinois under the PJM region.
The South Central region lacks a regional transmission
organization, or RTO, and, therefore, remains a bilateral
market, which is not able to take advantage of the large scale
economic dispatch of an ISO-administered energy market. NRG
operates the LaGen Control Area which encompasses the generating
facilities and the Companys cooperative load. As a result,
the LaGen control area is capable of providing control area
services, in addition to wholesale power, that allows NRG to
provide full requirement services to load-serving entities, thus
making the LaGen Control Area a competitive alternative to the
integrated utilities operating in the region.
Operating
Strategy
The South Central region maximizes its strategic position as a
significant coal-fired generator in a market that is highly
dependent on natural gas for power generation. South Central
also has long-term full service contracts with ten rural
cooperatives serving load across Louisiana and makes incremental
wholesale energy sales when its coal-fired capacity exceeds the
cooperative contract requirements. The South Central region
works to expand its customer base within and beyond Louisiana
and works within the confines of the Entergy Transmission System
to obtain paths for incremental sales as well as secure
transmission service for long-term sales or expansions.
The generation performance by fuel-type for the recent
three-year period is as shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Generation
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In thousands of MWh)
|
|
|
Coal
|
|
|
10,235
|
|
|
|
10,912
|
|
|
|
10,812
|
|
Gas
|
|
|
163
|
|
|
|
236
|
|
|
|
118
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
10,398
|
|
|
|
11,148
|
|
|
|
10,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
Generation
Facilities
NRGs generating assets in the South Central region consist
primarily of its net ownership of power generation facilities in
New Roads, Louisiana, which is referred to as Big Cajun II, and
also includes the Sterlington, Rockford, Bayou Cove and Big
Cajun peaking facilities.
NRGs power generation assets in the South Central region
as of December 31, 2009, are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary Fuel
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
(b)
|
|
|
type
|
|
Big Cajun
II(a)
|
|
New Roads, LA
|
|
|
86.0
|
|
|
|
1,495
|
|
|
Coal
|
Bayou Cove
|
|
Jennings, LA
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Big Cajun I (Peakers) Units 3 and 4
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
210
|
|
|
Natural Gas
|
Big Cajun I Units 1 and 2
|
|
Jarreau, LA
|
|
|
100.0
|
|
|
|
220
|
|
|
Natural Gas/Oil
|
Rockford I
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Rockford II
|
|
Rockford, IL
|
|
|
100.0
|
|
|
|
155
|
|
|
Natural Gas
|
Sterlington
|
|
Sterlington, LA
|
|
|
100.0
|
|
|
|
175
|
|
|
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total South Central
|
|
|
|
|
|
|
|
|
2,855
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
NRG owns 100% of Units 1 & 2;
58% of Unit 3.
|
(b)
|
|
Actual capacity can vary depending
on factors including weather conditions, operational conditions
and other factors.
|
Big Cajun II NRGs Big Cajun II
plant is a coal-fired,
sub-critical
baseload plant located along the banks of the Mississippi River,
near Baton Rouge, Louisiana. This plant includes three
coal-fired generation units (Units 1, 2 and 3) with an
aggregate generation capacity of 1,745 MW. The plant uses
coal supplied from the Powder River Basin and was commissioned
between 1981 and 1983. NRG owns 100% of Units 1 and 2 and a 58%
undivided interest in Unit 3 for an aggregate owned capacity of
1,495 MW of the plant. All three units have been upgraded
with advanced
low-NOx
burners and overfire air systems.
Market
Framework
NRGs assets in the South Central region are located within
the franchise territories of vertically integrated utilities,
primarily Entergy Corp., or Entergy. In the South Central
region, all power sales and purchases are consummated
bilaterally between individual counterparties. Transacting
counterparties are required to procure transmission service from
the relevant transmission owners at their FERC-approved tariff
rates.
As of December 31, 2009, NRG had long-term all-requirements
contracts with ten Louisiana distribution cooperatives with
initial terms ranging from ten to twenty-five years. Of the ten
contracts, seven expire in 2025 and account for 50% of the
contract load, while the remaining three expire in 2014 and
comprise 40% of contract load. In addition to earning energy
revenues from these cooperative agreements, NRG also earns
capacity revenues which are tied to summer peak demand as well
as provide a mechanism for recovering a portion of the costs for
mandated environmental projects over the remaining life of the
contract. During 2009, NRG successfully executed
all-requirements contracts with three Arkansas municipalities
with service start dates as early as mid-year 2010. These new
contracts account for over 500 MW of total load obligations
for NRG and the South Central region, more than offsetting the
South Central regions reduction in load in 2009 due to the
expiration of a Louisiana distribution cooperative contract. In
addition, NRG also has certain long-term contracts with the
Municipal Energy Agency of Mississippi, Mississippi Delta Energy
Agency, South Mississippi Electric Power Association, and
Southwestern Electric Power Company, which collectively
comprised an additional 10% of the regions contract load
requirement.
During limited peak demand periods, the load requirements of
these contract customers exceed the baseload capacity of
NRGs coal-fired Big Cajun II plant. During such peak
demand periods, NRG either employs its owned or leased gas-fired
assets or purchases power from external sources, depending upon
the then-current gas commodity pricing, and these purchases can
be at higher prices than can be recovered under the
Companys contracts. NRG has to date successfully mitigated
the risk of these peak contract load requirements by contracting
for new large industrial or municipal loads outside contract
pricing at market rates. Also, to minimize this risk during the
peak summer and winter seasons, the Company has been successful
in entering into structured agreements to reduce or eliminate
the need for spot market purchases.
27
WEST
NRGs generation assets in the West region of the
U.S. are primarily located in the California Independent
System Operator, or CAISO, control area. The West regions
generation assets currently consists of the Long Beach
Generating Station, the El Segundo Generating Station, the
Encina Generating Station and Cabrillo II, which consists of 12
combustion turbines located in San Diego County. The
Companys generation assets in the West region are
predominately intermediate and peaking duty natural gas-fired
plants located in southern California. In addition, the region
owns a 50% interest in the Saguaro power plant which is a
90 MW baseload, gas-fired plant located in Nevada and a
20 MW photovoltaic solar facility located in southern
California.
Operating
Strategy
NRGs West region strategy is focused on maximizing the
cash flow and value associated with its generating plants and
the development of renewable and repowering projects that
leverage off of existing capabilities, assets and sites, as well
as the preservation and ultimate realization of the commercial
value of the underlying real estate. There are four principal
components to this strategy: (i) capturing the value of the
portfolios generation assets through a combination of
forward contracts and market sales of capacity, energy, and
ancillary services; (ii) leveraging existing site control
and emission allowances to permit new, more efficient generating
units at existing sites; (iii) developing renewable project
opportunities that are positioned to compete for long-term
contracts offered by load serving entities; and
(iv) optimizing the value of the regions coastal
property for other purposes.
The Companys Encina Generating Station has sold all energy
and capacity, 965 MW in the aggregate, to a load-serving
entity through 2010, on a tolling basis, and recovers its
operating costs plus a capacity payment. For calendar year 2009,
El Segundo station entered into 548 MWs of RA capacity
contracts and placed the capacity in the market through a
portfolio of forward contracts. For calendar year 2010, El
Segundo station entered into 335 MWs of RA capacity
contracts and retained its rights to sell energy and ancillary
services into the market. Cabrillo II sold 188 MW of
RA capacity for calendar year 2009 and 2010, and 88 MW for
the period January 1, 2011 through November 30, 2013.
Units with RA contracts also sell into energy and ancillary
services markets consistent with unit availability.
The Saguaro power plant is located in Henderson, Nevada, and is
contracted to NV Energy (formerly Nevada Power) and two steam
hosts. The Saguaro plant is contracted to NV Energy through
2022, one steam host, Olin (formerly known as Pioneer), whose
contract was extended in 2009 for an additional two years, and a
steam off-taker, Ocean Spray, whose contract runs through 2015.
Saguaro Power Company, LP, the project company, procures fuel in
the open market. NRG manages its share of any fuel price risk
through NRGs commodity price risk strategy.
On November 20, 2009, NRG, through its wholly owned
subsidiary NRG Solar LLC, acquired Blythe Solar from First
Solar, Inc. On December 18, 2009, construction was
completed and commercial operation began for the 20 MW
utility-scale photovoltaic, or PV, solar facility located in
Riverside County in southeastern California. The Blythe Solar PV
field will provide electricity to Southern California Edison, or
SCE, under a
20-year
Power Purchase Agreement, or PPA. First Solar will operate and
maintain the solar facility under contract.
Generation
Facilities
NRGs power generation assets in the West region as of
December 31, 2009, are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
% Owned
|
|
|
(MW)
(a)
|
|
|
Fuel-type
|
|
Encina
|
|
Carlsbad, CA
|
|
|
100.0
|
|
|
|
965
|
|
|
Natural Gas
|
El Segundo
|
|
El Segundo, CA
|
|
|
100.0
|
|
|
|
670
|
|
|
Natural Gas
|
Long Beach
|
|
Long Beach, CA
|
|
|
100.0
|
|
|
|
260
|
|
|
Natural Gas
|
Cabrillo II
|
|
San Diego, CA
|
|
|
100.0
|
|
|
|
190
|
|
|
Natural Gas
|
Saguaro
|
|
Henderson, NV
|
|
|
50.0
|
|
|
|
45
|
|
|
Natural Gas
|
Blythe Solar
|
|
Blythe, CA
|
|
|
100.0
|
|
|
|
20
|
|
|
Solar
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total West Region
|
|
|
|
|
|
|
|
|
2,150
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Actual capacity can vary depending
on factors including weather conditions, operational conditions
and other factors.
|
28
The table below reflects the plants and relevant capacity
revenue sources for the West region:
|
|
|
|
|
|
|
|
|
|
|
Sources of Capacity
|
|
|
|
|
Revenue: Market Capacity,
|
|
|
|
|
RMR and Tolling
|
Region, Market and Facility
|
|
Zone
|
|
Arrangements
|
West Region:
|
|
|
|
|
|
|
California (CAISO):
|
|
|
|
|
|
|
Encina
|
|
|
CAISO
|
|
|
Toll (a)
|
Cabrillo II
|
|
|
CAISO
|
|
|
RA Capacity
(b)
|
El Segundo Power
|
|
|
CAISO
|
|
|
RA Capacity
(c)
|
Long Beach
|
|
|
CAISO
|
|
|
Toll(d)
|
Blythe
|
|
|
CAISO
|
|
|
Toll (e)
|
|
|
|
(a)
|
|
Toll expires December 31, 2010.
|
(b)
|
|
The RMR agreement covering
160 MW expired on 12/31/2008 and was replaced by RA
contracts covering the entire Cabrillo II portfolio during
2009 (RA contracts for 88 MW run through November 30,
2013).
|
(c)
|
|
El Segundo includes approximately
670MW economic call option and 548 MW of RA contracts for
2009.
|
(d)
|
|
NRG has purchased back energy and
ancillary service value of the toll through July 31, 2011.
Toll expires August 1, 2017.
|
(e)
|
|
Blythe reached commercial
operations on December 18, 2009 and sells all its energy
under a
20-year PPA.
|
The following are descriptions of the Companys most
significant revenue generating plants in the West region:
Encina The Encina Station is located in
Carlsbad, California and has a combined generating capacity of
965 MW from five fossil-fuel steam-electric generating
units and one combustion turbine. The five fossil-fuel
steam-electric units provide intermediate load services and use
natural gas. Also located at the Encina Station is a combustion
turbine that provides peaking and black-start services of
15 MW. Units 1, 2 and 3 each have a generation capacity of
approximately 107 MW and were installed in 1954, 1956 and
1958, respectively. Units 4 and 5 have a generation capacity of
approximately 300 MW and 330 MW respectively, and were
installed in 1973 and 1978. The combustion turbine was installed
in 1966. Low
NOx
burner modifications and Selective Catalytic Reduction, or SCR,
equipment have been installed on all the steam units.
El Segundo The El Segundo plant is located in
El Segundo, California and produces an aggregate generation
capacity of 670 MW from two gas-fired intermediate load
units (Units 3 and 4). These units, which have a generation
capacity of 335 MW each, were installed in 1964 and 1965,
respectively. SCR equipment has been installed on Units 3 and 4.
Long Beach On August 1, 2007, the
Company successfully completed and commissioned the repowering
of 260 MW of gas-fired generating capacity at its Long
Beach Generating Station. Generation from Long Beach provides
needed support for the summer peak and during transmission
contingencies to load serving entities and the CAISO. This
project is backed by a
10-year PPA
executed with SCE in November 2006 and effective through
July 31, 2017. The new generation consists of refurbished
gas turbines with SCR equipment.
Cabrillo II Cabrillo II consists of 12
combustion turbines located on 4 sites throughout San Diego
County with an aggregate generating capacity of approximately
190 MW. The combustion turbines were installed between 1968
and 1972 and are operated under a license agreement with
SDG&E through 2013. The combustion turbines provide peaking
services and serve a reliability function for the CAISO.
Blythe Solar Blythe Solar consists of a
20 MW utility-scale photovoltaic, or PV, solar facility
located in Riverside County in southeastern California. The site
uses approximately 350,000 photovoltaic solar modules that turn
sunlight directly into electricity. The Blythe Solar site covers
approximately 200 acres. The output of the facility is
fully contracted to SCE under a
20-year PPA.
Market
Framework
Except for the Saguaro facility, NRGs generation assets in
the West region operate within the balancing authority of CAISO.
CAISOs current market allows NRGs CAISO assets to
serve multiple load serving entities, or LSEs, and operates a
nodal balancing market and congestion clearing mechanism. CAISO
also has a locational capacity requirement, which requires LSEs
to procure a significant portion of load from defined local
reliability areas. All of NRGs CAISO assets are in the Los
Angeles or San Diego local reliability areas. CAISOs
new market,
29
known as Market Redesign and Technology Upgrade, or MRTU, became
operational on April 1, 2009. MRTU established a day-ahead
market for energy and ancillary services and settles prices
locationally. NRGs CAISO assets are all peaking and
intermediate in nature and are well positioned to capitalize on
the higher locational prices that may result from LMPs in
location constrained areas and will continue to satisfy local
distribution company capacity requirements. Longer term,
NRGs California portfolios locational advantage may
be impacted by new transmission, which may affect load pocket
procurement requirements. So far, however, the impacts of
increasing demand and need for flexible cycling capability
combined with delays in the online date of new transmission have
muted the impact of this long-term threat.
Californias resource mix will be significantly shaped in
the years ahead by Californias renewable portfolio
standard and its greenhouse gas reduction rules promulgated
pursuant to Assembly Bill 32 California Global
Warming Solutions Act of 2006, or AB32. In particular, the
states renewable portfolio standard is currently set at
20% for 2010 and the Governor, by Executive Order, has directed
that the standard be increased to 33% by 2020. This increase is
expected to create greater demand for low emission resources.
The intermittent and remote nature of most renewable resources
will create a strong demand for flexible load pocket resources.
NRGs California portfolio may also be impacted by
legislation and by any mechanism, such as
cap-and-trade,
that places a price on incremental carbon emissions. NRGs
expectation is that the emission costs will be reflected in the
market price of power and that the net cost to the
Companys existing portfolio of intermediate and peaking
resources will be manageable.
Californias investor-owned utilities are sponsoring
competitive solicitations for new fossil and renewable
generating capacity. The El Segundo repowering project has been
selected and contracted by a load-serving entity and is in the
final stages of permitting. The project is planned to be in
operation in the summer of 2013. A permit application for the
Encina repowering project has been submitted and is under
evaluation by the California Energy Commission. The Encina
repowering project has cost and location advantages that enhance
its competitive prospects. Both projects are supported by air
emissions credits that have been banked after the retirement of
older generating units.
INTERNATIONAL
As of December 31, 2009, NRG, through certain foreign
subsidiaries, had investments in power generation projects
located in Australia and Germany with approximately
1,005 MW of generation capacity. The Companys
strategy is to maximize its return on investment and concentrate
on contract management; monitoring of its facility operators to
ensure safe, profitable and sustainable operations; management
of cash flow and finances; and growth of its businesses through
investments in projects related to current businesses.
NRGs international power generation assets as of
December 31, 2009, are summarized in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
|
|
|
|
|
|
Generation
|
|
|
|
|
|
|
|
|
|
|
|
Capacity
|
|
|
Primary
|
Plant
|
|
Location
|
|
|
% Owned
|
|
|
(MW)
|
|
|
Fuel-type
|
|
Gladstone
|
|
|
Australia
|
|
|
|
37.5
|
|
|
|
605
|
|
|
Coal
|
Schkopau
|
|
|
Germany
|
|
|
|
41.9
|
|
|
|
400
|
|
|
Lignite
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total International
|
|
|
|
|
|
|
|
|
|
|
1,005
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Australia Through a joint venture, NRG holds
a 37.5% equity interest in the Gladstone power station, or
Gladstone. A wholly owned subsidiary, NRG Gladstone Operating
Services, serves as the stations sole operator. Because
NRG is neither the majority owner nor the joint venture manager,
NRG does not have unilateral control over the operation,
maintenance, and management of this asset. Gladstone
stations output is fully contracted through 2029 to Boyne
Smelter Limited and Stanwell Corporation Limited. Boyne Smelter
is owned by a consortium whose members include all the members
of the Gladstone joint venture other than NRG. Its business is
to refine alumina into aluminum. Stanwell is a state owned
corporation that generates power, purchases power from other
generators such as Gladstone, trades power in the Australian
National Electricity Market and delivers power to retail
customers.
30
Germany NRG, through its wholly-owned
subsidiary Saale Energie GmbH, or SEG, owns 400 MW of the
Schkopau plants electric capacity which is sold under a
long-term contract to Vattenfall Europe Generation, AG. The
900 MW Schkopau generating plant, in which the Company has
a 41.9% equity interest, is fueled with lignite.
On June 10, 2009, NRG completed the sale of its 50%
ownership interest in Mitteldeutsche Braunkohlengesellschaft
mbH, or MIBRAG, to a consortium of Severoćeské 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. For further discussion of
MIBRAG disposition, see Item 14 Note 4,
Discontinued Operation and Dispositions, to the
Consolidated Financial Statements.
THERMAL
Through its wholly-owned subsidiary, NRG Thermal LLC, or NRG
Thermal, the Company owns thermal and chilled water businesses
that have a steam and chilled water capacity of approximately
1,020 megawatts thermal equivalent, or MWt. As of
December 31, 2009, NRG Thermal provided steam heating to
approximately 495 customers and chilled water to 100 customers
in five different cities in the U.S. The Companys
thermal businesses in Pittsburgh, Harrisburg and
San Francisco are regulated by their respective
states Public Utility Commission. The other thermal
businesses are subject to contract terms with their customers.
In addition, NRG Thermal owns and operates a thermal project
that serves two industrial customers with high-pressure steam.
NRG Thermal also owns an 88 MW combustion turbine peaking
generation facility and a 16 MW coal-fired cogeneration
facility in Dover, Delaware as well as a 12 MW gas-fired
project in Harrisburg, Pennsylvania. Approximately 37% of NRG
Thermals revenues are derived from its district heating
and chilled water business in Minneapolis, Minnesota.
The table below reflects relevant electric capacity revenue
sources for the Thermal region:
|
|
|
|
|
|
|
|
|
Sources of
|
|
|
|
|
Capacity Revenue:
|
|
|
|
|
Market Capacity,
|
|
|
|
|
RMR and Tolling
|
Region and Facility
|
|
Zone
|
|
Arrangements
|
Thermal:
|
|
|
|
|
Dover
|
|
PJM East
|
|
DPL South
|
Paxon Creek
|
|
PJM West
|
|
PJM MAAC
|
New and
On-going Company Initiatives and Development Projects
NRG has a comprehensive set of initiatives and development
projects that supports its strategy focused on:
(i) top decile and enhanced operating performance;
(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; (iv) engaging in a proactive capital
allocation plan; and (v) pursuing selective acquisitions,
joint ventures, divestitures and investment in new
energy-related businesses and new technologies in order to
enhance the Companys asset mix and combat climate change.
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 was a 20 basis point
improvement in ROIC which corresponds to approximately
$30 million in cash flow. As of December 31, 2009, the
Company exceeded its 2009 goal with a 50.37 basis point
improvement in ROIC, which is equivalent to approximately
$76 million in cash flows. The performance of the plants
coupled with strategic projects undertaken by corporate
functions is evidenced in the overall corporate
31
performance. During 2010, the Company expects to progress
further toward the program goal of 100 basis point ROIC
improvement by 2012.
RepoweringNRG
Update
NRG has several projects in varying stages of development that
include the following: a new generating unit at the Limestone
power station and the repowering of Encina and El Segundo sites.
In addition, on December 22, 2009, NRG entered into a
13-year
agreement with University Medical Center of Princeton to provide
comprehensive high efficiency energy to this 237 room hospital.
The hospital, which is currently under construction, will use
electricity from an NRG owned combined heat and power system
that includes the production of steam for heating and chilled
water for air conditioning, achieved by means of a thermal
energy storage system. Construction of the facility will
commence in early 2010 with expected commercial operation by the
first quarter 2012. The development of these projects is subject
to certain conditions and milestones which may effect the
Companys decision to pursue further development of these
projects. The Companys development projects are generally
subject to certain conditions, milestones, or other factors that
may result in the Companys decision to no longer pursue
development of these projects.
The following is a summary of the 2009 repowering projects that
have been completed and operating as well as those still 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 520 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 260 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,
or GenConn, a
50/50
joint venture of NRG and The United Illuminating Company,
secured contracts in 2008 with Connecticut Light &
Power, or CL&P, for the construction and operation of two
200 MW peaking facilities, at NRGs Devon and
Middletown sites in Connecticut. The contracts, which are
structured as contracts for differences for the 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 facility while site demolition and excavation has
begun at the Middletown location.
On April 27, 2009, GenConn 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 $108 million as of
December 31, 2009. In August 2009, GenConn began to draw on
the project financing facility to cover costs related to the
Devon project.
Retail
Development
Electric Vehicle Services In
2009, NRG began development of a service business to support the
mass deployment of electric vehicles through its subsidiary
Reliant Energy. In 2010, Reliant Energy plans to begin selling
new products and services that enable both public and home
charging of electric vehicles. In conjunction with this effort,
Reliant Energy announced in November 2009 that it will work with
Nissan Motor Co. to make the City of Houston a launch city for
the broader use of electric vehicles. Also in November 2009,
Reliant Energy announced a
32
joint project with the City of Houston to add plug-in fleet
vehicles as well as public charging stations to support them.
Smart Energy In 2009, Reliant
Energy submitted an application to the Department of Energy, or
DOE, requesting $20 million in the Smart Grid Investment
Grant funds for a three-year project to bring a suite of Smart
Grid enabled products to residential customers. Reliant
Energys project was selected by the DOE in October 2009.
The Company is now in the process of negotiating a definitive
agreement with the DOE and expects to begin the project in the
first quarter 2010. Reliant Energys share of the project
costs are expected to be $45.5 million over a three-year
period.
Capital
Allocation Program
NRGs capital allocation philosophy includes reinvestment
in its core facilities, maintenance of prudent debt levels and
interest coverage, the regular return of capital to shareholders
and investment in repowering opportunities. Each of these
components are described further as follows:
|
|
|
|
|
Reinvestment in existing assets Opportunities to
invest in the existing business, including maintenance and
environmental capital expenditures that improve operational
performance, ensure compliance with environmental laws and
regulations, and expansion projects.
|
|
|
|
Management of debt levels The Company uses several
metrics to measure the efficiency of its capital structure and
debt balances, including the Companys targeted net debt to
total capital ratio range of 45% to 60% and certain cash flow
and interest coverage ratios. The Company intends in the normal
course of business to continue to manage its debt levels towards
the lower end of the range and may, from time to time, pay down
its debt balances for a variety of reasons.
|
|
|
|
Return of capital to shareholders The Companys
debt instruments include restrictions on the amount of capital
that can be returned to shareholders. The Company has in the
past returned capital to shareholders while maintaining
compliance with existing debt agreements and indentures. The
Company expects to regularly return capital to shareholders
through opportunistic share repurchases, while exploring other
prospects to increase its flexibility under restrictive debt
covenants.
|
|
|
|
Repowering, econrg and new build opportunities The
Company intends to pursue repowering initiatives that enhance
and diversify its portfolio and provide a targeted economic
return to the Company.
|
Nuclear
Development
Nuclear Innovation North America In
2008, NRG formed Nuclear Innovation North America LLC, or NINA,
an NRG subsidiary focused on marketing, siting, developing,
financing and investing in new advanced design nuclear projects
in select markets across North America, including the planned
South Texas Projects Units 3 and 4, or STP Units 3 and 4. NINA
is currently owned 88% by NRG and 12% by Toshiba American
Nuclear Energy Corporation, or TANE, a wholly owned subsidiary
of Toshiba Corporation.
Based on its current NRC schedule, the Company expects to
achieve commercial operation for Unit 3 in 2016 and commercial
operation for Unit 4 approximately 12 months thereafter.
The total rated capacity of the new units, STP Units 3 and 4, is
expected to equal or exceed 2,700 MW. NINA is in the
process of assessing the potential for increasing the gross
output of the units through an uprate amendment, shortly after
receipt of the Combined Operating License, or COL. This would
increase the rated gross output of the units to approximately
3,000 MWs. The NRC licensing process also provides an
opportunity for individuals to intervene in the COL application
as an ordinary part of the COL application process. At this
time, several individuals have elected to intervene in the COL
proceedings and NINA is currently in the process of defending,
addressing or eliminating, as appropriate, all open contentions
by the interveners.
The DOE has confirmed that the STP Units 3 and 4 project is one
of four projects selected for further due diligence and
negotiation leading to a conditional commitment under the DOE
loan guarantee program. NINA is currently in 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,
33
NINA is seeking to augment potential financial support from the
DOE by actively pursuing additional loan guarantees through the
Japanese government. The project is expected to have significant
Japanese content.
In 2009, NINA executed an EPC agreement with TANE to build STP
Units 3 and 4. The EPC agreement is structured so as to assure
that the new plant is constructed on time, on budget and to
exacting standards. There are three primary cost elements that
make up the total cost of the STP Units 3 and 4. The largest is
the EPC Cost, which is the cost the prime contractor will charge
for the engineering, construction, procurement, and
material/equipment of the STP Units 3 and 4. The second cost is
what is referred to as Owners Cost, comprised of licensing
fees, contingency, internal and agent resource costs, operations
training, owners engineers and other third party support
costs. The final cost component is the Financing Cost, which
includes subsidy costs of the DOE loan guarantee, interest
during construction, and support services associated with
putting the financing in place.
On December 30, 2009, NINA had received an estimate from
TANE, the prime contractor, containing the overnight estimate of
the EPC Cost. The estimate was approximately $11.5 billion
for STP Units 3 and 4 with an opportunity to reduce cost subject
to certain specification changes. Based on the estimate provided
by TANE and the Companys internal assessments, NINA
continues to believe that its stated target of
$9.8 billion, or $3,229/kW based on 3,000 MW gross
output is achievable. Cost reductions will be achieved through a
combination of specification changes and the re-alignment of
risks and responsibilities among key project stakeholders.
Owners Costs for the project, on an escalated basis, are
estimated to total approximately $2.1 billion during the
construction period. This is primarily comprised of the costs
for NRGs agent STPNOC, owners contingency and the
initial fuel load. Financing Costs are estimated to be
approximately $1.5 billion during the construction period,
and are comprised of the variables described above.
On February 17, 2010, an agreement in principle was reached
with CPS for NINA to acquire a controlling interest in the
project to construct STP Units 3 and 4 through a settlement of
the litigation between the parties. As part of the agreement,
NINA would increase its ownership in the STP Units 3 and 4
project from 50% to 92.375% and would assume full management
control of the project. NINA would also pay $80 million to
CPS, subject to receipt of a conditional DOE loan guarantee. The
first $40 million would be promptly paid after receipt of
the guarantee and the other half six months later. An additional
$10 million would be donated by NRG over four years in
annual payments of $2.5 million to the Residential Energy
Assistance Partnership in San Antonio. As part of the
agreement with CPS, all litigation would be dismissed with
prejudice. The parties continue to negotiate terms regarding
final documentation of the agreement in principle.
The agreement would enable the STP Unit 3 and 4 project
expansion to move forward and allow NINA to continuing pursuing
its application for a conditional loan guarantee from the DOE.
If NINA is not successful in reaching a final settlement with
CPS, obtaining a conditional loan guarantee or selling down its
interest in STP Units 3 and 4, there could be negative
implications for the project that may result in a reassessment
of the probability of success of the project and an impairment
of the value of the capitalized assets for STP Units 3 and 4. An
impairment would result in a permanent write-down of the
$299 million of construction-in-progress capitalized
through December 31, 2009, plus any amounts capitalized
through the impairment date.
Renewable
Development
NRG has routinely invested in the development of renewable
energy projects such as wind, solar and biomass, to support the
Companys econrg initiative. NRGs renewable strategy
is to capitalize on both first mover advantages and the
Companys inherent regional presence. The following are the
renewable development projects that Company is actively engaged
in:
Solar
Development
NRG intends to leverage its market knowledge, functional
expertise, cash position and tax appetite to be the leading
developer and owner of assets in the high growth solar power
industry. The Company intends to align itself with technology
providers who it believes are or will be the leading
technologies in the industry. These strategic relationships will
exist with photovoltaic, or PV, concentrated solar power, or
CSP, Sterling Dish, and storage technologies. NRG will focus on
projects that are supported by long term off-take agreements and
have the ability to
34
secure either commercial bank or DOE funding to maximize equity
returns. In 2009, NRG completed the following activities:
Acquisition and completion of Blythe
Solar On November 20, 2009, NRG,
through its wholly-owned subsidiary NRG Solar LLC, acquired FSE
Blythe 1, LLC, or Blythe Solar, from First Solar, Inc. On
December 18, 2009, construction was completed and
commercial operation began for the 20 MW utility-scale PV
solar facility located in Riverside County in southeastern
California. The Blythe Solar PV field provides electricity to
Southern California Edison, or SCE, under a
20-year PPA.
The site uses approximately 350,000 photovoltaic solar modules
that turn sunlight directly into electricity. The Blythe Solar
site covers approximately 200 acres of held land which is
fully permitted and is connected to SCEs electrical
distribution grid. The project is eligible for a cash grant from
the Department of Treasury and NRG will file an application for
an $18 million grant.
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 and
a successful financial closing in 2010. At the closing with
eSolar, NRG invested $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 10 eSolar modular solar generating units at these sites.
These development assets will use eSolars CSP, technology
to sell renewable electricity under contracted PPAs with local
utilities.
NRG has three projects in various stages of development: NRG New
Mexico SunTower, Alpine SunTower and Desert View SunTower. While
each of these projects has an anticipated commercial operation
date, the development of these projects are subject to certain
conditions and milestones which may effect the Companys
decision to pursue further development of these projects.
Wind
Development
NRG is an active participant in both onshore and offshore wind
energy across its core regions. As part of this strategy, the
Company actively engages in the development, acquisition,
divestiture and establishment of joint ventures of wind
projects. In the Northeast, there are strong offshore wind
resources located near major load centers which can support
projects of a size and scale larger than most on land wind and
other renewable projects in the region. NRG looks to achieve a
first-mover advantage in the U.S. offshore wind market through
the development, construction and operation of projects in the
region, as evidenced by the NRGs acquisition of Bluewater
Wind in the fourth quarter 2009. In 2009, NRG completed the
following activities:
Bluewater Wind Acquisition On
November 9, 2009, NRG through its wholly-owned subsidiary,
NRG Bluewater Holdings LLC, completed the acquisition of a 100%
interest in all the subsidiaries of Bluewater Wind LLC (such
subsidiaries, with NRG Bluewater Holdings LLC, or NRG Bluewater)
as part of the Companys strategy to promote development of
renewable energy projects in its core regions. NRG Bluewater
currently has a number of offshore wind energy projects that are
in various stages of development along the eastern seaboard and
the Great Lakes region of the U.S. In Delaware, NRG
Bluewater has a
25-year,
200 MW PPA with Delmarva Power & Light Company
that has been approved by the Delaware Public Service Commission
and other state agencies. On December 8, 2009, NRG
Bluewater was also selected to finalize a power purchase
agreement from the State of Maryland to provide up to 55 MW
of wind generation from the Delaware project. In 2009, NRG
Bluewater was awarded a $4 million rebate from the state of
New Jersey to build a meteorological tower, which would collect
wind and other data from a site off the coast of New Jersey.
Langford Wind Project On
December 8, 2009, NRG announced the completion of its
Langford project, a wholly-owned 150 MW wind farm located
in Tom Green, Irion, and Schleicher Counties, Texas. The Company
funded and developed this wind farm which consists of 100
General Electric 1.5 MW wind turbines. The project is
eligible for a cash grant from the Department of Treasury and
NRG has filed an application for an $84 million grant.
Padoma Wind On January 11, 2010,
NRG sold its terrestrial wind development company, Padoma Wind
Power LLC, or Padoma, to Enel North America, Inc., or Enel. NRG
acquired Padoma in 2006 to develop terrestrial
35
wind projects. NRG is maintaining its existing ownership
interest in its three Texas wind farms Sherbino,
Elbow Creek and Langford. In addition, NRG will maintain a
strategic partnership with Enel to evaluate potential
opportunities in renewable energy. NRG will retain a Right of
First Offer should Enel seek an equity partner in Padoma
projects.
Biomass
Development
NRG has several biomass projects in varying stages of
development, including a pilot project at the Big Cajun II
facility to be renewably fueled with switchgrass and
high-biomass sorghum, as well as the retrofit a steam unit at
Montville Station to enable the unit to use clean wood biomass
to produce up to 40 MW of renewable energy.
Regulatory
Matters
As operators of power plants and participants in wholesale
energy markets, certain NRG entities are subject to regulation
by various federal and state government agencies. These include
the CFTC, FERC, NRC, PUCT and other public utility commissions
in certain states where NRGs generating or thermal assets
are located. In addition, NRG is subject to the market rules,
procedures and protocols of the various ISO markets in which it
participates. Certain of the Reliant Energy entities are
competitive Retail Electric Providers, or REPs, and as such are
subject to the rules and regulations of the PUCT governing REPs.
NRG must also comply with the mandatory reliability requirements
imposed by the North American Electric Reliability Corporation,
or NERC, and the regional reliability councils in the regions
where the Company operates.
The operations of, and wholesale electric sales from, NRGs
Texas region are not subject to rate regulation by the FERC, as
they are deemed to operate solely within the ERCOT market and
not in interstate commerce. As discussed below, these operations
are subject to regulation by PUCT, as well as to regulation by
the NRC with respect to the Companys ownership interest in
STP.
Commodities
Futures Trading Commission, or CFTC
The CFTC, among other things, has regulatory oversight authority
over the trading of electricity and gas commodities, including
financial products and derivatives, under the Commodity Exchange
Act, or CEA. Specifically, under existing statutory authority,
CFTC has the authority to commence enforcement actions and seek
injunctive relief against any person, whenever that person
appears to be engaged in the communication of false or
misleading or knowingly inaccurate reports concerning market
information or conditions that affected or tended to affect the
price of natural gas, a commodity in interstate commerce, or
actions intended to or attempting to manipulate commodity
markets. The CFTC also has the authority to seek civil monetary
penalties, as well as the ability to make referrals to the
Department of Justice for criminal prosecution, in connection
with any conduct that violates the CEA. Proposals are pending in
Congress to expand CFTC oversight of the
over-the-counter
markets and bilateral financial transactions.
Federal
Energy Regulatory Commission
The FERC, among other things, regulates the transmission and the
wholesale sale of electricity in interstate commerce under the
authority of the Federal Power Act, or FPA. In addition, under
existing regulations, the FERC determines whether an entity
owning a generation facility is an Exempt Wholesale Generator,
or EWG, as defined in the Public Utility Holding Company Act of
2005, or PUHCA of 2005. The FERC also determines whether a
generation facility meets the ownership and technical criteria
of a Qualifying Facility, or QF, under Public Utility Regulatory
Policies Act of 1978, or PURPA. Each of NRGs
U.S. generating facilities has either been determined by
the FERC to qualify as a QF, or the subsidiary owning the
facility has been determined to be an EWG.
Federal Power Act The FPA gives the FERC
exclusive rate-making jurisdiction over the wholesale sale of
electricity and transmission of electricity in interstate
commerce. Under the FPA, the FERC, with certain exceptions,
regulates the owners of facilities used for the wholesale sale
of electricity or transmission in interstate commerce as public
utilities. The FPA also gives the FERC jurisdiction to review
certain transactions and numerous other activities of public
utilities. NRGs QFs are currently exempt from the
FERCs rate regulation
36
under Sections 205 and 206 of the FPA to the extent that
sales are made pursuant to a state regulatory authoritys
implementation of PURPA.
Public utilities under the FPA are required to obtain the
FERCs acceptance, pursuant to Section 205 of the FPA,
of their rate schedules for the wholesale sale of electricity.
All of NRGs non-QF generating and power marketing
companies in the U.S. make sales of electricity pursuant to
market-based rates authorized by the FERC. The FERCs
orders that grant NRGs generating and power marketing
companies market-based rate authority reserve the right to
revoke or revise that authority if the FERC subsequently
determines that NRG can exercise market power, create barriers
to entry, or engage in abusive affiliate transactions. In
addition, NRGs market-based sales are subject to certain
market behavior rules and, if any of its generating or power
marketing companies were deemed to have violated any one of
those rules, they would be subject to potential disgorgement of
profits associated with the violation
and/or
suspension or revocation of their market-based rate authority,
as well as criminal and civil penalties. As a condition of the
orders granting NRG market-based rate authority, NRG is required
to file regional market updates demonstrating that it continues
to meet the FERCs standards with respect to generating
market power and other criteria used to evaluate whether its
entities qualify for market-based rates. NRG is also required to
report to the FERC any material changes in status that would
reflect a departure from the characteristics that the FERC
relied upon when granting NRGs various generating and
power marketing companies market-based rates. If NRGs
generating and power marketing companies were to lose their
market-based rate authority, such companies would be required to
obtain the FERCs acceptance of a
cost-of-service
rate schedule and could become subject to the accounting,
record-keeping, and reporting requirements that are imposed on
utilities with cost-based rate schedules.
On April 27, 2009 and July 21, 2009, FERC accepted the
Companys updated market power analyses for its Northeast
and South Central assets, respectively. NRGs next such
market power update filing is due June 30, 2010, for its
CAISO and southwest assets.
Section 203 of the FPA requires the FERCs prior
approval for the transfer of control of assets subject to the
FERCs jurisdiction. Section 204 of the FPA gives the
FERC jurisdiction over a public utilitys issuance of
securities or assumption of liabilities. However, the FERC
typically grants blanket approval for future securities
issuances and the assumption of liabilities to entities with
market-based rate authority. In the event that one of NRGs
generating and power marketing companies were to lose its
market-based rate authority, such companys future
securities issuances or assumption of liabilities could require
prior approval from the FERC.
In compliance with Section 215 of the Energy Policy Act of
2005, or EPAct of 2005, the FERC has approved the NERC as the
national Energy Reliability Organization, or ERO. As the ERO,
NERC is responsible for the development and enforcement of
mandatory reliability standards for the wholesale electric power
system. NRG is responsible for complying with the standards in
the regions in which it operates. As the ERO, NERC has the
ability to assess financial penalties for non-compliance. In
addition to complying with NERC requirements, each NRG entity
must comply with the requirements of the regional reliability
entity for the region in which it is located.
Public Utility Holding Company Act of 2005
PUHCA of 2005 provides the FERC with certain authority over
and access to books and records of public utility holding
companies not otherwise exempt by virtue of their ownership of
EWGs, QFs, and Foreign Utility Companies, or FUCOs. NRG is a
public utility holding company, but because all of the
Companys generating facilities have QF status or are owned
through EWGs, it is exempt from the accounting, record
retention, and reporting requirements of the PUHCA of 2005.
Public Utility Regulatory Policies Act PURPA
was passed in 1978 in large part to promote increased energy
efficiency and development of independent power producers. PURPA
created QFs to further both goals, and the FERC is primarily
charged with administering PURPA as it applies to QFs. As
discussed above, under current law, some categories of QFs may
be exempt from regulation under the FPA as public utilities.
PURPA incentives also initially included a requirement that
utilities must buy and sell power to QFs. Among other things,
EPAct of 2005 provides for the elimination of the obligation
imposed on certain utilities to purchase power from QFs at an
avoided cost rate under certain conditions. However, the
purchase obligation is only eliminated if the FERC first finds
that a QF has non-discriminatory access to wholesale energy
markets having certain characteristics, including
nondiscriminatory transmission and interconnection services
provided by a regional transmission entity in certain
circumstances. Existing contracts entered into under PURPA are
not expected to be impacted. NRG
37
currently owns only one QF, Saguaro Power Company, a Limited
Partnership, which is interconnected to and has a contract with
Nevada Power Company. Nevada Power Company is not located in a
region with an ISO market.
Nuclear
Regulatory Commission, or NRC
The NRC is authorized under the Atomic Energy Act of 1954, as
amended, or the AEA, among other things, to grant licenses for,
and regulate the operation of, commercial nuclear power
reactors. As a holder of an ownership interest in STP, NRG is an
NRC licensee and is subject to NRC regulation. The NRC license
gives the Company the right to only possess an interest in STP
but not to operate it. Operating authority under the NRC
operating license for STP is held by STPNOC. NRC regulation
involves licensing, inspection, enforcement, testing,
evaluation, and modification of all aspects of plant design and
operation including the right to order a plant shutdown,
technical and financial qualifications, and decommissioning
funding assurance in light of NRC safety and environmental
requirements. In addition, NRCs written approval is
required prior to a licensee transferring an interest in its
license, either directly or indirectly. As a possession-only
licensee, i.e., non-operating co-owner, the NRCs
regulation of NRG is primarily focused on the Companys
ability to meet its financial and decommissioning funding
assurance obligations. In connection with the NRC license, the
Company and its subsidiaries have a support agreement to provide
up to $120 million to support operations at STP.
Decommissioning Trusts Upon expiration of the
operation licenses for the two generating units at STP,
currently scheduled for 2027 and 2028, the co-owners of STP are
required under federal law to decontaminate and decommission the
STP facility. Under NRC regulations, a power reactor licensee
generally must pre-fund the full amount of its estimated NRC
decommissioning obligations unless it is a rate-regulated
utility, or a state or municipal entity that sets its own rates,
or has the benefit of a state-mandated non-bypassable charge
available to periodically fund the decommissioning trust such
that the trust, plus allowable earnings, will equal the
estimated decommissioning obligations by the time the
decommissioning is expected to begin.
As a result of the acquisition of Texas Genco, NRG, through its
44% ownership interest, has become the beneficiary of
decommissioning trusts that have been established to provide
funding for decontamination and decommissioning of STP.
CenterPoint Energy Houston Electric, LLC, or CenterPoint, and
American Electric Power, or AEP, collect, through rates or other
authorized charges to their electric utility customers, amounts
designated for funding NRGs portion of the decommissioning
of the facility. See also Item 14 Note 7,
Nuclear Decommissioning Trust Fund, to the
Consolidated Financial Statements for additional discussion.
In the event that the funds from the trusts are ultimately
determined to be inadequate to decommission the STP facilities,
the original owners of the Companys STP interests,
CenterPoint and AEP, each will be required to collect, through
their PUCT-authorized non-bypassable rates or other charges to
customers, additional amounts required to fund NRGs
obligations relating to the decommissioning of the facility.
Following the completion of the decommissioning, if surplus
funds remain in the decommissioning trusts, those excesses will
be refunded to the respective rate payers of CenterPoint or AEP,
or their successors.
Public
Utility Commission of Texas, or PUCT
NRGs Texas generation subsidiaries are registered as power
generation companies with the PUCT. The PUCT also has
jurisdiction over power generation companies with regard to
their sales in the wholesale markets, the implementation of
measures to address undue market power or price volatility, and
the administration of nuclear decommissioning trusts. The PUCT
exercises its jurisdiction both directly, and indirectly,
through its oversight of the ERCOT, the regional transmission
organization. Certain of its subsidiaries within the Texas
region are also subject to regulatory oversight as a power
marketer or as a Qualified Scheduling Entity. NRG Power
Marketing, LLC, or PMI, is registered as a power marketer with
the PUCT and thus is also subject to the jurisdiction of the
PUCT with respect to its sales in the ERCOT. Certain of the
Reliant Energy entities are competitive Retail Electric
Providers, or REPs, and as such are subject to the rules and
regulations of the PUCT governing REPs.
Regional
Regulatory Developments
In New England, New York, the Mid-Atlantic region, the Midwest
and California, the FERC has approved regional transmission
organizations, also commonly referred to as ISOs. Most of these
ISOs administer a wholesale
38
centralized bid-based spot market in their regions pursuant to
tariffs approved by the FERC and associated ISO market rules.
These tariffs/market rules dictate how the capacity and energy
markets operate, how market participants may make bilateral
sales with one another, and how entities with market-based rates
are compensated within those markets. The ISOs in these regions
also control access to and the operation of the transmission
grid within their regions. In Texas, pursuant to a 1999
restructuring statute, the PUCT granted similar responsibilities
to the ERCOT.
NRG is affected by rule/tariff changes that occur in the ISO
regions. The ISOs that oversee most of the wholesale power
markets have in the past imposed, and may in the future continue
to impose, price limitations and other mechanisms to address
market power or volatility in these markets. These types of
price limitations and other regulatory mechanisms may adversely
affect the profitability of NRGs generation facilities
that sell capacity and energy into the wholesale power markets.
In addition, new approaches to the sale of electric power are
being implemented, and it is not clear whether they will operate
effectively or whether they will provide adequate compensation
to generators over the long-term.
For further discussion on regulatory developments see
Item 14 Note 23, Regulatory
Matters, to the Consolidated Financial Statements.
Texas
Region
The ERCOT has adopted Texas Nodal Protocols that
will revise the wholesale market design to incorporate
locational marginal pricing (in place of the current ERCOT zonal
market). Major elements of the Texas Nodal Protocols include the
continued capability for bilateral contracting of energy and
ancillary services, a financially binding day-ahead market,
resource-specific energy and ancillary service offer curves, the
direct assignment of all congestion rents, nodal energy prices
for resources, aggregation of nodal to zonal energy prices for
loads, congestion revenue rights (including pre-assignment for
public power entities), and pricing safeguards. The PUCT
approved the Texas Nodal Protocols on April 5, 2006, and
full implementation of the new market design was scheduled to
begin in 2008. On May 20, 2008, the ERCOT announced that it
would delay the implementation of the Texas Nodal Protocols, and
is now targeting a December 2010 implementation.
On October 6, 2008, as part of its determination of
Competitive Renewable Energy Zones, or CREZ, the 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.
There are various appeals and other challenges to CREZ that
could disrupt or delay the schedule. 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.
Northeast
Region
New England NRGs Middletown, Montville
and Norwalk facilities continue to be operated pursuant to RMR
agreements. Unless terminated earlier, these RMR agreements will
terminate upon the commencement of the FCM on June 1, 2010.
New York The state-wide Installed Reserve
Margin, or IRM, is set annually by the New York State
Reliability Council, or NYSRC, and affects the overall demand
for capacity in the New York market. The NYSRC approved a 2010
IRM of 18%, which is an increase of 1.5% from the 2009
requirement. This increase may be offset
39
by lower load forecasts for 2010. On January 29, 2008, the
FERC accepted the NYISOs installed capacity demand curves
for 2008/2009, 2009/2010, and 2010/2011. The demand curves are a
critical determinant of capacity market prices. Of particular
note to the New York City capacity market, New York Power
Authority, or NYPA, retired its 885 MW Poletti facility on
January 31, 2010.
West
Region
California The CAISO 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.
Environmental
Matters
NRG is subject to a wide range of environmental regulations
across a broad number of jurisdictions in the development,
ownership, construction and operation of domestic and
international projects. These laws and regulations generally
require that governmental permits and approvals be obtained
before construction and during operation of power plants.
Environmental laws have become increasingly stringent in recent
years, especially around the regulation of air emissions from
power generators. Such laws generally require regular capital
expenditures for power plant upgrades, modifications and the
installation of certain pollution control equipment. In general,
future laws and regulations are expected to require the addition
of emission controls or other environmental quality equipment or
the imposition of certain restrictions on the operations of the
Companys facilities. NRG expects that future liability
under, or compliance with, environmental requirements could have
a material effect on the Companys operations or
competitive position.
Federal
Environmental Initiatives
Climate Change The United States
signed the Copenhagen Accord, or the Accord, which sets the
stage for a worldwide approach to this global issue. Under the
Accord, the U.S. has committed to a 17% reduction from 2005
emission levels of GHGs by 2020. While Congress was unable to
come to agreement on climate legislation in 2009, the subject
continues to be a topic for consideration in 2010. Lack of
legislation will prolong the uncertainty associated with the
nature and timing of GHG requirements, and therefore impact on
NRG.
On December 15, 2009, the U.S. EPA issued a final rule
finding that a mix of six key GHGs in the atmosphere, carbon
dioxide, methane, nitrous oxide, hydrofluorocarbons,
perfluorocarbons and sulfur hexafluoride, threaten the public
health and welfare. This action paves the way for finalization
of the September 28, 2009, Proposed GHG Emissions
Standards for Motor Vehicles. These actions are in response
to the Supreme Courts decision in Massachusetts v.
U.S. EPA, which requires the U.S. EPA to decide
under the Clean Air Acts, or CAA, mobile source title
whether GHGs contribute to climate change, and if so, promulgate
appropriate regulations. Under the CAA, these regulations would
render GHGs regulated pollutants and subject them to other
existing requirements that affect stationary sources, including
power plants. The primary impact on NRG would be a statutory
requirement to install Best Available Control Technology, or
BACT, determined on a
case-by-case
basis, for major modifications or improvements at power plants
if they cause GHG emissions to increase by the statutory
Prevention of Significant Deterioration, or PSD limits of 100
tons per year. The U.S. EPA also released, on
September 30, 2009, a draft PSD tailoring rule for GHGs
that would increase the major stationary source threshold of
25,000 tons per year of carbon dioxide equivalents. This
threshold level would be used to determine (i) if an
existing source would be required to obtain a Title V
operating permit and (ii) if a new facility or a major
modification at an existing facility would trigger PSD
permitting requirements. Existing major sources making
modifications that result in an increase of emissions above the
significance level would be required to obtain a PSD permit and
install BACT. The timing and implementation of the final motor
vehicle rule, acceptance of the PSD tailoring rule and
U.S. EPAs approach to BACT for GHGs could affect the
level of impact to NRGs plants, and future repowering
projects that have not completed their permitting process.
In 2009, in the course of producing approximately
71 million MWh of electricity, NRGs power plants
emitted 59 million tonnes of
CO2,
of which 53 million tonnes were emitted in the U.S.,
3 million tonnes in Germany and
40
3 million tonnes in Australia. The impact from legislation
or federal, regional or state regulation of GHGs on the
Companys financial performance will depend on a number of
factors, including the overall level of GHG reductions required
under any such regulations, the price and availability of
offsets, and the extent to which NRG would be entitled to
receive
CO2
emissions allowances without having to purchase them in an
auction or on the open market. Thereafter, under any such
legislation or regulation, the impact on NRG would depend on the
Companys level of success in developing and deploying low
and no carbon technologies such as those being pursued as part
of RepoweringNRG. Additionally, NRGs current
contracts with its South Central regions cooperative
customers allows for the recovery of emission-based costs.
Regulations A number of regulations
are under review by U.S. EPA including CAIR, MACT, National
Ambient Air Quality Standards, or NAAQS, for ozone, nitrogen
dioxide,
SO2,
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, NRGs planned
environmental capital expenditures include 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, or BTA, under
Phase II 316(b) Rule. NRG continues to explore
cost-effective alternatives that can achieve desired results.
This planned investment 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.
Air 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 grant
of reconsideration and administrative stay of the
PM2.5
Implementation Rule was published in the Federal Register
on June 1, 2009. While none of these actions directly
impact NRG at this point, it is unknown if any such final rules
will impact future projects.
CAIR applies to 28 eastern states and Washington D.C., and caps
both
SO2
and
NOx
emissions from power plants in two phases. CAIR applies to most
of the Companys power plants in the states of New York,
Massachusetts, Connecticut, Delaware, Louisiana, Illinois,
Pennsylvania, Maryland and Texas. The CAIR
NOx
trading program went into effect on January 1, 2009 and
remains in effect. Vintage 2010 and later
SO2
Acid Rain Program allowances in the CAIR region will be
discounted on a 2:1 basis beginning January 1, 2010. The
timing and substantive provisions of any ensuing revised or
replacement regulations or legislation may alter the composition
and/or rate
of spending for environmental retrofits at the Companys
facilities.
In a ruling on December 22, 2006, the U.S. Court of
Appeals for the District of Columbia, or D.C. Circuit,
overturned portions of the U.S. EPAs Phase I
implementation rule for the new
eight-hour
ozone standard. Specifically, the D.C. Circuit ruled that the
U.S. EPA could revoke the
one-hour
standard as long as there was no backsliding from more stringent
control measures. This ruling could result in the imposition of
fees under Section 185 of the CAA on volatile organic
carbon, or VOC, and
NOx
emissions in severe non-attainment areas. The fees could be as
high as $7,700/ton for emissions above 80% of baseline emissions
levels. Depending on the determination of baseline emission
levels, this could materially impact NRGs operations in
Los Angeles, New York City Area and Houston.
The U.S. EPA strengthened the primary and secondary ground
level ozone NAAQS, (eight hour average) from 0.08 ppm to
0.075 ppm on March 12, 2008. The U.S. EPA plans
to finalize ozone non-attainment regions by March 2010 and
states would likely submit plans to come into attainment by
2013. The Company is unable to predict with certainty the impact
of the states future recommendations on NRGs
operations.
In the 1990s, the U.S. EPA commenced an industry-wide
investigation of coal-fired electric generators to determine
compliance with environmental requirements under the CAA
associated with repairs, maintenance, modifications and
operational changes made to facilities over the years. As a
result, the U.S. EPA and several states filed suits against
a number of coal-fired power plants in mid-western and southern
states alleging violations of the CAA, NSR, and, PSD
requirements. The U.S. EPA previously issued two Notices of
Violation, or NOV, against NRGs Big Cajun II plant
alleging that NRGs predecessors had undertaken projects
that triggered requirements under the PSD program, including the
installation of emission controls. NRG has evaluated the claims
and believes
41
they have no merit. Further discussion on this matter can be
found in Item 14 Note 22, Commitments
and Contingencies, Louisiana Generating, LLC, to the
Consolidated Financial Statements.
Water In July 2004, the U.S. EPA
published rules governing cooling water intake structures at
existing power facilities commonly referred to as the
Phase II 316(b) rules. These rules specify standards for
cooling water intake structures at existing power plants using
the largest amounts of cooling water. These rules will require
implementation of the BTA for minimizing adverse environmental
impacts unless a facility shows that such standards would result
in very high costs or little environmental benefit. As a result
of a decision by the Second Circuit Court of Appeals, the
U.S. EPA suspended the rule in July 2007 while preparing a
revised version. The U.S. Supreme Court released a decision
on the challenge on April 1, 2009, in which it concluded
that the U.S. EPA does have the authority to allow a
cost-benefit analysis in the evaluation of 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. In the absence of federal regulations, some states in
which NRG operates, such as California, Connecticut, Delaware
and New York, are moving ahead with guidance for more stringent
requirements for once-through cooled units which may have an
impact on future operations.
Nuclear Waste The Obama administration
has determined that Yucca Mountain, Nevada is not a workable
option for a nuclear waste repository and will discontinue its
program to construct a repository at the mountain in 2010. In
order to meet the federal governments obligations to
safely manage used nuclear fuel and radioactive waste under the
U.S. Nuclear Waste Policy Act of 1982, the Department of
Energy has announced the establishment of a blue ribbon
commission to explore alternatives. Consistent with the
U.S. Nuclear Waste Policy Act of 1982, owners of nuclear
plants, including the owners of STP, entered into contracts
setting out the obligations of the owners and the DOE including
the fees to be paid by the owners for DOEs services. Since
1998, the DOE has been in default on its obligations to begin
removing spent nuclear fuel and high-level radioactive waste
from reactors.
Under the federal Low-Level Radioactive Waste Policy Act of
1980, as amended, the state of Texas is required to provide,
either on its own or jointly with other states in a compact, for
the disposal of all low-level radioactive waste generated within
the state. In 2003, the state of Texas enacted legislation
allowing a private entity to be licensed to accept low-level
radioactive waste for disposal. NRG intends to continue to ship
low-level waste material from STP offsite for as long as an
alternative disposal site is available. Should existing off-site
disposal become unavailable, the low-level waste material will
then be stored
on-site.
STPs
on-site
storage capacity is expected to be adequate for STPs needs
until other off-site facilities become available.
Regional
U.S. Environmental Initiatives
West
Region
Under AB32, which was enacted in 2007, the state of California
will launch a multi sector climate change program which likely
will include, among other things, a phased
cap-and-trade
approach starting in 2012 and an increased use of renewable
energy. NRG does not expect any implementation of
cap-and-trade
under AB32 in California to have a significant adverse financial
impact on the Company for a variety of reasons, including the
fact that NRGs California portfolio consists of natural
gas-fired peaking facilities and will likely be able to pass
through any costs of purchasing allowances in power prices.
South
Central Region
On 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
Item 3 Legal Proceedings, United States of
America v. Louisiana Generating, LLC.
Domestic
Site Remediation Matters
Under certain federal, state and local environmental laws and
regulations, a current or previous owner or operator of any
facility, including an electric generating facility, may be
required to investigate and remediate
42
releases or threatened releases of hazardous or toxic substances
or petroleum products at the facility. NRG may also be held
liable to a governmental entity or to third parties for property
damage, personal injury and investigation and remediation costs
incurred by a party in connection with hazardous material
releases or threatened releases. These laws, including the
Comprehensive Environmental Response, Compensation and Liability
Act of 1980 as amended by the Superfund Amendments and
Reauthorization Act of 1986, or SARA, impose liability without
regard to whether the owner knew of or caused the presence of
the hazardous substances, and the courts have interpreted
liability under such laws to be strict (without fault) and joint
and several. Cleanup obligations can often be triggered during
the closure or decommissioning of a facility, in addition to
spills or other occurrences during its operations.
In January 2006, NRGs Indian River Operations, Inc.
received a letter of informal notification from the DNREC
stating that it may be a potentially responsible party with
respect to Burton Island Old Ash Landfill, a historic captive
landfill located at the Indian River facility. On
October 1, 2007, NRG signed an agreement with the DNREC to
investigate the site through the Voluntary
Clean-up
Program. On February 4, 2008, the DNREC issued findings
that no further action is required in relation to surface water
and that a previously planned shoreline stabilization project
would adequately address shore line erosion. The landfill itself
will require a further Remedial Investigation and Feasibility
Study to determine the type and scope of any additional work
required. Until the Remedial Investigation and Feasibility Study
is completed, the Company is unable to predict the impact of any
required remediation.
On May 29, 2008, the DNREC issued an invitation to
NRGs Indian River Operations, Inc. to participate in the
development and performance of a Natural Resource Damage
Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG
is currently working with the DNREC and other Trustees to close
out the matter.
Further details regarding the Companys Domestic Site
Remediation obligations can be found in Item 14
Note 24, Environmental Matters, to the Consolidated
Financial Statements.
International
Environmental Matters
Most of the foreign countries in which NRG owns, may acquire or
develop independent power projects have environmental and safety
laws or regulations relating to the ownership or operation of
electric power generation facilities. These laws and
regulations, like those in the U.S., are constantly evolving and
have a significant impact on international wholesale power
producers. In particular, NRGs international power
generation facilities will likely be affected by emissions
limitations and operational requirements imposed by the Kyoto
Protocol, an international treaty related to greenhouse gas
emissions enacted on February 16, 2005, as well as
country-based restrictions pertaining to global climate change
concerns.
NRG retains appropriate advisors in foreign countries and seeks
to design its international asset management strategy to comply
with each countrys environmental and safety laws and
regulations. There can be no assurance that changes in such laws
or regulations will not adversely affect the Companys
international operations.
Schkopau, Germany The cost of
compliance with the
CO2
regulation for NRGs Schkopau plant is passed through to
its off-taker of energy under terms of its existing PPA.
Gladstone, Australia On
December 3, 2007, Australia ratified the Kyoto Protocol
that commits to targets for GHG reductions. Australia also set a
target to reduce greenhouse gas emissions to 60% of 2000 levels
by 2050. The government established a single national system for
reporting of GHG, abatement actions and energy consumption and
generation on July 1, 2008. This will underpin the
Australian Emissions Trading Scheme, currently being debated in
the Parliament. If it is passed into law, it is not expected to
be effective until 2012. NRG may be able to mitigate its
exposure to such law by getting free credits
and/or
contractually passing the obligation to buy credits on to its
counterparties.
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2010
through 2014 to meet NRGs environmental commitments will
be approximately $0.9 billion. These capital expenditures,
in general, are related to installation of particulate,
SO2,
NOx
and mercury controls to comply with federal and state air
quality rules and consent orders, as well as installation of
Best Technology
43
Available under the Phase II 316(b) rule. NRG
continues to explore cost effective alternatives that can
achieve desired results. While this estimate reflects schedules
and controls to meet anticipated reduction requirements, the
full impact on the scope and timing of environmental retrofits
cannot be determined until issuance of final rules by the
U.S. EPA.
The following table summarizes the estimated environmental
capital expenditures for the referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
|
|
|
$
|
230
|
|
|
$
|
3
|
|
|
$
|
233
|
|
2011
|
|
|
|
|
|
|
179
|
|
|
|
52
|
|
|
|
231
|
|
2012
|
|
|
6
|
|
|
|
45
|
|
|
|
108
|
|
|
|
159
|
|
2013
|
|
|
39
|
|
|
|
9
|
|
|
|
109
|
|
|
|
157
|
|
2014
|
|
|
50
|
|
|
|
4
|
|
|
|
68
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
95
|
|
|
$
|
467
|
|
|
$
|
340
|
|
|
$
|
902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
This estimate reflects the recent announcement to retrofit only
Unit 4 at the Indian River Generating Station and shifts in the
timing of other projects to reflect anticipated issuance dates
for revised regulations.
NRGs current contracts with the Companys rural
electrical customers in the South Central region allow for
recovery of a significant portion of the regions capital costs,
along with a capital return incurred by complying with new laws,
including interest over the asset life of the required
expenditures. Actual recoveries will depend, among other things,
on the duration of the contracts.
Available
Information
NRGs annual reports on
Form 10-K,
quarterly reports on
Form 10-Q,
current reports on
Form 8-K,
and amendments to those reports filed or furnished pursuant to
section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended, or Exchange Act, are available free of charge
through the Companys website, www.nrgenergy.com, as soon
as reasonably practicable after they are electronically filed
with, or furnished to the SEC. The Company also routinely posts
press releases, presentations, webcasts, and other information
regarding the Company on the Companys website.
|
|
Item 1A
|
Risk
Factors Related to NRG Energy, Inc.
|
Many
of NRGs power generation facilities operate, wholly or
partially, without long-term power sale
agreements.
Many of NRGs facilities operate as merchant
facilities without long-term power sales agreements for some or
all of their generating capacity and output, and therefore are
exposed to market fluctuations. Without the benefit of long-term
power sales agreements for these assets, NRG cannot be sure that
it will be able to sell any or all of the power generated by
these facilities at commercially attractive rates or that these
facilities will be able to operate profitably. This could lead
to future impairments of the Companys property, plant and
equipment or to the closing of certain of its facilities,
resulting in economic losses and liabilities, which could have a
material adverse effect on the Companys results of
operations, financial condition or cash flows.
NRGs
financial performance may be impacted by changing natural gas
prices, significant and unpredictable price fluctuations in the
wholesale power markets and other market factors that are beyond
the Companys control.
A significant percentage of the Companys domestic revenues
are derived from baseload power plants that are fueled by coal.
In many of the competitive markets where NRG operates, the price
of power typically is set by natural gas-fired power plants that
currently have substantially higher variable costs than
NRGs coal-fired baseload power plants. This allows the
Companys baseload coal generation assets to earn
attractive operating margins compared to plants fueled by
natural gas. A decrease in natural gas prices could result in a
corresponding decrease in
44
the market price of power that could significantly reduce the
operating margins of the Companys baseload generation
assets and materially and adversely impact its financial
performance.
In addition, because changes in power prices in the markets
where NRG operates are generally correlated with changes in
natural gas prices, NRGs hedging portfolio includes
natural gas derivative instruments to hedge power prices for its
baseload generation. If this correlation between power prices
and natural gas prices is not maintained and a change in gas
prices is not proportionately offset by a change in power
prices, the Companys natural gas hedges may not fully
cover this differential. This could have a material adverse
impact on the Companys cash flow and financial position.
Market prices for power, capacity and ancillary services tend to
fluctuate substantially. Unlike most other commodities, electric
power can only be stored on a very limited basis and generally
must be produced concurrently with its use. As a result, power
prices are subject to significant volatility from supply and
demand imbalances, especially in the day-ahead and spot markets.
Long- and short-term power prices may also fluctuate
substantially due to other factors outside of the Companys
control, including:
|
|
|
|
|
changes in generation capacity in the Companys markets,
including the addition of new supplies of power from existing
competitors or new market entrants as a result of the
development of new generation plants, expansion of existing
plants or additional transmission capacity;
|
|
|
|
electric supply disruptions, including plant outages and
transmission disruptions;
|
|
|
|
changes in power transmission infrastructure;
|
|
|
|
fuel transportation capacity constraints;
|
|
|
|
weather conditions;
|
|
|
|
changes in the demand for power or in patterns of power usage,
including the potential development of demand-side management
tools and practices;
|
|
|
|
development of new fuels and new technologies for the production
of power;
|
|
|
|
regulations and actions of the ISOs; and
|
|
|
|
federal and state power market and environmental regulation and
legislation.
|
These factors have caused the Companys operating results
to fluctuate in the past and will continue to cause them to do
so in the future.
NRGs
costs, results of operations, financial condition and cash flows
could be adversely impacted by disruption of its fuel
supplies.
NRG relies on coal, oil and natural gas to fuel a majority of
its power generation facilities. Delivery of these fuels to the
facilities is dependent upon the continuing financial viability
of contractual counterparties as well as upon the infrastructure
(including rail lines, rail cars, barge facilities, roadways,
and natural gas pipelines) available to serve each generation
facility. As a result, the Company is subject to the risks of
disruptions or curtailments in the production of power at its
generation facilities if a counterparty fails to perform or if
there is a disruption in the fuel delivery infrastructure.
NRG has sold forward a substantial portion of its baseload power
in order to lock in long-term prices that it deemed to be
favorable at the time it entered into the forward sale
contracts. In order to hedge its obligations under these forward
power sales contracts, the Company has entered into long-term
and short-term contracts for the purchase and delivery of fuel.
Many of the forward power sales contracts do not allow the
Company to pass through changes in fuel costs or discharge the
power sale obligations in the case of a disruption in fuel
supply due to force majeure events or the default of a fuel
supplier or transporter. Disruptions in the Companys fuel
supplies may therefore require it to find alternative fuel
sources at higher costs, to find other sources of power to
deliver to counterparties at a higher cost, or to pay damages to
counterparties for failure to deliver power as contracted. Any
such event could have a material adverse effect on the
Companys financial performance.
45
NRG also buys significant quantities of fuel on a short-term or
spot market basis. Prices for all of the Companys fuels
fluctuate, sometimes rising or falling significantly over a
relatively short period of time. The price NRG can obtain for
the sale of energy may not rise at the same rate, or may not
rise at all, to match a rise in fuel or delivery costs. This may
have a material adverse effect on the Companys financial
performance. Changes in market prices for natural gas, coal and
oil may result from the following:
|
|
|
|
|
weather conditions;
|
|
|
|
seasonality;
|
|
|
|
demand for energy commodities and general economic conditions;
|
|
|
|
disruption or other constraints or inefficiencies of
electricity, gas or coal transmission or transportation;
|
|
|
|
additional generating capacity;
|
|
|
|
availability and levels of storage and inventory for fuel stocks;
|
|
|
|
natural gas, crude oil, refined products and coal production
levels;
|
|
|
|
changes in market liquidity;
|
|
|
|
federal, state and foreign governmental regulation and
legislation; and
|
|
|
|
the creditworthiness and liquidity and willingness of fuel
suppliers/transporters to do business with the Company.
|
NRGs plant operating characteristics and equipment,
particularly at its coal-fired plants, often dictate the
specific fuel quality to be combusted. The availability and
price of specific fuel qualities may vary due to supplier
financial or operational disruptions, transportation disruptions
and force majeure. At times, coal of specific quality may not be
available at any price, or the Company may not be able to
transport such coal to its facilities on a timely basis. In this
case, the Company may not be able to run the coal facility even
if it would be profitable. Operating a coal facility with
different quality coal can lead to emission or operating
problems. If the Company had sold forward the power from such a
coal facility, it could be required to supply or purchase power
from alternate sources, perhaps at a loss. This could have a
material adverse impact on the financial results of specific
plants and on the Companys results of operations.
There
may be periods when NRG will not be able to meet its commitments
under forward sale obligations at a reasonable cost or at
all.
A substantial portion of the output from NRGs baseload
facilities has been sold forward under fixed price power sales
contracts through 2014, and the Company also sells forward the
output from its intermediate and peaking facilities when it
deems it commercially advantageous to do so. Because the
obligations under most of these agreements are not contingent on
a unit being available to generate power, NRG is generally
required to deliver power to the buyer, even in the event of a
plant outage, fuel supply disruption or a reduction in the
available capacity of the unit. To the extent that the Company
does not have sufficient lower cost capacity to meet its
commitments under its forward sale obligations, the Company
would be required to supply replacement power either by running
its other, higher cost power plants or by obtaining power from
third-party sources at market prices that could substantially
exceed the contract price. If NRG fails to deliver the
contracted power, it would be required to pay the difference
between the market price at the delivery point and the contract
price, and the amount of such payments could be substantial.
In the South Central region, NRG has long-term contracts with
rural cooperatives that require it to serve all of the
cooperatives requirements at prices that generally reflect
the costs of coal-fired generation. During limited peak demand
periods, the load requirements of these contract customers
exceed the baseload capacity of NRGs coal-fired Big
Cajun II plant. During such peak demand periods, NRG either
employs its owned or leased gas-fired assets or purchases power
from external sources and, depending upon the then-current gas
commodity pricing, these purchases can be at higher prices than
can be recovered under the Companys contracts. NRGs
financial returns from its South Central region could be
negatively impacted for a limited period if the rural
cooperatives
46
significantly grow their customer base during the remaining
terms of these contracts prior to the expiration of half of the
cooperative contracts in 2014. In addition, NRG has other
obligations to supply power to load serving entities and, at
times, NRGs load obligations may exceed its available
generation and long-term purchases thus requiring the Company to
purchase energy at market prices.
NRGs
trading operations and the use of hedging agreements could
result in financial losses that negatively impact its results of
operations.
The Company typically enters into hedging agreements, including
contracts to purchase or sell commodities at future dates and at
fixed prices, in order to manage the commodity price risks
inherent in its power generation operations. These activities,
although intended to mitigate price volatility, expose the
Company to other risks. When the Company sells power forward, it
gives up the opportunity to sell power at higher prices in the
future, which not only may result in lost opportunity costs but
also may require the Company to post significant amounts of cash
collateral or other credit support to its counterparties. The
Company also relies on counterparty performance under its
hedging agreements and is exposed to the credit quality of its
counterparties under those agreements. Further, if the values of
the financial contracts change in a manner that the Company does
not anticipate, or if a counterparty fails to perform under a
contract, it could harm the Companys business, operating
results or financial position.
NRG does not typically hedge the entire exposure of its
operations against commodity price volatility. To the extent it
does not hedge against commodity price volatility, the
Companys results of operations and financial position may
be improved or diminished based upon movement in commodity
prices.
NRG may engage in trading activities, including the trading of
power, fuel and emissions allowances that are not directly
related to the operation of the Companys generation
facilities or the management of related risks. These trading
activities take place in volatile markets and some of these
trades could be characterized as speculative. The Company would
expect to settle these trades financially rather than through
the production of power or the delivery of fuel. This trading
activity may expose the Company to the risk of significant
financial losses which could have a material adverse effect on
its business and financial condition.
NRG
may not have sufficient liquidity to hedge market risks
effectively.
The Company is exposed to market risks through its power
marketing business, which involves the sale of energy, capacity
and related products and the purchase and sale of fuel,
transmission services and emission allowances. These market
risks include, among other risks, volatility arising from
location and timing differences that may be associated with
buying and transporting fuel, converting fuel into energy and
delivering the energy to a buyer.
NRG undertakes these marketing activities through agreements
with various counterparties. Many of the Companys
agreements with counterparties include provisions that require
the Company to provide guarantees, offset of netting
arrangements, letters of credit, a first or second lien on
assets
and/or cash
collateral to protect the counterparties against the risk of the
Companys default or insolvency. The amount of such credit
support that must be provided typically is based on the
difference between the price of the commodity in a given
contract and the market price of the commodity. Significant
movements in market prices can result in the Company being
required to provide cash collateral and letters of credit in
very large amounts. The effectiveness of the Companys
strategy may be dependent on the amount of collateral available
to enter into or maintain these contracts, and liquidity
requirements may be greater than the Company anticipates or will
be able to meet. Without a sufficient amount of working capital
to post as collateral in support of performance guarantees or as
a cash margin, the Company may not be able to manage price
volatility effectively or to implement its strategy. An increase
in the amount of letters of credit or cash collateral required
to be provided to the Companys counterparties may
negatively affect the Companys liquidity and financial
condition.
Further, if any of NRGs facilities experience unplanned
outages, the Company may be required to procure replacement
power at spot market prices in order to fulfill contractual
commitments. Without adequate liquidity to meet margin and
collateral requirements, the Company may be exposed to
significant losses, may miss significant opportunities, and may
have increased exposure to the volatility of spot markets.
47
The
accounting for NRGs hedging activities may increase the
volatility in the Companys quarterly and annual financial
results.
NRG engages in commodity-related marketing and price-risk
management activities in order to financially hedge its exposure
to market risk with respect to electricity sales from its
generation assets, fuel utilized by those assets and emission
allowances.
NRG generally attempts to balance its fixed-price physical and
financial purchases and sales commitments in terms of contract
volumes and the timing of performance and delivery obligations
through the use of financial and physical derivative contracts.
These derivatives are accounted for in accordance with ASC-815,
Derivatives and Hedging, or ASC 815, which requires the
Company to record all derivatives on the balance sheet at fair
value with changes in the fair value resulting from fluctuations
in the underlying commodity prices immediately recognized in
earnings, unless the derivative qualifies for cash flow hedge
accounting treatment. Whether a derivative qualifies for cash
flow hedge accounting treatment depends upon it meeting specific
criteria used to determine if the cash flow hedge is and will
remain appropriate for the term of the derivative. All economic
hedges may not necessarily qualify for cash flow hedge
accounting treatment. As a result, the Companys quarterly
and annual results are subject to significant fluctuations
caused by changes in market prices.
Competition
in wholesale power markets may have a material adverse effect on
NRGs results of operations, cash flows and the market
value of its assets.
NRG has numerous competitors in all aspects of its business, and
additional competitors may enter the industry. Because many of
the Companys facilities are old, newer plants owned by the
Companys competitors are often more efficient than
NRGs aging plants, which may put some of these plants at a
competitive disadvantage to the extent the Companys
competitors are able to consume the same or less fuel as the
Companys plants consume. Over time, the Companys
plants may be squeezed out of their markets, or may be unable to
compete with these more efficient plants.
In NRGs power marketing and commercial operations, it
competes on the basis of its relative skills, financial position
and access to capital with other providers of electric energy in
the procurement of fuel and transportation services, and the
sale of capacity, energy and related products. In order to
compete successfully, the Company seeks to aggregate fuel
supplies at competitive prices from different sources and
locations and to efficiently utilize transportation services
from third-party pipelines, railways and other fuel transporters
and transmission services from electric utilities.
Other companies with which NRG competes with may have greater
liquidity, greater access to credit and other financial
resources, lower cost structures, more effective risk management
policies and procedures, greater ability to incur losses,
longer-standing relationships with customers, greater potential
for profitability from ancillary services or greater flexibility
in the timing of their sale of generation capacity and ancillary
services than NRG does.
NRGs competitors may be able to respond more quickly to
new laws or regulations or emerging technologies, or to devote
greater resources to the construction, expansion or
refurbishment of their power generation facilities than NRG can.
In addition, current and potential competitors may make
strategic acquisitions or establish cooperative relationships
among themselves or with third parties. Accordingly, it is
possible that new competitors or alliances among current and new
competitors may emerge and rapidly gain significant market
share. There can be no assurance that NRG will be able to
compete successfully against current and future competitors, and
any failure to do so would have a material adverse effect on the
Companys business, financial condition, results of
operations and cash flow.
Operation
of power generation facilities involves significant risks and
hazards customary to the power industry that could have a
material adverse effect on NRGs revenues and results of
operations. NRG may not have adequate insurance to cover these
risks and hazards.
The ongoing operation of NRGs facilities involves risks
that include the breakdown or failure of equipment or processes,
performance below expected levels of output or efficiency and
the inability to transport the Companys product to its
customers in an efficient manner due to a lack of transmission
capacity. Unplanned outages of
48
generating units, including extensions of scheduled outages due
to mechanical failures or other problems occur from time to time
and are an inherent risk of the Companys business.
Unplanned outages typically increase the Companys
operation and maintenance expenses and may reduce the
Companys revenues as a result of selling fewer MWh or
require NRG to incur significant costs as a result of running
one of its higher cost units or obtaining replacement power from
third parties in the open market to satisfy the Companys
forward power sales obligations. NRGs inability to operate
the Companys plants efficiently, manage capital
expenditures and costs, and generate earnings and cash flow from
the Companys asset-based businesses could have a material
adverse effect on the Companys results of operations,
financial condition or cash flows. While NRG maintains
insurance, obtains warranties from vendors and obligates
contractors to meet certain performance levels, the proceeds of
such insurance, warranties or performance guarantees may not be
adequate to cover the Companys lost revenues, increased
expenses or liquidated damages payments should the Company
experience equipment breakdown or non-performance by contractors
or vendors.
Power generation involves hazardous activities, including
acquiring, transporting and unloading fuel, operating large
pieces of rotating equipment and delivering electricity to
transmission and distribution systems. In addition to natural
risks such as earthquake, flood, lightning, hurricane and wind,
other hazards, such as fire, explosion, structural collapse and
machinery failure are inherent risks in the Companys
operations. These and other hazards can cause significant
personal injury or loss of life, severe damage to and
destruction of property, plant and equipment, contamination of,
or damage to, the environment and suspension of operations. The
occurrence of any one of these events may result in NRG being
named as a defendant in lawsuits asserting claims for
substantial damages, including for environmental cleanup costs,
personal injury and property damage and fines
and/or
penalties. NRG maintains an amount of insurance protection that
it considers adequate, but the Company cannot provide any
assurance that its insurance will be sufficient or effective
under all circumstances and against all hazards or liabilities
to which it may be subject. A successful claim for which the
Company is not fully insured could hurt its financial results
and materially harm NRGs financial condition. Further, due
to rising insurance costs and changes in the insurance markets,
NRG cannot provide any assurance that its insurance coverage
will continue to be available at all or at rates or on terms
similar to those presently available. Any losses not covered by
insurance could have a material adverse effect on the
Companys financial condition, results of operations or
cash flows.
Maintenance,
expansion and refurbishment of power generation facilities
involve significant risks that could result in unplanned power
outages or reduced output and could have a material adverse
effect on NRGs results of operations, cash flow and
financial condition.
Many of NRGs facilities are old and require periodic
upgrading and improvement. Any unexpected failure, including
failure associated with breakdowns, forced outages or any
unanticipated capital expenditures could result in reduced
profitability.
NRG cannot be certain of the level of capital expenditures that
will be required due to changing environmental and safety laws
and regulations (including changes in the interpretation or
enforcement thereof), needed facility repairs and unexpected
events (such as natural disasters or terrorist attacks). The
unexpected requirement of large capital expenditures could have
a material adverse effect on the Companys liquidity and
financial condition.
If NRG makes any major modifications to its power generation
facilities, the Company may be required to install the best
available control technology or to achieve the lowest achievable
emission rates as such terms are defined under the new source
review provisions of the federal Clean Air Act. Any such
modifications would likely result in substantial additional
capital expenditures.
The
Company may incur additional costs or delays in the development,
construction and operation of new plants, improvements to
existing plants, or the implementation of environmental control
equipment at existing plants and may not be able to recover
their investment or complete the project.
The Company is in the process of developing or constructing new
generation facilities, improving its existing facilities and
adding environmental controls to its existing facilities. The
development, construction, expansion, modification and
refurbishment of power generation facilities involve many
additional risks, including:
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delays in obtaining necessary permits and licenses;
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49
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environmental remediation of soil or groundwater at contaminated
sites;
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interruptions to dispatch at the Companys facilities;
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supply interruptions;
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work stoppages;
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labor disputes;
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weather interferences;
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unforeseen engineering, environmental and geological problems;
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unanticipated cost overruns;
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exchange rate risks;
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performance risks; and
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unsuccessful partnering relationships.
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In addition, NINA, the Companys 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 is subject to
these and to additional risks, including delays in receiving or
failure to receive commitments under the DOEs loan
guaranty program and the inability to sell down NINAs
interest in the STP expansion as the project develops.
Any of these risks could cause NRGs financial returns on
new investments to be lower than expected, or could cause the
Company to operate below expected capacity or availability
levels, which could result in lost revenues, increased expenses,
higher maintenance costs and penalties. Insurance is maintained
to protect against these risks, warranties are generally
obtained for limited periods relating to the construction of
each project and its equipment in varying degrees, and
contractors and equipment suppliers are obligated to meet
certain performance levels. The insurance, warranties or
performance guarantees, however, may not be adequate to cover
increased expenses. As a result, a project may cost more than
projected and may be unable to fund principal and interest
payments under its construction financing obligations, if any. A
default under such a financing obligation could result in losing
the Companys interest in a power generation facility.
If the Company is unable to complete the development or
construction of a facility or environmental control, or decides
to delay or cancel such project, it may not be able to recover
its investment in that facility or environmental control. In
addition, the Companys nuclear development initiatives are
an integral part of the Companys overall low or no carbon
growth initiatives and the inability of the Company to maintain
significant involvement in new nuclear development may result in
the Companys inability to successfully implement the
Companys other growth initiatives. Furthermore, if
construction projects are not completed according to
specification, the Company may incur liabilities and suffer
reduced plant efficiency, higher operating costs and reduced net
income.
The
Companys RepoweringNRG program is subject to financing
risks that could adversely impact NRGs financial
performance.
While NRG currently intends to develop and finance the more
capital intensive, solid fuel-fired projects included in the
RepoweringNRG program on a non-recourse or limited
recourse basis through separate project financed entities, and
intends to seek additional investments in most of these projects
from third parties, NRG anticipates that it will need to make
significant equity investments in these projects. NRG may also
decide to develop and finance some of the projects, such as
smaller gas-fired and renewable projects, using corporate
financial resources rather than non-recourse debt, which could
subject NRG to significant capital expenditure requirements and
to risks inherent in the development and construction of new
generation facilities. In addition to providing some or all of
the equity required to develop and build the proposed projects,
NRGs ability to finance these projects on a non-recourse
basis is contingent upon a number of factors, including the
terms of the EPC contracts, construction costs, PPAs and fuel
procurement contracts, capital markets conditions, the
availability of tax credits and other government incentives for
certain new technologies. To the extent NRG is not able to
obtain
50
non-recourse financing for any project or should the credit
rating agencies attribute a material amount of the project
finance debt to NRGs credit, the financing of the
RepoweringNRG projects could have a negative impact on
the credit ratings of NRG.
As part of the RepoweringNRG program, NRG may also choose
to undertake the repowering, refurbishment or upgrade of current
facilities based on the Companys assessment that such
activity will provide adequate financial returns. Such projects
often require several years of development and capital
expenditures before commencement of commercial operations, and
key assumptions underpinning a decision to make such an
investment may prove incorrect, including assumptions regarding
construction costs, timing, available financing and future fuel
and power prices.
Supplier
and/or customer concentration at certain of NRGs
facilities may expose the Company to significant financial
credit or performance risks.
NRG often relies on a single contracted supplier or a small
number of suppliers for the provision of fuel, transportation of
fuel and other services required for the operation of certain of
its facilities. If these suppliers cannot perform, the Company
utilizes the marketplace to provide these services. There can be
no assurance that the marketplace can provide these services as,
when and where required.
At times, NRG relies on a single customer or a few customers to
purchase all or a significant portion of a facilitys
output, in some cases under long-term agreements that account
for a substantial percentage of the anticipated revenue from a
given facility. The Company has also hedged a portion of its
exposure to power price fluctuations through forward fixed price
power sales and natural gas price swap agreements.
Counterparties to these agreements may breach or may be unable
to perform their obligations. NRG may not be able to enter into
replacement agreements on terms as favorable as its existing
agreements, or at all. If the Company was unable to enter into
replacement PPAs, the Company would sell its plants
power at market prices. If the Company is unable to enter into
replacement fuel or fuel transportation purchase agreements, NRG
would seek to purchase the Companys fuel requirements at
market prices, exposing the Company to market price volatility
and the risk that fuel and transportation may not be available
during certain periods at any price.
The failure of any supplier or customer to fulfill its
contractual obligations to NRG could have a material adverse
effect on the Companys financial results. Consequently,
the financial performance of the Companys facilities is
dependent on the credit quality of, and continued performance
by, suppliers and customers.
NRG
relies on power transmission facilities that it does not own or
control and that are subject to transmission constraints within
a number of the Companys core regions. If these facilities
fail to provide NRG with adequate transmission capacity, the
Company may be restricted in its ability to deliver wholesale
electric power to its customers and the Company may either incur
additional costs or forego revenues. Conversely, improvements to
certain transmission systems could also reduce
revenues.
NRG depends on transmission facilities owned and operated by
others to deliver the wholesale power it sells from the
Companys power generation plants to its customers. If
transmission is disrupted, or if the transmission capacity
infrastructure is inadequate, NRGs ability to sell and
deliver wholesale power may be adversely impacted. If a
regions power transmission infrastructure is inadequate,
the Companys recovery of wholesale costs and profits may
be limited. If restrictive transmission price regulation is
imposed, the transmission companies may not have sufficient
incentive to invest in expansion of transmission infrastructure.
The Company cannot also predict whether transmission facilities
will be expanded in specific markets to accommodate competitive
access to those markets.
In addition, in certain of the markets in which NRG operates,
energy transmission congestion may occur and the Company may be
deemed responsible for congestion costs if it schedules delivery
of power between congestion zones during times when congestion
occurs between the zones. If NRG were liable for such congestion
costs, the Companys financial results could be adversely
affected.
The Company has a significant amount of generation located in
load pockets, making that generation valuable, particularly with
respect to maintaining the reliability of the transmission grid.
Expansion of transmission systems
51
to reduce or eliminate these load pockets could negatively
impact the value or profitability of the Companys existing
facilities in these areas.
Because
NRG owns less than a majority of some of its project
investments, the Company cannot exercise complete control over
their operations.
NRG has limited control over the operation of some project
investments and joint ventures because the Companys
investments are in projects where it beneficially owns less than
a majority of the ownership interests. NRG seeks to exert a
degree of influence with respect to the management and operation
of projects in which it owns less than a majority of the
ownership interests by negotiating to obtain positions on
management committees or to receive certain limited governance
rights, such as rights to veto significant actions. However, the
Company may not always succeed in such negotiations. NRG may be
dependent on its co-venturers to operate such projects. The
Companys co-venturers may not have the level of
experience, technical expertise, human resources management and
other attributes necessary to operate these projects optimally.
The approval of co-venturers also may be required for NRG to
receive distributions of funds from projects or to transfer the
Companys interest in projects.
Future
acquisition activities may have adverse effects.
NRG may seek to acquire additional companies or assets in the
Companys industry or which complement the Companys
industry. The acquisition of companies and assets is subject to
substantial risks, including the failure to identify material
problems during due diligence, the risk of over-paying for
assets, the ability to retain customers and the inability to
arrange financing for an acquisition as may be required or
desired. Further, the integration and consolidation of
acquisitions requires substantial human, financial and other
resources and, ultimately, the Companys acquisitions may
not be successfully integrated. There can be no assurances that
any future acquisitions will perform as expected or that the
returns from such acquisitions will support the indebtedness
incurred to acquire them or the capital expenditures needed to
develop them.
NRGs
business is subject to substantial governmental regulation and
may be adversely affected by legislative or regulatory changes,
as well as liability under, or any future inability to comply
with, existing or future regulations or
requirements.
NRGs business is subject to extensive foreign, and
U.S. federal, state and local laws and regulation.
Compliance with the requirements under these various regulatory
regimes may cause the Company to incur significant additional
costs, and failure to comply with such requirements could result
in the shutdown of the non-complying facility, the imposition of
liens, fines,
and/or civil
or criminal liability.
Public utilities under the FPA are required to obtain FERC
acceptance of their rate schedules for wholesale sales of
electricity. All of NRGs non-qualifying facility
generating companies and power marketing affiliates in the
U.S. make sales of electricity in interstate commerce and
are public utilities for purposes of the FPA. The FERC has
granted each of NRGs generating and power marketing
companies the authority to sell electricity at market-based
rates. The FERCs orders that grant NRGs generating
and power marketing companies market-based rate authority
reserve the right to revoke or revise that authority if the FERC
subsequently determines that NRG can exercise market power in
transmission or generation, create barriers to entry, or engage
in abusive affiliate transactions. In addition, NRGs
market-based sales are subject to certain market behavior rules,
and if any of NRGs generating and power marketing
companies were deemed to have violated one of those rules, they
are subject to potential disgorgement of profits associated with
the violation
and/or
suspension or revocation of their market-based rate authority.
If NRGs generating and power marketing companies were to
lose their market-based rate authority, such companies would be
required to obtain the FERCs acceptance of a
cost-of-service
rate schedule and could become subject to the accounting,
record-keeping, and reporting requirements that are imposed on
utilities with cost-based rate schedules. This could have an
adverse effect on the rates NRG charges for power from its
facilities.
NRG is also affected by legislative and regulatory changes, as
well as changes to market design, market rules, tariffs, cost
allocations, and bidding rules that occur in the existing ISOs.
The ISOs that oversee most of the wholesale power markets
impose, and in the future may continue to impose, mitigation,
including price limitations, offer caps, and other mechanisms to
address some of the volatility and the potential exercise of
market power in
52
these markets. These types of price limitations and other
regulatory mechanisms may have an adverse effect on the
profitability of NRGs generation facilities that sell
energy and capacity into the wholesale power markets.
The regulatory environment applicable to the electric power
industry has undergone substantial changes over the past several
years as a result of restructuring initiatives at both the state
and federal levels. These changes are ongoing and the Company
cannot predict the future design of the wholesale power markets
or the ultimate effect that the changing regulatory environment
will have on NRGs business. In addition, in some of these
markets, interested parties have proposed material market design
changes, including the elimination of a single clearing price
mechanism, as well as proposals to re-regulate the markets or
require divestiture by generating companies to reduce their
market share. Other proposals to re-regulate may be made and
legislative or other attention to the electric power market
restructuring process may delay or reverse the deregulation
process. If competitive restructuring of the electric power
markets is reversed, discontinued, or delayed, the
Companys business prospects and financial results could be
negatively impacted.
Furthermore, Congress is currently considering legislative
proposals that would significantly increase the regulation of
over-the-counter
derivatives including those related to energy commodities,
through the amendment of the Commodity Exchange Act. While NRG
cannot predict at this time the outcome of any of the
legislative efforts, many of the proposals generally contemplate
mandatory clearing of such derivatives through clearing
organizations and the increased standardization of contracts,
products, and collateral requirements. Such changes could
negatively impact NRGs ability to hedge its portfolio in
an efficient, cost-effective manner, and, among other things,
may limit NRGs ability to utilize liens as collateral. In
addition, certain proposals seek to limit the proprietary
trading activity of the banking institutions. Such changes may
also result in a decrease in liquidity in the commodity markets.
NRGs
ownership interest in a nuclear power facility subjects the
Company to regulations, costs and liabilities uniquely
associated with these types of facilities.
Under the Atomic Energy Act of 1954, as amended, or AEA,
operation of STP, of which NRG indirectly owns a 44.0% interest,
is subject to regulation by the NRC. Such regulation includes
licensing, inspection, enforcement, testing, evaluation and
modification of all aspects of nuclear reactor power plant
design and operation, environmental and safety performance,
technical and financial qualifications, decommissioning funding
assurance and transfer and foreign ownership restrictions.
NRGs 44% share of the output of STP represents
approximately 1,175 MW of generation capacity.
There are unique risks to owning and operating a nuclear power
facility. These include liabilities related to the handling,
treatment, storage, disposal, transport, release and use of
radioactive materials, particularly with respect to spent
nuclear fuel, and uncertainties regarding the ultimate, and
potential exposure to, technical and financial risks associated
with modifying or decommissioning a nuclear facility. The NRC
could require the shutdown of the plant for safety reasons or
refuse to permit restart of the unit after unplanned or planned
outages. New or amended NRC safety and regulatory requirements
may give rise to additional operation and maintenance costs and
capital expenditures. STP may be obligated to continue storing
spent nuclear fuel if the Department of Energy continues to fail
to meet its contractual obligations to STP made pursuant to the
U.S. Nuclear Waste Policy Act of 1982 to accept and dispose
of STPs spent nuclear fuel. See also
Environmental Matters U.S. Federal
Environmental Initiatives Nuclear Waste in
Item 1 for further discussion. Costs associated with these
risks could be substantial and have a material adverse effect on
NRGs results of operations, financial condition or cash
flow. In addition, to the extent that all or a part of STP is
required by the NRC to permanently or temporarily shut down or
modify its operations, or is otherwise subject to a forced
outage, NRG may incur additional costs to the extent it is
obligated to provide power from more expensive alternative
sources either NRGs own plants, third party
generators or the ERCOT to cover the Companys
then existing forward sale obligations. Such shutdown or
modification could also lead to substantial costs related to the
storage and disposal of radioactive materials and spent nuclear
fuel.
NRG and the other owners of STP maintain nuclear property and
nuclear liability insurance coverage as required by law. The
Price-Anderson Act, as amended by the Energy Policy Act of 2005,
requires owners of nuclear power plants in the U.S. to be
collectively responsible for retrospective secondary insurance
premiums for liability
53
to the public arising from nuclear incidents resulting in claims
in excess of the required primary insurance coverage amount of
$300 million per reactor. The Price-Anderson Act only
covers nuclear liability associated with any accident in the
course of operation of the nuclear reactor, transportation of
nuclear fuel to the reactor site, in the storage of nuclear fuel
and waste at the reactor site and the transportation of the
spent nuclear fuel and nuclear waste from the nuclear reactor.
All other non-nuclear liabilities are not covered. Any
substantial retrospective premiums imposed under the
Price-Anderson Act or losses not covered by insurance could have
a material adverse effect on NRGs financial condition,
results of operations or cash flows.
NRG is
subject to environmental laws and regulations that impose
extensive and increasingly stringent requirements on the
Companys ongoing operations, as well as potentially
substantial liabilities arising out of environmental
contamination. These environmental requirements and liabilities
could adversely impact NRGs results of operations,
financial condition and cash flows.
NRGs business is subject to the environmental laws and
regulations of foreign, federal, state and local authorities.
The Company must comply with numerous environmental laws and
regulations and obtain numerous governmental permits and
approvals to operate the Companys plants. Should NRG fail
to comply with any environmental requirements that apply to its
operations, the Company could be subject to administrative,
civil and/or
criminal liability and fines, and regulatory agencies could take
other actions seeking to curtail the Companys operations.
In addition, when new requirements take effect or when existing
environmental requirements are revised, reinterpreted or subject
to changing enforcement policies, NRGs business, results
of operations, financial condition and cash flows could be
adversely affected.
Environmental laws and regulations have generally become more
stringent over time, and the Company expects this trend to
continue. Regulations currently under revision by U.S. EPA,
including CAIR, MACT standards to control Mercury or acid gases
and the 316 (b) rule to mitigate impact by once-through
cooling, could result in tighter standards or reduced compliance
flexibility. While the NRG fleet employs advanced controls and
utilizes industrys best practices, new regulations to
address tightened National Ambient Air Quality Standards for
Ozone and PM 2.5 or new rules to further restrict ash handling
at coal-fired power plants could also further restrict plant
operations.
Policies
at the national, regional and state levels to regulate GHG
emissions could adversely impact NRGs result of
operations, financial condition and cash flows.
At the national level and at various regional and state levels,
policies are under development to regulate GHG emissions. In
addition, GHG emissions from power plants will be subject to
existing sections of the CAA including PSD/NSR and Title V
permitting, at some point after the Light Duty Vehicle
Greenhouse Gas Emissions Standards take effect. Implementation
practices under the PSD/NSR requirements will determine the
extent to which power plant operations are affected over time In
2009, in the course of producing approximately 71 million
MWh of electricity, NRGs power plants emitted
59 million tonnes of
CO2,
of which 53 million tonnes were emitted in the U.S.,
3 million tonnes in Germany and 3 million tonnes in
Australia.
Further federal, state or regional regulation of GHG emissions
could have a material impact on the Companys financial
performance. The actual impact on the Companys financial
performance will depend on a number of factors, including the
overall level of GHG reductions required under any such
regulations, the extent to which mitigation is required, the
price and availability of offsets, and the extent to which NRG
would be entitled to receive
CO2
emissions allowances without having to purchase them in an
auction or on the open market.
Of the approximately 53 million tonnes of
CO2
emitted by NRG in the U.S. in 2009, approximately
8 million tonnes were emitted from the Companys
generating units in Connecticut, Delaware, Maryland,
Massachusetts, and New York that are subject to RGGI which
started in 2009. While 2009 through 2011
CO2
allowance prices have remained low, the impact of RGGI on future
power prices (and thus on the Companys financial
performance), indirectly through generators seeking to pass
through the cost of their
CO2
emissions, cannot be predicted.
Hazards customary to the power production industry include the
potential for unusual weather conditions, which could affect
fuel pricing and availability, the Companys route to
market or access to customers,
54
i.e. transmission and distribution lines, or critical plant
assets. To the extent that climate change contributes to the
frequency or intensity of weather related events, NRGs
operations and planning process could be impacted.
NRGs
business, financial condition and results of operations could be
adversely impacted by strikes or work stoppages by its unionized
employees or inability to replace employees as they
retire.
As of December 31, 2009, approximately 63% of NRGs
employees at its U.S. generation plants were covered by
collective bargaining agreements. In the event that the
Companys union employees strike, participate in a work
stoppage or slowdown or engage in other forms of labor strife or
disruption, NRG would be responsible for procuring replacement
labor or the Company could experience reduced power generation
or outages. NRGs ability to procure such labor is
uncertain. Strikes, work stoppages or the inability to negotiate
future collective bargaining agreements on favorable terms could
have a material adverse effect on the Companys business,
financial condition, results of operations and cash flow. In
addition, a number of the Companys employees at NRGs
plants are close to retirement. The Companys inability to
replace those workers could create potential knowledge and
expertise gaps as those workers retire.
Changes
in technology may impair the value of NRGs power
plants.
Research and development activities are ongoing to provide
alternative and more efficient technologies to produce power,
including fuel cells, clean coal and coal
gasification, micro-turbines, photovoltaic (solar) cells and
improvements in traditional technologies and equipment, such as
more efficient gas turbines. Advances in these or other
technologies could reduce the costs of power production to a
level below what the Company has currently forecasted, which
could adversely affect its cash flow, results of operations or
competitive position.
Acts
of terrorism could have a material adverse effect on NRGs
financial condition, results of operations and cash
flows.
NRGs generation facilities and the facilities of third
parties on which they rely may be targets of terrorist
activities, as well as events occurring in response to or in
connection with them, that could cause environmental
repercussions
and/or
result in full or partial disruption of the facilities ability
to generate, transmit, transport or distribute electricity or
natural gas. Strategic targets, such as energy-related
facilities, may be at greater risk of future terrorist
activities than other domestic targets. Any such environmental
repercussions or disruption could result in a significant
decrease in revenues or significant reconstruction or
remediation costs, which could have a material adverse effect on
the Companys financial condition, results of operations
and cash flow.
NRGs
level of indebtedness could adversely affect its ability to
raise additional capital to fund its operations, or return
capital to stockholders. It could also expose it to the risk of
increased interest rates and limit its ability to react to
changes in the economy or its industry.
NRGs substantial debt could have important consequences,
including:
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increasing NRGs vulnerability to general economic and
industry conditions;
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requiring a substantial portion of NRGs cash flow from
operations to be dedicated to the payment of principal and
interest on its indebtedness, therefore reducing NRGs
ability to pay dividends to holders of its preferred or common
stock or to use its cash flow to fund its operations, capital
expenditures and future business opportunities;
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limiting NRGs ability to enter into long-term power sales
or fuel purchases which require credit support;
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exposing NRG to the risk of increased interest rates because
certain of its borrowings, including borrowings under its new
senior secured credit facility are at variable rates of interest;
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limiting NRGs ability to obtain additional financing for
working capital including collateral postings, capital
expenditures, debt service requirements, acquisitions and
general corporate or other purposes; and
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limiting NRGs ability to adjust to changing market
conditions and placing it at a competitive disadvantage compared
to its competitors who have less debt.
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The indentures for NRGs notes and senior secured credit
facility contain financial and other restrictive covenants that
may limit the Companys ability to return capital to
stockholders or otherwise engage in activities that may be in
its long-term best interests. NRGs failure to comply with
those covenants could result in an event of default which, if
not cured or waived, could result in the acceleration of all of
the Companys indebtedness.
In addition, NRGs ability to arrange financing, either at
the corporate level or at a non-recourse project-level
subsidiary, and the costs of such capital, are dependent on
numerous factors, including:
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general economic and capital market conditions;
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credit availability from banks and other financial institutions;
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investor confidence in NRG, its partners and the regional
wholesale power markets;
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NRGs financial performance and the financial performance
of its subsidiaries;
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NRGs level of indebtedness and compliance with covenants
in debt agreements;
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maintenance of acceptable credit ratings;
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cash flow; and
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provisions of tax and securities laws that may impact raising
capital.
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NRG may not be successful in obtaining additional capital for
these or other reasons. The failure to obtain additional capital
from time to time may have a material adverse effect on its
business and operations.
Goodwill
and/or other intangible assets not subject to amortization that
NRG has recorded in connection with its acquisitions are subject
to mandatory annual impairment evaluations and as a result, the
Company could be required to write off some or all of this
goodwill and other intangible assets, which may adversely affect
the Companys financial condition and results of
operations.
In accordance with ASC-350, Intangibles-Goodwill and
Others; or ASC 305, goodwill is not amortized but is
reviewed annually or more frequently for impairment and other
intangibles are also reviewed at least annually or more
frequently, if certain conditions exist, and may be amortized.
Any reduction in or impairment of the value of goodwill or other
intangible assets will result in a charge against earnings which
could materially adversely affect NRGs reported results of
operations and financial position in future periods.
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 significant 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).
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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.
56
NRGs
Texas retail business 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.
NRGs
Texas retail business 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 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 Texas retail
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.
Cautionary
Statement Regarding Forward Looking Information
This Annual Report on
Form 10-K
includes forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933, as amended, or
Securities Act, and Section 21E of the Exchange Act. The
words believes, projects,
anticipates, plans, expects,
intends, estimates and similar
expressions are intended to identify forward-looking statements.
These forward-looking statements involve known and unknown
risks, uncertainties and other factors that may cause NRG
Energy, Inc.s actual results, performance and
achievements, or industry results, to be materially different
from any future results, performance or achievements expressed
or implied by such forward-looking statements. These factors,
risks and uncertainties include the factors described under
Risks Related to NRG in Item 1A of this report and the
following:
|
|
|
|
|
General economic conditions, changes in the wholesale power
markets and fluctuations in the cost of fuel;
|
|
|
Volatile power supply costs and demand for power;
|
|
|
Hazards customary to the power production industry and power
generation operations such as fuel and electricity price
volatility, unusual weather conditions, catastrophic
weather-related or other damage to facilities, unscheduled
generation outages, maintenance or repairs, unanticipated
changes to fuel supply costs or availability due to higher
demand, shortages, transportation problems or other
developments, environmental incidents, or electric transmission
or gas pipeline system constraints and the possibility that NRG
may not have adequate insurance to cover losses as a result of
such hazards;
|
|
|
The effectiveness of NRGs risk management policies and
procedures, and the ability of NRGs counterparties to
satisfy their financial commitments;
|
|
|
Counterparties collateral demands and other factors
affecting NRGs liquidity position and financial condition;
|
|
|
NRGs ability to operate its businesses efficiently, manage
capital expenditures and costs tightly, and generate earnings
and cash flows from its asset-based businesses in relation to
its debt and other obligations;
|
|
|
NRGs ability to enter into contracts to sell power and
procure fuel on acceptable terms and prices;
|
|
|
The liquidity and competitiveness of wholesale markets for
energy commodities;
|
|
|
Government regulation, including compliance with regulatory
requirements and changes in market rules, rates, tariffs and
environmental laws and increased regulation of carbon dioxide
and other greenhouse gas emissions;
|
57
|
|
|
|
|
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;
|
|
|
NRGs ability to borrow additional funds and access capital
markets, as well as NRGs substantial indebtedness and the
possibility that NRG may incur additional indebtedness going
forward;
|
|
|
Operating and financial restrictions placed on NRG 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;
|
|
|
NRGs ability to implement its RepoweringNRG
strategy of developing and building new power generation
facilities, including new nuclear, wind and solar projects;
|
|
|
NRGs ability to implement its econrg strategy of finding
ways to meet the challenges of climate change, clean air and
protecting our natural resources while taking advantage of
business opportunities;
|
|
|
NRGs ability to implement its FORNRG strategy of
increasing the return on invested capital through operational
performance improvements and a range of initiatives at plants
and corporate offices to reduce costs or generate revenues;
|
|
|
NRGs ability to achieve its strategy of regularly
returning capital to shareholders;
|
|
|
Reliant Energys ability to maintain market share;
|
|
|
NRGs ability to successfully evaluate investments in new
business and growth initiatives; and
|
|
|
NRGs ability to successfully integrate and manage any
acquired businesses.
|
Forward-looking statements speak only as of the date they were
made, and NRG Energy, Inc. undertakes no obligation to publicly
update or revise any forward-looking statements, whether as a
result of new information, future events or otherwise. The
foregoing review of factors that could cause NRGs actual
results to differ materially from those contemplated in any
forward-looking statements included in this Annual Report on
Form 10-K
should not be construed as exhaustive.
|
|
Item 1B
|
Unresolved
Staff Comments
|
None.
58
Listed below are descriptions of NRGs interests in
facilities, operations
and/or
projects owned as of December 31, 2009. The MW figures
provided represent nominal summer net megawatt capacity of power
generated as adjusted for the Companys ownership position
excluding capacity from inactive/mothballed units as of
December 31, 2009. The following table summarizes
NRGs power production and cogeneration facilities by
region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
|
|
|
|
|
|
Power
|
|
|
|
|
Generation
|
|
|
Primary
|
Name and Location of Facility
|
|
Market
|
|
% Owned
|
|
|
Capacity (MW)
|
|
|
Fuel-type
|
Texas Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
W. A. Parish, Thompsons, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
2,490
|
|
|
Coal
|
Limestone, Jewett, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,690
|
|
|
Lignite/Coal
|
South Texas Project, Bay City,
Texas(a)
|
|
ERCOT
|
|
|
44.0
|
|
|
|
1,175
|
|
|
Nuclear
|
Cedar Bayou, Baytown, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,495
|
|
|
Natural Gas
|
Cedar Bayou 4, Baytown, Texas
|
|
ERCOT
|
|
|
50.0
|
|
|
|
260
|
|
|
Natural Gas
|
T. H. Wharton, Houston, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,025
|
|
|
Natural Gas
|
W. A. Parish, Thompsons, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
1,175
|
|
|
Natural Gas
|
S. R. Bertron, Deer Park, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
765
|
|
|
Natural Gas
|
Greens Bayou, Houston, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
760
|
|
|
Natural Gas
|
San Jacinto, LaPorte, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
160
|
|
|
Natural Gas
|
Elbow Creek Wind Farm, Howard County, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
120
|
|
|
Wind
|
Langford Wind Farm, Christoval, Texas
|
|
ERCOT
|
|
|
100.0
|
|
|
|
150
|
|
|
Wind
|
Sherbino Wind Farm, Pecos County, Texas
|
|
ERCOT
|
|
|
50.0
|
|
|
|
75
|
|
|
Wind
|
Northeast Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oswego, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
1,635
|
|
|
Oil
|
Arthur Kill, Staten Island, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
865
|
|
|
Natural Gas
|
Middletown, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
770
|
|
|
Oil
|
Indian River, Millsboro, Delaware
|
|
PJM
|
|
|
100.0
|
|
|
|
740
|
|
|
Coal
|
Astoria Gas Turbines, Queens, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
550
|
|
|
Natural Gas
|
Dunkirk, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
530
|
|
|
Coal
|
Huntley, Tonawanda, New York
|
|
NYISO
|
|
|
100.0
|
|
|
|
380
|
|
|
Coal
|
Montville, Uncasville, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
500
|
|
|
Oil
|
Norwalk Harbor, So. Norwalk, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
340
|
|
|
Oil
|
Devon, Milford, Connecticut
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
135
|
|
|
Natural Gas
|
Vienna, Maryland
|
|
PJM
|
|
|
100.0
|
|
|
|
170
|
|
|
Oil
|
Somerset, Massachusetts
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
125
|
|
|
Coal
|
Connecticut Jet Power, Connecticut (four sites)
|
|
ISO-NE
|
|
|
100.0
|
|
|
|
145
|
|
|
Oil/Natural Gas
|
Conemaugh, New Florence, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
Keystone, Shelocta, Pennsylvania
|
|
PJM
|
|
|
3.7
|
|
|
|
65
|
|
|
Coal
|
South Central Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Cajun II, New Roads,
Louisiana(b)
|
|
SERC-Entergy
|
|
|
86.0
|
|
|
|
1,495
|
|
|
Coal
|
Bayou Cove, Jennings, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Big Cajun I, Jarreau, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
430
|
|
|
Natural Gas/Oil
|
Rockford I, Illinois
|
|
PJM
|
|
|
100.0
|
|
|
|
300
|
|
|
Natural Gas
|
Rockford II, Illinois
|
|
PJM
|
|
|
100.0
|
|
|
|
155
|
|
|
Natural Gas
|
Sterlington, Louisiana
|
|
SERC-Entergy
|
|
|
100.0
|
|
|
|
175
|
|
|
Natural Gas
|
West Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Blythe, Blythe, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
20
|
|
|
Solar
|
Encina, Carlsbad, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
965
|
|
|
Natural Gas
|
El Segundo Power, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
670
|
|
|
Natural Gas
|
Long Beach, California
|
|
CAISO
|
|
|
100.0
|
|
|
|
260
|
|
|
Natural Gas
|
San Diego Combustion Turbines, California (three sites)
|
|
CAISO
|
|
|
100.0
|
|
|
|
190
|
|
|
Natural Gas
|
Saguaro Power Co., Henderson, Nevada
|
|
WECC
|
|
|
50.0
|
|
|
|
45
|
|
|
Natural Gas
|
International Region:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gladstone Power Station, Queensland, Australia
|
|
Enertrade/Boyne Smelter
|
|
|
37.5
|
|
|
|
605
|
|
|
Coal
|
Schkopau Power Station, Germany
|
|
Vattenfall Europe
|
|
|
41.9
|
|
|
|
400
|
|
|
Lignite
|
|
|
|
|
(a)
|
For the nature of NRGs interest and various limitations on
the Companys interest, please read Item 1
Business Texas Generation Facilities
section
|
|
(b)
|
Units 1 and 2 owned 100.0%, Unit 3 owned 58.0%
|
59
The following table summarizes NRGs thermal facilities as
of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
Ownership
|
|
|
|
Name and Location of Facility
|
|
Thermal Energy Purchaser
|
|
Interest
|
|
|
Generating Capacity
|
|
NRG Energy Center Minneapolis, Minnesota
|
|
Approx. 100 steam customers and 50 chilled water customers
|
|
|
100.0
|
|
|
Steam: 1,143 MMBtu/hr. (335 MWt) Chilled Water: 40,630
tons (143 MWt)
|
NRG Energy Center San Francisco, California
|
|
Approx. 170 steam customers
|
|
|
100.0
|
|
|
Steam: 454 MMBtu/Hr. (133 MWt)
|
NRG Energy Center Harrisburg, Pennsylvania
|
|
Approx. 210 steam customers and 3 chilled water customers
|
|
|
100.0
|
|
|
Steam: 440 MMBtu/hr. (129 MWt) Chilled water: 2,400
tons (8 MWt)
|
NRG Energy Center Pittsburgh, Pennsylvania
|
|
Approx. 25 steam and 25 chilled
water customers
|
|
|
100.0
|
|
|
Steam: 296 MMBtu/hr. (87 MWt) Chilled water: 12,920
tons (45 MWt)
|
NRG Energy Center San Diego, California
|
|
Approx. 20 chilled water customers
|
|
|
100.0
|
|
|
Chilled water: 7,425 tons (26 MWt)
|
Camas Power Boiler Camas, Washington
|
|
Georgia-Pacific Corp.
|
|
|
100.0
|
|
|
Steam: 200 MMBtu/hr. (59 MWt)
|
NRG Energy Center Dover, Delaware
|
|
Kraft Foods Inc. and Procter & Gamble Company
|
|
|
100.0
|
|
|
Steam: 190 MMBtu/hr. (56 MWt)
|
Paxton Creek Cogeneration, Harrisburg, Pennsylvania
|
|
PJM
|
|
|
100.0
|
|
|
12 MW -- Natural Gas
|
Dover Cogeneration, Delaware
|
|
PJM
|
|
|
100.0
|
|
|
103 MW -- Natural Gas/Coal
|
Other
Properties
In addition, NRG owns several real property and facilities
relating to its generation assets, other vacant real property
unrelated to the Companys generation assets, interest in a
construction project, and properties not used for operational
purposes. NRG believes it has satisfactory title to its plants
and facilities in accordance with standards generally accepted
in the electric power industry, subject to exceptions that, in
the Companys opinion, would not have a material adverse
effect on the use or value of its portfolio.
NRG leases its corporate offices at 211 Carnegie Center,
Princeton, New Jersey, its Reliant Energy offices and call
centers, and various other office space. In addition, NRG is
constructing office space under a newly signed lease, to combine
the Companys Texas region administration offices and
Reliant Energys offices.
|
|
Item 3
|
Legal
Proceedings
|
City of San Antonio, Texas, acting by and through the
City Public Service Board of San Antonio, a Texas municipal
utility v. Toshiba Corporation; NRG Energy, Inc.; Nuclear
Innovation North America, LLC; NINA Texas 3 LLC; and NINA Texas
4 LLC (as amended), 37th Judicial District Court, Bexar
County, TX, Case #2009CL19492 (filed December 6,
2009) The original December 6, 2009,
complaint against two Nuclear Innovation North America, or NINA,
entities asked the court to declare the rights, obligations, and
remedies of the parties pursuant to the 1997 and 2007 agreements
between the parties should CPS unilaterally withdraw from the
proposed South Texas Project Units 3 and 4, or the STP Units 3
and 4 Project. On December 23, 2009, CPS amended its
original December 6 complaint adding NRG, Toshiba Corporation,
and NINA LLC as defendants and not only continued to request
that the Court declare the rights, obligations, and remedies of
the parties under the two operative governing agreements, but
also sought $32 billion in damages. CPS amended its
complaint again on December 28, 2009.
On January 6, 2010, CPS amended its complaint for the third
time. In addition to requesting immediate injunctive relief, the
amended complaint alleges that NRG, Toshiba, and NINA have been
involved in a conspiracy to defraud CPS, that they purposefully
misled CPS in inducing it to be a partner in the STP Units 3 and
4 Project, that they maliciously interfered with CPS contracts
and business relationships, and that they willfully disparaged
CPS. It sought declarations that: (i) owner consensus is
required for all development decisions; (ii) there is a
right to voluntary withdrawal, after which no further
obligations accrue but undiluted ownership continues;
(iii) both the partition waiver and forfeiture provisions
are unenforceable against CPS under Texas law if they did apply;
and (iv) CPS is not currently in breach. In addition, CPS
sought relief among the following alternatives: partition by
sale; an order forcing NRG and NINA to buy CPS undiluted share
at an independent valuation; an order requiring NRG to
compensate CPS $350 million investment and fair value for
the site; an order granting CPS twelve months
60
following withdrawal to sell its stake in the project; or an
order that no further development take place without consensus
of all project owners. The case was removed and remanded to and
from federal court on three separate occasions. On
January 19, 2010, CPS dismissed Toshiba from the lawsuit.
The parties agreed to a January 25, 2010, phased trial
wherein all other claims would be reserved for an undetermined
future phase II date and a trial would go forward in phase
I only on CPS request for declaratory relief to determine
the respective rights, obligations, and remedies of the parties
under the two operative governing agreements should CPS withdraw
from the STP Units 3 and 4 Project. On January 25,2010, the
parties argued the NINA entities and NRGs Motion for
Summary Judgment which was denied on January 26, 2010.
After a
two-day
trial, the court issued its ruling on January 29, 2010,
making a number of findings. It ruled that as of
January 29, CPS and NINA were each 50% equity owners as
tenants in common under Texas law in the STP Units 3 and 4
Project. The court found that while a withdrawing party does not
forfeit its 50% interest upon a withdrawal, the governing
agreements are silent as to whether that withdrawing party can
recoup its sunk costs upon withdrawal. Finally, the court noted
that for CPS to remain a 50% equity owner, it must pay all
appropriate costs. Failure to do so, the court determined, would
result in a complete loss of CPS equity share.
On February 17, 2010, an agreement in principle was reached
with CPS for NINA to acquire a controlling interest in the STP
Units 3 and 4 Project through a settlement of all pending
litigation between the parties. As part of that agreement, all
litigation would be dismissed with prejudice, including all
Phase II claims, thereby ending this matter. For further
discussion, see Item 1, Nuclear Development. The
parties continue to negotiate terms regarding final
documentation of the agreement in principle.
Public Utilities Commission of the State of
California v. Long-Term Sellers of Long-Term Contracts to
the California Department of Water Resources, FERC
Docket
No. EL02-60
et al. This matter concerns, among other
contracts and other defendants, the California Department of
Water Resources, or CDWR, and its wholesale power contract with
subsidiaries of WCP (Generation) Holdings, Inc., or WCP. The
case originated with a February 2002 complaint filed by the
State of California alleging that many parties, including WCP
subsidiaries, overcharged the State of California. For WCP, the
alleged overcharges totaled approximately $940 million for
2001 and 2002. The complaint demanded that the FERC abrogate the
CDWR contract and sought refunds associated with revenues
collected under the contract. In 2003, the FERC rejected this
complaint, denied rehearing, and the case was appealed to the
U.S. Court of Appeals for the Ninth Circuit where oral
argument was held on December 8, 2004. On December 19,
2006, the Ninth Circuit decided that in the FERCs review
of the contracts at issue, the FERC could not rely on the
Mobile-Sierra standard presumption of just and reasonable
rates, where such contracts were not reviewed by the FERC with
full knowledge of the then existing market conditions. WCP and
others sought review by the U.S. Supreme Court. WCPs
appeal was not selected, but instead held by the Supreme Court.
In the appeal that was selected by the Supreme Court, on
June 26, 2008 the Supreme Court ruled: (i) that the
Mobile-Sierra public interest standard of review applied
to contracts made under a sellers market-based rate
authority; (ii) that the public interest bar
required to set aside a contract remains a very high one to
overcome; and (iii) that the Mobile-Sierra
presumption of contract reasonableness applies when a
contract is formed during a period of market dysfunction unless
(a) such market conditions were caused by the illegal
actions of one of the parties or (b) the contract
negotiations were tainted by fraud or duress. In this related
case, the U.S. Supreme Court affirmed the Ninth
Circuits decision agreeing that the case should be
remanded to the FERC to clarify the FERCs 2003 reasoning
regarding its rejection of the original complaint relating to
the financial burdens under the contracts at issue and to
alleged market manipulation at the time these contracts were
formed. As a result, the U.S. Supreme Court then reversed
and remanded the WCP CDWR case to the Ninth Circuit for
treatment consistent with its June 26, 2008 decision in the
related case. On October 20, 2008, the Ninth Circuit asked
the parties in the remanded CDWR case, including WCP and the
FERC, whether that Court should answer a question the
U.S. Supreme Court did not address in its June 26,
2008, decision; whether the Mobile-Sierra doctrine
applies to a third-party that was not a signatory to any of the
wholesale power contracts, including the CDWR contract, at issue
in that case. Without answering that reserved question, on
December 4, 2008, the Ninth Circuit vacated its prior
opinion and remanded the WCP CDWR case back to the FERC for
proceedings consistent with the U.S. Supreme Courts
June 26, 2008 decision. On December 15, 2008, WCP and
the other seller-defendants filed with the FERC a Motion for
Order Governing Proceedings on Remand. On January 14, 2009,
the Public Utilities Commission of the State of California filed
an Answer and Cross Motion for an Order Governing Procedures on
Remand, and on January 28, 2009, WCP and the other
seller-defendants filed their reply.
61
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.
On January 14, 2010, the U.S. Supreme Court issued its
decision in an unrelated proceeding involving the
Mobile-Sierra doctrine that will affect the standard of
review applied to the CDWR contract on remand before the FERC.
In NRG Power Marketing v. Maine Public Utilities
Commission, the Supreme Court held by an 8 to 1 margin that
the Mobile-Sierra presumption regarding the
reasonableness of contract rates does not depend on the identity
of the complainant who seeks a FERC investigation/refund. The
Supreme Court proceeding arose following an appeal by the
Attorneys General of the State of Connecticut and of the
Commonwealth of Massachusetts regarding the settlement
establishing the New England Forward Capacity Market. The
settlement, filed with the FERC on March 7, 2006, provides
for interim capacity transition payments for all generators in
New England for the period from December 1, 2006, through
May 31, 2010, and for the Forward Capacity Market auction
rates thereafter. The Court of Appeals for the DC Circuit, or DC
Circuit, had rejected all substantive challenges to the
settlement, but had sustained one procedural argument relating
to the applicability of the Mobile-Sierra doctrine to
third parties. The Supreme Court reversed the DC Circuit on this
point, and remanded the case for further consideration of
whether the transition payments and auction rates qualify as
contract rates.
United States of America v. Louisiana Generating,
LLC., U.S.D.C Middle District of Louisiana, Civil
Action
No. 09-100-RET-CN
(filed 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.
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 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. It filed an objection in the Cajun Electric Cooperative
Power, Inc.s bankruptcy proceeding in the
U.S. Bankruptcy Court for the Middle District of Louisiana
to seek to prevent the bankruptcy from closing. It also filed a
complaint in the same bankruptcy proceeding in the same court
seeking a judgment that: (i) it did not assume liability
from Cajun Electric for any claims or other liabilities under
environmental laws with respect to Big Cajun II that arose,
or are based on activities that were undertaken, prior to the
closing date of the acquisition; (ii) it is not otherwise
the successor to Cajun Electric; and (iii) Cajun Electric
and/or the
Bankruptcy Trustee are exclusively liable for the violations
alleged in the February 11, 2009 lawsuit to the extent that
such claims are determined to have merit. On 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. On August 24,
2009, Louisiana Generating, LLC filed a motion to dismiss this
lawsuit, and on September 25, 2009, the
62
Department of Justice filed its opposition to the motion to
dismiss. A new federal bankruptcy judge was appointed on
October 9, 2009.
On February 18, 2010, the Louisiana Department of Environmental
Quality, or LDEQ, filed a motion to intervene in the above
lawsuit and a complaint against Louisiana Generating LLC for
alleged violations of Louisianas PSD regulations and
Louisianas Title V operating permit program. LDEQ seeks
similar relief to that requested by the Department of Justice.
Specifically, LDEQ seeks injunctive relief 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 pursuant to the requirements
of PSD and the Louisiana Title V operating permits program; (iv)
conduct audits to determine if any additional modifications have
occurred which would require it to meet the requirements of PSD
and report the Results of the audit to the LDEQ and EPA; (v)
order the surrender of emission allowances or credits; (vi) take
other appropriate actions to remedy, mitigate and offset the
harm to public health and the environment caused by violations
of the CAA; (vii) assess civil penalties; and (viii) award to
the LDEQ its costs in prosecuting the litigation. On
February 19, 2010, the district court granted LDEQs
motion to intervene.
Hohl Industrial Services, Inc, v. Dunkirk Power LLC,
et al; New York State Supreme Court, County of Chautauqua; Index
No, Kl-2009-1510 (original complaint filed August 28,
2009, cross claims filed by CBEEC on February 17,
2010) In 2005, NRG entered into a Consent Decree
with the New York State Department of Environmental Conservation
whereby it agreed to reduce certain emissions generated by its
Huntley and Dunkirk power plants. Pursuant to the Consent
Decree, on November 21, 2007, Clyde Bergemann EEC, or
CBEEC, and NRG entered into a firm fixed price contract for the
supply of equipment, material and services for six fabric
filters for NRGs Dunkirk Electric Power Generating
Station. Subsequent to contracting with NRG, CBEEC subcontracted
with Hohl Industrial Services, Inc., or Hohl, to perform steel
erection and equipment installation at Dunkirk.
On August 28, 2009, Hohl filed its original complaint
against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power,
and CBEEC among others for claims of breach of contract, quantum
meruit, unjust enrichment and foreclosure of mechanics
liens. As part of CBEECs contractual obligation to NRG,
CBEEC agreed to defend, under a reservation of rights,
NRGs interest in this lawsuit. CBEEC filed an answer to
the above complaint on behalf of itself, NRG and Dunkirk Power
on October 5, 2009. On December 16, 2009, CBEEC filed
a Motion for Summary Judgment on behalf of itself, NRG, and
Dunkirk Power, which has yet to be decided.
On February 1, 2010, NRG and Dunkirk Power filed a Motion
for Leave to file an Amended Answer with Cross-Claims against
CBEEC. NRG asserted breach of contract claims seeking liquidated
damages for the delays caused by CBEEC. NRG also retained its
own counsel to represent its interest in the cross-claims and
reserved its rights to seek reimbursement from CBEEC. On
February 17, 2010, CBEEC filed an Amended Answer with
Affirmative Defenses, Counterclaims and Cross-Claims against
NRG. CBEEC is seeking approximately $30 million alleging
breach of contract, quantum meruit, unjust enrichment, and
foreclosure of two mechanics liens, as a result of alleged
delays caused by NRG and Dunkirk Power. A court ordered hearing
and settlement conference is scheduled for February 23,
2010.
Excess Mitigation Credits From January
2002 to April 2005, CenterPoint Energy applied excess mitigation
credits, or EMCs, to its monthly charges to retail electric
providers as ordered by the PUCT. The PUCT imposed these credits
to facilitate the transition to competition in Texas, which had
the effect of lowering the retail electric providers
monthly charges payable to CenterPoint Energy. As indicated in
its Petition for Review filed with the Supreme Court of Texas on
June 2, 2008, CenterPoint Energy has claimed that the
portion of those EMCs credited to Reliant Energy Retail
Services, LLC, or RERS, a retail electric provider and NRG
subsidiary acquired from RRI Energy Inc., or 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
63
the first such appeal filed on the same date as the state
district court judgment and the last such appeal filed on
October 10, 2005. On April 17, 2008, the Court of
Appeals for the Third District reversed the lower courts
decision ruling that CenterPoint Energys stranded cost
recovery should exclude only EMCs credited to RERS for its
Price to Beat customers. On June 2, 2008,
CenterPoint Energy filed a Petition for Review with the Supreme
Court of Texas and on June 19, 2009, the Court agreed to
consider the CenterPoint Energy appeal as well as two related
petitions for review filed by other entities. Oral argument
occurred on October 6, 2009.
In November 2008, CenterPoint Energy and 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.
Additional Litigation In addition to
the foregoing, NRG is party to other litigation or legal
proceedings. The Company believes that it has valid defenses to
the legal proceedings and investigations described above and
intends to defend them vigorously. However, litigation is
inherently subject to many uncertainties. There can be no
assurance that additional litigation will not be filed against
the Company or its subsidiaries in the future asserting similar
or different legal theories and seeking similar or different
types of damages and relief. Unless specified above, the Company
is unable to predict the outcome these legal proceedings and
investigations may have or reasonably estimate the scope or
amount of any associated costs and potential liabilities. An
unfavorable outcome in one or more of these proceedings could
have a material impact on the Companys consolidated
financial position, results of operations or cash flows. The
Company also has indemnity rights for some of these proceedings
to reimburse the Company for certain legal expenses and to
offset certain amounts deemed to be owed in the event of an
unfavorable litigation outcome.
PART II
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Item 4
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Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
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Market
Information and Holders
NRGs authorized capital stock consists of
500,000,000 shares of NRG common stock and
10,000,000 shares of preferred stock. A total of
16,000,000 shares of the Companys common stock are
available for issuance under NRGs Long-Term Incentive
Plan. NRG has also filed with the Secretary of State of Delaware
a Certificate of Designation for the 3.625% Convertible
Perpetual Preferred Stock.
NRGs common stock is listed on the New York Stock Exchange
and has been assigned the symbol: NRG. The high and low sales
prices, as well as the closing price for the Companys
common stock on a per share basis for 2009 and 2008 are set
forth below:
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Fourth
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Third
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Second
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First
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Fourth
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Third
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Second
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First
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Common Stock
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Quarter
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Quarter
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Quarter
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Quarter
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Quarter
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Quarter
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Quarter
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Quarter
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Price
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2009
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2009
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2009
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2009
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2008
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2008
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2008
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2008
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High
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$
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29.18
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$
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29.26
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$
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25.96
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$
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25.38
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$
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25.40
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$
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43.95
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$
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45.78
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$
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43.96
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Low
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22.82
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21.94
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16.50
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15.19
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14.39
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22.20
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38.36
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34.56
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Closing
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$
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23.61
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$
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28.19
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$
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25.96
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$
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17.60
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$
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23.33
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$
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24.75
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$
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42.90
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$
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38.99
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NRG had 253,995,308 shares outstanding as of
December 31, 2009, and as of February 17, 2010, there
were 261,898,178 shares outstanding. As of
February 17, 2010, there were 70,000 common stockholders of
record.
Dividends
NRG has not declared or paid dividends on its common stock. To
the extent NRG declares such a dividend, the amount available
for dividends is currently limited by the Companys senior
secured credit agreements and high yield note indentures.
64
Repurchase
of equity securities
NRGs repurchases of equity securities for the year ended
December 31, 2009, were as follows:
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Total Number
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of Shares
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Dollar Value of
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Purchased as
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Shares that may be
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Part of Publicly
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Purchased Under the
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Total Number of
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Average Price
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Announced Plans
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2009 Capital
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For the Year Ended December 31, 2009
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Shares Purchased
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Paid per Share
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or Programs
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Allocation Plan
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First quarter
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$
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$
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330,000,000
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Second quarter
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330,000,000
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Third quarter
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8,919,100
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28.01
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8,919,100
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250,002,565
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Fourth quarter
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10,386,400
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24.05
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10,386,400
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Total for 2009
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19,305,500
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$
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25.88
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19,305,500
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$
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The Companys Capital Allocation Plan included 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. In
July 2009, as part of the Companys 2009 Capital Allocation
Program, NRGs Board of Directors approved an increase to
the Companys previously authorized common share
repurchases under its capital allocation plan from the existing
$330 million to $500 million. The Companys
repurchases during the quarters ended September 30, 2009,
and December 31, 2009, were $250 million and
$250 million, respectively. The Companys share
repurchases are subject to market prices, financial restrictions
under the Companys debt facilities, and as permitted by
securities laws.
Securities
Authorized for Issuance under Equity Compensation
Plans
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(c)
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Number of Securities
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(a)
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Remaining Available
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Number of Securities
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(b)
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for Future Issuance
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to be Issued Upon
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Weighted-Average Exercise
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Under Equity Compensation
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Exercise of
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Price of Outstanding
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Plans (Excluding
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Outstanding Options,
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Options, Warrants and
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Securities Reflected
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Plan Category
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Warrants and Rights
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Rights
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in Column
(a))
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Equity compensation plans approved by security holders
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7,947,003
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$
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25.07
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5,129,593
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Equity compensation plans not approved by security holders
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N/A
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Total
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7,947,003
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$
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25.07
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5,129,593
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(a)
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Consists of NRG Energy, Inc.s
Long-Term Incentive Plan, or the LTIP, and NRG Energy,
Inc.s Employee Stock Purchase Plan, or the ESPP. The LTIP
became effective upon the Companys emergence from
bankruptcy. The LTIP was subsequently approved by the
Companys stockholders on August 4, 2004 and was
amended on April 28, 2006 to increase the number of shares
available for issuance to 16,000,000, on a post-split basis, and
again on December 8, 2006 to make technical and
administrative changes. The LTIP provides for grants of stock
options, stock appreciation rights, restricted stock,
performance units, deferred stock units and dividend equivalent
rights. NRGs directors, officers and employees, as well as
other individuals performing services for, or to whom an offer
of employment has been extended by the Company, are eligible to
receive grants under the LTIP. The purpose of the LTIP is to
promote the Companys long-term growth and profitability by
providing these individuals with incentives to maximize
stockholder value and otherwise contribute to the Companys
success and to enable the Company to attract, retain and reward
the best available persons for positions of responsibility. The
Compensation Committee of the Board of Directors administers the
LTIP. There were 5,129,593 and 6,798,074 shares of common
stock remaining available for grants of awards under NRGs
LTIP as of December 31, 2009 and 2008, respectively. The
ESPP was approved by the Companys stockholders on
May 14, 2008. There were 500,000 shares reserved from
the Companys treasury shares for the ESPP. As of
December 31, 2009, there were 418,468 shares of
treasury stock reserved for issuance under the ESPP. In January
2010, 54,845 shares were issued to employees accounts from
the treasury stock reserve for the ESPP.
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65
Stock
Performance Graph
The performance graph below compares NRGs cumulative total
shareholder return on the Companys common stock for the
period December 31, 2004, through December 31, 2009,
with the cumulative total return of the Standard &
Poors 500 Composite Stock Price Index, or S&P 500,
and the Philadelphia Utility Sector Index, or UTY. NRGs
common stock trades on the New York Stock Exchange under the
symbol NRG.
The performance graph shown below is being provided as furnished
and compares each period assuming that $100 was invested on
December 31, 2004, in each of the common stock of NRG, the
stocks included in the S&P 500 and the stocks included in
the UTY, and that all dividends were reinvested.
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Dec-2004
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Dec-2005
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Dec-2006
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Dec-2007
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Dec-2008
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Dec-2009
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NRG Energy, Inc.
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$
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100.00
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$
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130.71
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$
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155.37
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$
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240.44
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$
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129.43
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$
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130.98
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S&P 500
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100.00
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104.91
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121.48
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128.16
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80.74
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102.11
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UTY
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$
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100.00
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$
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118.43
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$
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142.34
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$
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169.34
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$
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123.15
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$
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135.51
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66
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Item 5
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Selected
Financial Data
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The following table presents NRGs historical selected
financial data. The data included in the following table has
been restated to reflect the assets, liabilities and results of
operations of certain projects that have met the criteria for
treatment as discontinued operations as well as the retroactive
effect of the
two-for-one
stock split effective May 25, 2007. For additional
information refer to Item 14 Note 4,
Discontinued Operations and Dispositions, to the
Consolidated Financial Statements.
This historical data should be read in conjunction with the
Consolidated Financial Statements and the related notes thereto
in Item 14 and Item 6, Managements Discussion
and Analysis of Financial Condition and Results of
Operations.
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Year Ended December 31,
|
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|
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2009
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2008
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2007
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2006
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2005
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(In millions unless otherwise noted)
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Statement of income data:
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Total operating revenues
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$
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8,952
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$
|
6,885
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$
|
5,989
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$
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5,585
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|
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$
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2,400
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|
|
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|
|
Total operating costs and expenses
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7,283
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|
|
|
5,119
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|
|
|
5,073
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|
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4,724
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2,290
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Income from continuing operations, net
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941
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1,053
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|
556
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539
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68
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Income from discontinued operations, net
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172
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17
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78
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16
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Net income attributable to NRG Energy, Inc.
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942
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1,225
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573
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617
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84
|
|
|
|
|
|
Common share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic shares outstanding average
|
|
|
246
|
|
|
|
235
|
|
|
|
240
|
|
|
|
258
|
|
|
|
169
|
|
|
|
|
|
Diluted shares outstanding average
|
|
|
271
|
|
|
|
275
|
|
|
|
288
|
|
|
|
301
|
|
|
|
171
|
|
|
|
|
|
Shares outstanding end of year
|
|
|
254
|
|
|
|
234
|
|
|
|
237
|
|
|
|
245
|
|
|
|
161
|
|
|
|
|
|
Per share data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to NRG from continuing
operations basic
|
|
|
3.70
|
|
|
|
4.25
|
|
|
|
2.09
|
|
|
|
1.89
|
|
|
|
0.28
|
|
|
|
|
|
Income attributable to NRG from continuing
operations diluted
|
|
|
3.44
|
|
|
|
3.80
|
|
|
|
1.90
|
|
|
|
1.76
|
|
|
|
0.28
|
|
|
|
|
|
Net income attributable to NRG basic
|
|
|
3.70
|
|
|
|
4.98
|
|
|
|
2.16
|
|
|
|
2.19
|
|
|
|
0.38
|
|
|
|
|
|
Net income attributable to NRG diluted
|
|
|
3.44
|
|
|
|
4.43
|
|
|
|
1.96
|
|
|
|
2.02
|
|
|
|
0.38
|
|
|
|
|
|
Book value
|
|
|
29.72
|
|
|
|
26.75
|
|
|
|
19.55
|
|
|
|
19.60
|
|
|
|
11.31
|
|
|
|
|
|
Business metrics:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from operations
|
|
$
|
2,106
|
|
|
$
|
1,479
|
|
|
$
|
1,517
|
|
|
$
|
408
|
|
|
$
|
68
|
|
|
|
|
|
Liquidity
position
(a)
|
|
|
3,971
|
|
|
|
4,124
|
|
|
|
2,715
|
|
|
|
2,227
|
|
|
|
758
|
|
|
|
|
|
Ratio of earnings to fixed charges
|
|
|
3.27
|
|
|
|
3.65
|
|
|
|
2.24
|
|
|
|
2.36
|
|
|
|
1.57
|
|
|
|
|
|
Ratio of earnings to fixed charges and preference dividends
|
|
|
3.04
|
|
|
|
3.19
|
|
|
|
1.99
|
|
|
|
2.08
|
|
|
|
1.32
|
|
|
|
|
|
Return on equity
|
|
|
12.24
|
%
|
|
|
17.20
|
%
|
|
|
10.38
|
%
|
|
|
10.85
|
%
|
|
|
3.77
|
%
|
|
|
|
|
Ratio of debt to total capitalization
|
|
|
43.49
|
%
|
|
|
47.50
|
%
|
|
|
55.58
|
%
|
|
|
57.18
|
%
|
|
|
44.91
|
%
|
|
|
|
|
Balance sheet data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
$
|
6,208
|
|
|
$
|
8,492
|
|
|
$
|
3,562
|
|
|
$
|
3,083
|
|
|
$
|
2,197
|
|
|
|
|
|
Current liabilities
|
|
|
3,762
|
|
|
|
6,581
|
|
|
|
2,277
|
|
|
|
2,032
|
|
|
|
1,357
|
|
|
|
|
|
Property, plant and equipment, net
|
|
|
11,564
|
|
|
|
11,545
|
|
|
|
11,320
|
|
|
|
11,546
|
|
|
|
2,559
|
|
|
|
|
|
Total assets
|
|
|
23,378
|
|
|
|
24,808
|
|
|
|
19,274
|
|
|
|
19,436
|
|
|
|
7,467
|
|
|
|
|
|
Long-term debt, including current maturities and capital leases
|
|
|
8,418
|
|
|
|
8,161
|
|
|
|
8,346
|
|
|
|
8,698
|
|
|
|
2,456
|
|
|
|
|
|
Total stockholders equity
|
|
$
|
7,697
|
|
|
$
|
7,123
|
|
|
$
|
5,519
|
|
|
$
|
5,686
|
|
|
$
|
2,231
|
|
|
|
|
|
N/A Not applicable
|
|
|
(a)
|
|
Liquidity position is determined as
disclosed in Item 6, Liquidity and Capital Resources,
Liquidity Position. It includes funds deposited by
counterparties of $177 million and $754 million as of
December 31, 2009 and 2008, respectively, which represents
cash held as collateral from hedge counterparties in support of
energy risk management activities. It is the Companys
intention to limit the use of these funds for repayment of the
related current liability for collateral received in support of
energy risk management activities.
|
67
The following table provides the details of NRGs operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(In millions)
|
|
|
Energy
|
|
$
|
3,031
|
|
|
$
|
4,519
|
|
|
$
|
4,265
|
|
|
$
|
3,155
|
|
|
$
|
1,840
|
|
Capacity
|
|
|
1,030
|
|
|
|
1,359
|
|
|
|
1,196
|
|
|
|
1,516
|
|
|
|
563
|
|
Retail revenue
|
|
|
4,440
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Risk management activities
|
|
|
418
|
|
|
|
418
|
|
|
|
4
|
|
|
|
124
|
|
|
|
(292)
|
|
Contract amortization
|
|
|
(179
|
)
|
|
|
278
|
|
|
|
242
|
|
|
|
628
|
|
|
|
9
|
|
Thermal
|
|
|
100
|
|
|
|
114
|
|
|
|
125
|
|
|
|
124
|
|
|
|
124
|
|
Hedge Reset
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(129
|
)
|
|
|
|
|
Other
|
|
|
112
|
|
|
|
197
|
|
|
|
157
|
|
|
|
167
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
8,952
|
|
|
$
|
6,885
|
|
|
$
|
5,989
|
|
|
$
|
5,585
|
|
|
$
|
2,400
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue consists of revenues received from third parties
for sales in the day-ahead and real-time markets, as well as
bilateral sales. Beginning in 2006, energy revenues also
included revenues from the settlement of financial instruments
that qualify for cash flow hedge accounting treatment.
Capacity revenue consists of revenues received from a third
party at either the market or negotiated contract rates for
making installed generation capacity available in order to
satisfy system integrity and reliability requirements. Capacity
revenues also included revenues from the settlement of financial
instruments that qualify for cash flow hedge accounting
treatment. In addition, capacity revenue includes revenue
received under tolling arrangements, which entitle third parties
to dispatch NRGs facilities and assume title to the
electrical generation produced from that facility.
Retail revenue, representing operating revenue of Reliant
Energy, consists of revenues from retail electric sales to
residential, small business, commercial, industrial and
governmental/institutional customers, as well as revenues from
the sale of excess supply into various markets in Texas.
Risk management activities includes fair value changes of
economic hedges that did not qualify for cash flow hedge
accounting, ineffectiveness on cash flow hedges and trading
activities. It also includes the settlement of all derivative
transactions that do not qualify for cash flow hedge accounting
treatment. Prior to 2006, risk management activities included
the settlement of financial instruments that qualified for cash
flow hedge accounting treatment.
Thermal revenue consists of revenues received from the sale of
steam, hot and chilled water generally produced at a central
district energy plant and sold to commercial, governmental and
residential buildings for space heating, domestic hot water
heating and air conditioning. It also includes the sale of
high-pressure steam produced and delivered to industrial
customers that is used as part of an industrial process.
Contract amortization revenues consists of acquired power
contracts, gas swaps, and certain power sales agreements assumed
at Fresh Start and Texas Genco purchase accounting dates related
to the sale of electric capacity and energy in future periods,
which are amortized into revenue over the term of the underlying
contracts based on actual generation or contracted volumes. Also
included is amortization of the intangible asset for net
in-market C&I contracts that was established in connection
with the acquisition of Reliant Energy.
Hedge Reset is the impact from the net settlement of long-term
power contracts and gas swaps by negotiating prices to current
market. This transaction was completed in November 2006.
Other revenue primarily consists of operations and maintenance
fees, or O&M fees, construction management services, or CMA
fees, sale of natural gas and emission allowances, and revenue
from ancillary services. O&M fees consist of revenues
received from providing certain unconsolidated affiliates with
services under long-term operating agreements. CMA fees are
earned where NRG provides certain management and oversight of
construction projects pursuant to negotiated agreements such as
for the GenConn and Cedar Bayou 4 construction projects.
Ancillary services are comprised of the sale of energy-related
products associated with the generation of electrical energy
such as spinning reserves, reactive power and other similar
products.
68
|
|
Item 6
|
Managements
Discussion and Analysis of Financial Condition and Results of
Operations
|
In this discussion and analysis, the Company discusses and
explains its financial condition and results of operations,
including:
|
|
|
|
|
Factors which affect NRGs business;
|
|
|
NRGs earnings and costs in the periods presented;
|
|
|
Changes in earnings and costs between periods;
|
|
|
Impact of these factors on NRGs overall financial
condition;
|
|
|
A discussion of new and ongoing initiatives that may affect
NRGs future results of operations and financial condition;
|
|
|
Expected future expenditures for capital projects; and
|
|
|
Expected sources of cash for future operations and capital
expenditures.
|
As you read this discussion and analysis, refer to NRGs
Consolidated Statements of Operations, which presents the
results of the Companys operations for the years ended
December 31, 2009, 2008 and 2007. The Company analyzes and
explains the differences between the periods in the specific
line items of NRGs Consolidated Statements of Operations.
This discussion and analysis has been organized as follows:
|
|
|
|
|
Executive Summary, including introduction and overview, business
strategy, and the business environment in which NRG operates
including how regulation, weather, and other factors affect the
business;
|
|
|
Significant events that are important to understanding the
results of operations and financial condition;
|
|
|
Results of operations beginning with an overview of the
Companys results, followed by a more detailed review of
those results by operating segment;
|
|
|
Financial condition addressing credit ratings, liquidity
position, sources and uses of cash, capital resources and
requirements, commitments, and off-balance sheet
arrangements; and
|
|
|
Critical accounting policies which are most important to both
the portrayal of the Companys financial condition and
results of operations, and which require managements most
difficult, subjective or complex judgment.
|
Executive
Summary
Overview
NRG Energy, Inc., or NRG or the Company, is primarily a
wholesale power generation company with a significant presence
in major competitive power markets in the U.S., 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 U.S. and
select international markets, and the supply of electricity and
energy services to retail electricity customers in the Texas
market.
As of December 31, 2009, NRG had a total global generation
portfolio of 187 active operating fossil fuel and nuclear
generation units, at 44 power generation plants, with an
aggregate generation capacity of approximately 24,115 MW,
and approximately 400 MW under construction which includes
partner interests of 200 MW. In addition to its fossil fuel
plant ownership, NRG has ownership interests in operating
renewable facilities with an aggregate generation capacity of
365 MW, consisting of three wind farms representing an
aggregate generation capacity of 345 MW (which includes
partner interest of 75 MW) and a solar facility with an
aggregate generation capacity of 20 MW. Within the U.S.,
NRG has large and diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 23,110 MW of fossil fuel and nuclear
generation capacity in 179 active generating units at 42 plants.
The Companys power generation facilities are most heavily
concentrated in Texas (approximately 11,340 MW, including
345 MW from three wind farms), the Northeast (approximately
7,015 MW), South Central (approximately 2,855 MW), and
West (approximately 2,150 MW, including 20 MW from a
solar farm) regions of the U.S., with approximately 115 MW
of additional generation capacity from the Companys
thermal assets. In addition, through certain foreign
subsidiaries, NRG has investments in power generation projects
located in Australia and Germany with approximately
1,005 MW of generation capacity.
69
NRGs principal domestic power plants consist of a mix of
natural gas-, coal-, oil-fired, nuclear and renewable
facilities, representing approximately 46%, 32%, 16%, 5% and 1%
of the Companys total domestic generation capacity,
respectively. In addition, 9% 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
the Merit Order, and include thermal energy production plants.
The sale of capacity and power from baseload generation
facilities accounts for the majority of the Companys
revenues and provides a stable source of cash flow. In addition,
NRGs generation portfolio provides the Company with
opportunities to capture additional revenues by selling power
during periods of peak demand, offering capacity or similar
products to retail electric providers and others, and providing
ancillary services to support system reliability.
On May 1, 2009, NRG acquired Reliant Energy, which is the
second largest electricity provider to Mass customers in Texas.
Reliant Energy is also the largest electricity and energy
services provider, based on load, to C&I customers in
Texas. Based on metered locations, as of December 31, 2009,
Reliant Energy had approximately 1.5 million Mass customers
and approximately 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 through production and the sale of safe, reliable and
affordable power to its customers and in the markets served by
the Company, while aggressively pursuing sustainable energy
solutions for the future.
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) 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; and (v) pursuit of selective
acquisitions, joint ventures, divestitures and investments in
energy-related new businesses and new technologies in order to
enhance the Companys asset mix and competitive position in
the its core markets, as well as increasing demand for
sustainable energy lifestyles and combating climate change.
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:
Operational Performance The Company is
focused on increasing value from its existing assets. Through
the FORNRG 2.0 initiative, NRG will continue its
companywide effort to focus on extracting value from its
portfolio by improving plant performance, reducing costs and
harnessing the Companys advantages of scale in the
procurement of fuels and other commodities, parts and services,
and in doing so improving the Companys ROIC.
In addition to the FORNRG initiative, the Company seeks
to maximize profitability and manage cash flow volatility
through the Companys commercial operations strategy by
leveraging its: (i) expertise in marketing power and
ancillary services; (ii) its knowledge of markets;
(iii) its balanced financial structure; and (iv) its
diverse portfolio of power generation assets in the execution of
asset-based risk management, hedging, marketing and trading
strategies within well-defined risk and liquidity guidelines.
The Companys marketing and hedging philosophy is centered
on generating stable returns from its portfolio of baseload
power generation assets while preserving an ability to
capitalize on strong spot market conditions and to capture the
extrinsic value of the Companys intermediate and peaking
facilities and portions of its baseload fleet.
70
The Company also seeks to achieve synergies between the
Companys retail and wholesale business in Texas through
its complementary generation portfolio in the Texas region,
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, credit exposures, and collateral
postings. In addition, with Reliant Energys base of retail
customers, NRG now has a customer interface with the scale that
is important to the successful deployment of consumer facing
energy technologies and services.
Finally, NRG remains focused on cash flow and maintaining
appropriate levels of liquidity, debt and equity in order to
ensure continued access, through all economic and financial
cycles, to capital for investment, to enhance risk-adjusted
returns and to provide flexibility in executing NRGs
business strategy, including a regular return of capital to its
debt and equity holders.
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, as well as
clean coal and the retrofit of post-combustion
carbon capture technologies. Primarily through the
RepoweringNRG and econrg initiatives, NRG intends to
invest in its existing assets through plant improvements,
repowerings, brownfield development and site expansions to meet
anticipated requirements for additional capacity in NRGs
core markets, with an emphasis on new capacity that is supported
by long-term power sales agreements and financed with limited or
non-recourse project financing, and the demonstration and
deployment of green technologies.
RepoweringNRG is a comprehensive portfolio redevelopment
program designed to develop, construct and operate new
multi-fuel, multi-technology, highly efficient and
environmentally responsible generation capacity in locations
where the Company anticipates retiring certain existing units
and adding new generation to meet growing demand in the
Companys core markets. econrg represents NRGs
commitment to environmentally responsible power generation by
addressing the challenges of climate change, clean air and
water, and conservation of our natural resources while taking
advantage of business opportunities that may inure to NRG. 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 reduced
environmental impacts, including facilities that either have
near zero GHG emissions or can be equipped to capture and
sequester GHG emissions. In addition, 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 as well
as other government incentive packages. NRG has several
applications pending or contemplated.
New Businesses and New Technology NRG
is focused on the development and investment in energy-related
new businesses and new technologies, including low or no GHG
emitting energy generating sources, such as nuclear, wind, solar
thermal, and photovoltaic, as well as other endeavors where the
benefits of such investments represent significant commercial
opportunities and create a comparative advantage for the
Company, such as smart meters, electric vehicle ecosystems, and
distributed clean solutions. The Company has made a
series of recent advancements in these initiatives, including:
(i) the acquisition of Bluewater Wind, an offshore wind
development company; (ii) the acquisition of Blythe Solar,
the largest photovoltaic solar power facility in California;
(iii) the commercial operation of the Langford Wind Farm,
the Companys third wind farm to be brought online;
(iv) a partnership between Reliant Energy and the City of
Houston and a partnership between Reliant Energy and Nissan to
make Houston, Texas a launch city for the use of electric
vehicles; and (v) the use of smart meters for
Reliant Energy customers. Furthermore, the Company, supported by
the econrg initiative, intends to capitalize on the high growth
opportunities presented by government-mandated renewable
portfolio standards, tax incentives and loan guaranties for
renewable energy projects, new technologies and expected future
carbon regulation.
Company-Wide Initiatives In addition,
the Companys overall strategy is also supported by Future
NRG and NRG Global Giving initiatives. Future NRG is the
Companys workforce planning and development initiative and
represents NRGs strong commitment to planning for future
staffing requirements to meet the on-going needs of the
Companys current operations and initiatives. NRG Global
Giving is designed to enhance respect for the community, which
is one of NRGs core values. The Global Giving Program
invests NRGs resources to strengthen
71
the communities where NRG does business and seeks to make
community investments in four focus areas: community and
economic development, education, environment and human welfare.
Business
Environment
General Industry Trends impacting the power
industry include: (i) financial credit market availability;
and (ii) increased regulatory and political scrutiny. The
industry dynamics and external influences that will affect the
Company and the power generation industry in 2010 and for the
medium term include:
Consolidation Over the long-term, industry
consolidation is expected to occur, with mergers and
acquisitions activity in the power generation sector likely to
involve utility-merchant or merchant-merchant combinations.
There may also be interest by foreign power companies,
particularly European utilities, in the American power
generation sector.
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. In addition, economic recessions
historically result in lower power demand, power prices, and
fuel prices. During 2009, the nations credit markets
recovered to some extent although credit continued to be tight
relative to years prior to 2008. 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%. In addition, NRG had
arranged a Credit Sleeve Reimbursement Agreement, or CSRA, with
Merrill Lynch to support Reliant Energy after closing the
acquisition. NRG has a diversified liquidity program, with
$3.8 billion in total liquidity as of December 31,
2009, 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 transacts with a
diversified pool of counterparties and actively manages the
Companys exposure to any single counterparty. See
Part II, Item 6 Liquidity and Capital
Resources, and Part II, Item 6a
Quantitative and Qualitative Disclosures about Market Risk
for a further discussion.
The addition of Reliant Energy to NRGs existing generation
business 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 its wholesale supply in order to secure
its margin as load is contracted, should also benefit from
having better access to nonstandard and longer term products
necessary to meet load. NRG expects to continue hedging its
wholesale production consistent with its prior practice, but now
will benefit from having an additional outlet for its range of
generation products.
Climate Change The U.S. signed the
Copenhagen Accord, or the Accord, which sets the stage for a
worldwide approach to this global issue. Under the Accord, the
U.S. has committed to a 17% reduction from 2005 emission
levels of GHGs by 2020. While Congress was unable to come to
agreement on climate legislation in 2009, the subject continues
to be a topic for consideration in 2010. Lack of legislation
will prolong the uncertainty of the nature and timing of GHG
requirements and their resulting impact on NRG.
Climate change efforts continued outside of the legislature. The
RGGI
cap-and-trade
program, in which NRGs emissions of
CO2
were 8 million tonnes in 2009, ended its first year with
low allowance prices, nearing the reserve floor. This trend is
expected to continue in the short term while the region works
through the recession and increased use of renewable energy.
California continues to develop their program for 2012
implementation. In addition to regional efforts, the
U.S. EPA moved forward with a finding that GHGs do pose a
threat to public health and welfare and light duty tailpipe
regulations. These efforts will ultimately trigger the
application of existing GHG permitting requirements for new and
modified stationary sources like power plants, although the
effective date and specifics of implementation lack clarity. The
impact to NRG is dependent on the timing and implementation of
PSD/NSR and Title V permit requirements with regard to GHGs
and any future actions taken by the U.S. EPA.
In 2009, in the course of producing approximately
71 million MWh of electricity, NRGs power plants
emitted 59 million tonnes of
CO2,
of which 53 million tonnes were emitted in the U.S.,
3 million tonnes in Germany and 3 million tonnes in
Australia. The impact from legislation or federal, regional or
state regulation of GHGs on the Companys financial
performance will depend on a number of factors, including the
overall level of GHG reductions
72
required under any such regulations, the price and availability
of offsets, and the extent to which NRG would be entitled to
receive
CO2
emissions allowances without having to purchase them in an
auction or on the open market. Thereafter, under any such
legislation or regulation, the impact on NRG would depend on the
Companys level of success in developing and deploying low
and no carbon technologies such as those being pursued as part
of the RepoweringNRG. Additionally, NRGs current
contracts with its South Central regions cooperative
customers allows for the recovery of emission-based costs.
Environmental Regulatory Landscape A number
of regulations that could significantly impact the power
generation industry are in development or under review by the
U.S. EPA: CAIR, MACT, NAAQS revisions, coal combustion
wastes, once-through cooling, and GHG regulations. While most of
these regulations have been considered for some time, they are
expected to gain clarity in 2010 through 2011. The timing and
stringency of these regulations will provide a framework for the
retrofit of existing fossil plants and deployment of new,
cleaner technologies in the next decade. The Company has
included capital to meet anticipated CAIR Phase I and II, MACT
standards for mercury, and the installation of Best
Technology Available under the 316(b) Rule in the current
estimated environmental capital expenditure. While the Company
cannot predict the impact of future regulations and would likely
face additional investments over time, these expenditures,
combined with the Companys already existing air quality
controls; use of Powder River Basin coal; closed cycle cooling;
and dry ash handling systems, position NRG well to meet more
stringent requirements.
Public Policy Support and Government Financial
Incentives The economic crisis, a changing
public policy environment, and the current political climate
have led to a shift away from utility investment in traditional
fossil-fueled coal and natural gas-fired capacity and towards
investment in non-traditional capacity, including renewable
technologies, demand-side resources and nuclear. Generous public
support, in the form of tax credits, loan guarantees,
depreciation tax benefits, renewable energy credits, or RECs,
and various other state and local incentives, are now available
to builders of renewable electric generation. State Renewable
Portfolio Standards, or RPS, requirements are now on the
books in 28 states requiring load-serving entities to
eventually source large percentages of their supply requirements
from renewable sources or by purchasing REC credits, and federal
requirements may follow. Designers of capacity markets in the
Northeast region have attempted to improve the position of
demand side resources relative to peaking capacity by holding
these resources to a less stringent deliverability standard.
Finally, the threat of carbon policy has had a
chilling effect on new fossil generation supply
additions, while encouraging all zero-carbon sources. These
developments are likely to increase the role of renewable energy
in the next energy commodity cycle, driving changes in wholesale
market dynamics as renewable market share rises.
Infrastructure Development In the recent
recessionary environment, the U.S. has experienced a
contraction in demand, led primarily by reduced industrial
demand in the manufacturing, chemical and petrochemical
industries. As a result of lower demand and a proliferation of
new natural gas supply from shale gas reserves, near term gas
and power markets have experienced lower prices thus causing
delays and cancellations of new generation supply and
transmission investments. The Company expects recovery from the
recession could lead to demand recovery and a trending back
toward normalized growth rates spurring the need for additional
generation supply. The potential for future federal carbon
legislation and more restrictive environmental regulations could
cause a rebalancing of the generation sector with older less
efficient coal plants risking retirement and new infrastructure
capital being deployed into low carbon technology in the form of
baseload nuclear, renewable energy projects, and high efficiency
(quick start) natural gas units. Government sponsored subsidies
in the form of cash grants, investment tax credits and loan
guarantees along with improved environmental policy clarity will
continue to be crucial to help finance additional generation
investment.
Natural Gas Market The price of natural gas
plays an important role in setting the price of electricity in
many of the regions where NRG operates power plants. Natural gas
prices are driven by many variables including demand from
industrial, residential; and electric sectors; productivity
across natural gas supply basins; fixed and variable costs of
natural gas production; changes in pipeline infrastructure, and
the financial and hedging profile of natural gas consumers and
producers. In 2009, domestic natural gas supply increased, while
demand decreased in the wake of the recession, leading to a fall
in natural gas prices when compared to 2008. The increase in
natural gas supply was due to increased production from
unconventional resources, particularly the shale basins, and
from the low variable costs of extraction from these resources.
The Company expects rebalancing of the natural gas market to
73
continue, and a price recovery could be driven by supply cuts as
producer hedges roll-off and variable costs rise above market
prices.
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
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|
Average Natural Gas Price ($/MMbtu)
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Henry Hub
|
|
$
|
3.92
|
|
|
$
|
8.85
|
|
|
$
|
6.94
|
|
|
|
Electricity Prices The price of electricity
is a key determinant of the profitability of the Companys
generation portfolio. In 2009, prices for electricity were lower
than in 2008, affected by both lower prices for natural gas and
lower electric demand due largely to the recession. As general
economic conditions improve, NRG expects to see a similar
recovery in electric demand. The following table summarizes
average on-peak power prices for each of the major markets in
which NRG operates for the years ended December 31, 2009,
2008 and 2007.
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|
|
|
|
|
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|
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|
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Average on Peak Power Price
($/MWh)
|
Region
|
|
|
|
2009
|
|
|
|
2008
|
|
|
|
2007
|
|
|
Texas
|
|
$
|
|
|
|
|
35.43
|
|
|
$
|
|
|
|
|
86.23
|
|
|
$
|
|
|
|
|
60.98
|
|
|
|
Northeast
|
|
|
|
|
|
|
46.14
|
|
|
|
|
|
|
|
91.68
|
|
|
|
|
|
|
|
76.37
|
|
|
|
South Central
|
|
|
|
|
|
|
33.58
|
|
|
|
|
|
|
|
71.25
|
|
|
|
|
|
|
|
59.63
|
|
|
|
West
|
|
$
|
|
|
|
|
40.10
|
|
|
$
|
|
|
|
|
82.20
|
|
|
$
|
|
|
|
|
66.46
|
|
|
|
Competition
Wholesale power generation is a capital-intensive,
commodity-driven business with numerous industry participants.
NRG competes on the basis of the location of its plants and
ownership of multiple plants in various regions, which increases
the stability and reliability of its energy supply. Wholesale
power generation is basically a local business that is currently
highly fragmented relative to other commodity industries and
diverse in terms of industry structure. As such, there is a wide
variation in terms of the capabilities, resources, nature, and
identity of the companies NRG competes with depending on the
market.
The deregulated retail energy business in ERCOT is a competitive
business. In general, competition in the retail energy business
is on the basis of price, service, brand image, product
offerings, and market perceptions of creditworthiness. Reliant
Energy sells electricity pursuant to fixed price or indexed
products, and customers elect terms of service typically ranging
from one month to five years. Reliant Energys rates are
market-based rates, and not subject to traditional
cost-of-service
regulation by the PUCT. Non-affiliated transmission and
distribution service companies provide, on a non-discriminatory
basis, the wires and metering services necessary to access
customers.
Weather
Weather conditions in the different regions of the
U.S. influence the financial results of NRGs
businesses. Weather conditions can affect the supply and demand
for electricity and fuels. Changes in energy supply and demand
may impact the price of these energy commodities in both the
spot and forward markets, which may affect the Companys
results in any given period. Typically, demand for and the price
of electricity is higher in the summer and the winter seasons,
when temperatures are more extreme. The demand for and price of
natural gas and oil are higher in the winter. However, all
regions of North America typically do not experience extreme
weather conditions at the same time, thus NRG is typically not
exposed to the effects of extreme weather in all parts of its
business at once.
Other
Factors
A number of other factors significantly influence the level and
volatility of prices for energy commodities and related
derivative products for NRGs business. These factors
include:
|
|
|
|
|
seasonal daily and hourly changes in demand;
|
|
|
extreme peak demands;
|
|
|
available supply resources;
|
|
|
transportation and transmission availability and reliability
within and between regions;
|
74
|
|
|
|
|
location of NRGs generating facilities relative to the
location of its load-serving opportunities;
|
|
|
procedures used to maintain the integrity of the physical
electricity system during extreme conditions; and
|
|
|
changes in the nature and extent of federal and state
regulations.
|
These factors can affect energy commodity and derivative prices
in different ways and to different degrees. These effects may
vary throughout the country as a result of regional differences
in:
|
|
|
|
|
weather conditions;
|
|
|
market liquidity;
|
|
|
capability and reliability of the physical electricity and gas
systems;
|
|
|
local transportation systems; and
|
|
|
the nature and extent of electricity deregulation.
|
Environmental
Matters, Regulatory Matters and Legal Proceedings
NRG discusses details of its other environmental matters in
Item 14 Note 24, Environmental
Matters, to the Consolidated Financial Statements and
Item 1, Business Environmental Matters,
section. NRG discusses details of its regulatory matters in
Item 14 Note 23, Regulatory
Matters, to the Consolidated Financial Statements and
Item 1, Business Environmental Matters,
section. NRG discusses details of its legal proceedings in
Item 14 Note 22, Commitments and
Contingencies, to these Consolidated Financial Statements.
Some of this information is about costs that may be material to
the Companys financial results.
NINA On December 30, 2009, NINA
had received an estimate from TANE, the prime contractor,
containing the overnight estimate of the EPC Cost. The estimate
was approximately $11.5 billion for STP Units 3 and 4 with
an opportunity to reduce cost subject to certain specification
changes. Based on the estimate provided by TANE and the
Companys internal assessments, NINA continues to believe
that NRGs stated target of $9.8 billion or $3,229/kW
based on 3,000 MW gross output is achievable. Cost
reductions will be achieved through a combination of
specification changes and the re-alignment of risks and
responsibilities among key project stakeholders.
Owners Costs for the project, on an escalated basis, are
estimated to total approximately $2.1 billion during the
construction period. This is primarily comprised of the costs
for NRGs agent STPNOC, owners contingency and the
initial fuel load. Financing Costs are estimated to be
approximately $1.5 billion during the construction period,
and are comprised of the variables described above.
On February 17, 2010, an agreement in principle was reached
with CPS for NINA to acquire a controlling interest in the
project to construct STP Units 3 and 4 through a settlement of
the litigation between the parties. As part of the agreement,
NINA would increase its ownership in the STP Units 3 and 4
project from 50% to 92.375% and would assume full management
control of the project. NINA would also pay $80 million to
CPS, subject to receipt of a conditional DOE loan guarantee. The
first $40 million would be promptly paid after receipt of
the guarantee and the other half six months later. An additional
$10 million would be donated by NRG over four years in
annual payments of $2.5 million to the Residential Energy
Assistance Partnership in San Antonio. As part of the
agreement with CPS, all litigation would be dismissed with
prejudice. The parties continue to negotiate terms regarding
final documentation of the agreement in principle.
The agreement would enable the STP Unit 3 and 4 project
expansion to move forward and allow NINA to continuing pursuing
its application for a conditional loan guarantee from the DOE.
If NINA is not successful in reaching a final agreement with
CPS, obtaining a conditional loan guarantee, or selling down its
interest in STP Units 3 and 4, there could be negative
implications for the project that may result in a reassessment
of the probability of success of the project and an impairment
of the value of the capitalized assets for STP Units 3 and 4. An
impairment would result in a permanent
write-down
of the $299 million of
construction-in-progress
capitalized through December 31, 2009, plus any amounts
capitalized through the impairment date.
75
Impact
of inflation on NRGs results
Unless discussed specifically in the relevant segment, for the
years ended December 31, 2009, 2008 and 2007, the impact of
inflation and changing prices (due to changes in exchange rates)
on NRGs revenues and income from continuing operations was
immaterial.
Capital
Allocation Program
NRGs capital allocation philosophy includes reinvestment
in its core facilities, maintenance of prudent debt levels and
interest coverage, the regular return of capital to shareholders
and investment in repowering opportunities. As part of the 2010
program, the Company will invest approximately $474 million
in maintenance and environmental capital expenditures in the
existing assets and $707 million in projects under
RepoweringNRG that are currently under construction or
for which there exists current obligations. Finally, in addition
to scheduled debt amortization payment, in the first quarter
2010 the Company will offer its first lien lenders
$430 million of its 2009 excess cash flow (as defined in
the Senior Credit Facility) of which the Company made a
prepayment of $200 million in December 2009.
Significant
events during the year ended December 31,
2009
Results
of Operations and Financial Condition
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|
|
|
|
Acquisition of Reliant Energy On May 1,
2009, NRG acquired Reliant Energy, which consisted of the entire
Texas electric retail business operation of RRI, for cash
consideration of $360 million, net of cash acquired. During
the eight months ended December 31, 2009, Reliant Energy
added $4.4 billion in retail revenue and $3.5 billion
in cost of sales to the Companys results. In addition, NRG
incurred non-recurring acquisition-related transaction and
integration costs which totaled $54 million for the eight
months ended December 31, 2009.
|
|
|
|
Lower energy revenue Energy revenues
decreased $1.5 billion as a result of reduced energy prices
as well as lower generation. The reduced energy prices were
caused by lower average natural gas prices of approximately 56%.
The reduction in generation was driven by weakened demand for
power due to the recessionary economy.
|
|
|
|
Lower capacity revenue Capacity revenue
decreased $329 million as a result of a lower portion of
baseload contracts in the Texas region containing a capacity
component.
|
|
|
|
Higher selling, general and administrative
The Companys total selling, general and administrative
expense increased in 2009 by $231 million. For the eight
months ended December 31, 2009, Reliant Energy selling,
general and administrative expense totaled $203 million,
including $61 million of bad debt expense. Also included in
2009 results was the non-recurring cost of the Exelons
exchange offer and proxy contest efforts of $31 million.
|
|
|
|
Liquidity position The Companys total
liquidity, excluding collateral received, rose $430 million
in 2009. Cash balances grew by $810 million since the end
of 2008 as $2.1 billion of cash provided by operating
activities exceeded cash used including $734 million of
capital expenditures, $644 million in debt payments,
$500 million in treasury share payments, and
$427 million in business acquisitions offset by the
proceeds from the sale of MIBRAG of $284 million and the
proceeds from the issuance of debt of $892 million.
|
|
|
|
Purchase of treasury shares During 2009, the
Company repurchased 19,305,500 shares of common stock under
its capital allocation plan for a total of $500 million.
|
|
|
|
Preferred Stock conversion On March 16,
2009, all of the outstanding shares of the Companys 5.75%
Preferred Stock were converted into common stock for
$447 million. During 2009, a total of 265,870 shares
of Companys 4% Preferred Stock were converted into common
stock for $257 million.
|
|
|
|
Sale of MIBRAG In 2009, the Company sold its
50% ownership interest in MIBRAG, to a consortium of
Severoćeské doly Chomutov, a member of the CEZ Group,
and J&T Group. For its share, NRG received proceeds of
$284 million, net of transaction costs and realized a
$128 million gain on sale of the equity method investment.
|
76
|
|
|
|
|
Issuance of 2019 Senior Notes In June 2009,
NRG completed the issuance of $700 million aggregate
principal amount of 8.5% Senior Notes due 2019, or 2019
Senior Notes. The Company used a portion of the net proceeds of
$678 million to facilitate the early termination of
NRGs obligations pursuant to the CSRA Amendment, which
became effective October 5, 2009.
|
|
|
|
Merrill Lynch Credit Sleeve Facility On
May 1, 2009, NRG arranged with Merrill Lynch 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 Power Marketing LLC, or PML, and Reliant Energy
Power Supply LLC, or REPS, modified or novated certain
transactions with counterparties to transfer PMLs
in-the-money
transactions to REPS and moved $522 million of cash
collateral held by NRG to Merrill Lynch, thereby reducing
Merrill Lynchs actual and contingent collateral supporting
Reliant Energy
out-of-money
positions. Effective October 5, 2009, the Company then
executed the CSRA Amendment. In connection with this
transaction, the Company posted $366 million of cash
collateral to Merrill Lynch and other counterparties, returned
$53 million of counterparty collateral, issued
$206 million of letters of credit, and received
$45 million of counterparty collateral. In addition,
Merrill Lynch returned $250 million of previously posted
cash collateral, and released liens on $322 million of
unrestricted cash held by Reliant Energy. Upon execution of the
CSRA Amendment, the Company was required to post collateral for
any net liability derivatives, and other static margin
associated with supply for Reliant Energy.
|
|
|
|
GenConn LLC related financings In April 2009,
NRG Connecticut Peaking LLC., a wholly-owned subsidiary of NRG,
executed 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. Also 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.
The aggregate credit amount secured is $291 million,
including $48 million for the revolving facility. In August
2009, GenConn began to draw under the secured financing to cover
costs related to the Devon project and as of December 31,
2009, has drawn $48 million.
|
Other
|
|
|
|
|
NINA On February 24, 2009, NINA executed
an EPC agreement with TANE to build the STP expansion.
Concurrent with the execution of the EPC agreement, NINA entered
into a $500 million credit facility with Toshiba to finance
the cost of long-lead materials for STP Units 3 and 4.
|
|
|
|
Cedar Bayou Generating Station In June 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
520 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 260 MW given NRGs 50% ownership.
|
|
|
|
Langford Wind Project In December 2009, NRG
completed its Langford project, a wholly-owned 150 MW wind
farm located in Tom Green, Irion, and Schleicher Counties,
Texas. The Company funded and developed this wind farm which
consists of 100 General Electric 1.5 MW wind turbines. The
project is eligible for a cash grant from the Department of
Treasury and NRG has filed an application for an
$84 million grant.
|
|
|
|
Acquisition and completion of Blythe Solar On
November 20, 2009, NRG acquired through its wholly-owned
subsidiary NRG Solar LLC, FSE Blythe 1, LLC, or Blythe Solar,
from First Solar, Inc. On December 18, 2009, construction
was completed and commercial operation began for the 20 MW
utility-scale photovoltaic, or PV, solar facility located in
Riverside County in southeastern California. The project is
eligible for a cash grant from the Department of Treasury and
NRG will file an application for an $18 million grant.
|
|
|
|
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
|
77
|
|
|
|
|
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 presenting their
proposals for the Companys 2009 Annual Meeting of
Stockholders. NRGs Board of Directors recommended a vote
against each of their 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, stockholders voted to
re-elect all of the Companys director nominees to the NRG
Board of Directors and rejected Exelons proposals. 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. The total
defense costs associated with Exelons unsolicited proposal
was approximately $39 million for the period
October 1, 2008, through December 31, 2009, of which
$31 million was for the year ended December 31, 2009.
|
78
Consolidated
Results of Operations
2009
compared to 2008
The following table provides selected financial information for
NRG Energy, Inc., for the years ended December 31, 2009,
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change%
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
3,031
|
|
|
$
|
4,519
|
|
|
|
(33
|
)%
|
Capacity revenue
|
|
|
1,030
|
|
|
|
1,359
|
|
|
|
(24
|
)
|
Retail revenue
|
|
|
4,440
|
|
|
|
|
|
|
|
N/A
|
|
Risk management activities
|
|
|
418
|
|
|
|
418
|
|
|
|
|
|
Contract amortization
|
|
|
(179
|
)
|
|
|
278
|
|
|
|
(164
|
)
|
Thermal revenue
|
|
|
100
|
|
|
|
114
|
|
|
|
(12
|
)
|
Other revenues
|
|
|
112
|
|
|
|
197
|
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
8,952
|
|
|
|
6,885
|
|
|
|
30
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
|
4,524
|
|
|
|
2,641
|
|
|
|
71
|
|
Risk management activities
|
|
|
(338
|
)
|
|
|
|
|
|
|
N/A
|
|
Other cost of operations
|
|
|
1,137
|
|
|
|
957
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations
|
|
|
5,323
|
|
|
|
3,598
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
818
|
|
|
|
649
|
|
|
|
26
|
|
Selling, general and administrative
|
|
|
550
|
|
|
|
319
|
|
|
|
72
|
|
Acquisition-related transaction and integration costs
|
|
|
54
|
|
|
|
|
|
|
|
N/A
|
|
Development costs
|
|
|
48
|
|
|
|
46
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,793
|
|
|
|
4,612
|
|
|
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
2,159
|
|
|
|
2,273
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
41
|
|
|
|
59
|
|
|
|
(31
|
)
|
Gains on sales of equity method investments
|
|
|
128
|
|
|
|
|
|
|
|
N/A
|
|
Other (loss)/income, net
|
|
|
(5
|
)
|
|
|
17
|
|
|
|
(129
|
)
|
Refinancing expenses
|
|
|
(20
|
)
|
|
|
|
|
|
|
N/A
|
|
Interest expense
|
|
|
(634
|
)
|
|
|
(583
|
)
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(490
|
)
|
|
|
(507
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations before income tax
expense
|
|
|
1,669
|
|
|
|
1,766
|
|
|
|
(5
|
)
|
Income tax expense
|
|
|
728
|
|
|
|
713
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
941
|
|
|
|
1,053
|
|
|
|
(9
|
)
|
Income from discontinued operations, net of income tax expense
|
|
|
|
|
|
|
172
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
941
|
|
|
$
|
1,225
|
|
|
|
(23
|
)
|
Less: Net loss attributable to noncontrolling interest
|
|
|
(1
|
)
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
942
|
|
|
$
|
1,225
|
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMbtu)
|
|
|
3.92
|
|
|
|
8.85
|
|
|
|
(56
|
)%
|
N/A Not applicable
79
The table below represents the results of NRG excluding the
impact of Reliant Energy during the year ended December 31,
2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
Total excluding
|
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
Reliant Energy
|
|
|
Reliant Energy
|
|
|
Consolidated
|
|
|
Change%
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
3,031
|
|
|
$
|
|
|
|
$
|
3,031
|
|
|
$
|
4,519
|
|
|
|
(33
|
)%
|
Capacity revenue
|
|
|
1,030
|
|
|
|
|
|
|
|
1,030
|
|
|
|
1,359
|
|
|
|
(24
|
)
|
Retail revenue
|
|
|
4,440
|
|
|
|
4,440
|
|
|
|
|
|
|
|
|
|
|
|
N/A
|
|
Risk management activities
|
|
|
418
|
|
|
|
|
|
|
|
418
|
|
|
|
418
|
|
|
|
|
|
Contract amortization
|
|
|
(179
|
)
|
|
|
(258
|
)
|
|
|
79
|
|
|
|
278
|
|
|
|
(72
|
)
|
Thermal revenue
|
|
|
100
|
|
|
|
|
|
|
|
100
|
|
|
|
114
|
|
|
|
(12
|
)
|
Other revenues
|
|
|
112
|
|
|
|
|
|
|
|
112
|
|
|
|
197
|
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
8,952
|
|
|
|
4,182
|
|
|
|
4,770
|
|
|
|
6,885
|
|
|
|
(31
|
)
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of sales
|
|
|
4,524
|
|
|
|
3,003
|
|
|
|
1,521
|
|
|
|
2,641
|
|
|
|
(42
|
)
|
Risk management activities
|
|
|
(338
|
)
|
|
|
(315
|
)
|
|
|
(23
|
)
|
|
|
|
|
|
|
N/A
|
|
Other operating costs
|
|
|
1,137
|
|
|
|
153
|
|
|
|
984
|
|
|
|
957
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of operations
|
|
|
5,323
|
|
|
|
2,841
|
|
|
|
2,482
|
|
|
|
3,598
|
|
|
|
(31
|
)
|
Depreciation and amortization
|
|
|
818
|
|
|
|
137
|
|
|
|
681
|
|
|
|
649
|
|
|
|
5
|
|
Selling, general and administrative
|
|
|
550
|
|
|
|
203
|
|
|
|
347
|
|
|
|
319
|
|
|
|
9
|
|
Acquisition-related transaction and integration costs
|
|
|
54
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
N/A
|
|
Development costs
|
|
|
48
|
|
|
|
|
|
|
|
48
|
|
|
|
46
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,793
|
|
|
|
3,181
|
|
|
|
3,612
|
|
|
|
4,612
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
2,159
|
|
|
$
|
1,001
|
|
|
$
|
1,158
|
|
|
$
|
2,273
|
|
|
|
(49
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Revenues
Operating revenues, excluding risk management activities,
increased $2.1 billion during the year ended
December 31, 2009, compared to the same period in 2008.
|
|
|
|
|
Retail revenue the acquisition of Reliant
Energy contributed $4.4 billion of retail revenue during
the eight months ended December 31, 2009. Retail revenue
includes Mass revenues of $2.6 billion, C&I revenues
of $1.6 billion, and supply management revenues of
$251 million.
|
|
|
|
Energy revenue decreased $1.5 billion
during the year ended December 31, 2009, compared to the
same period in 2008:
|
|
|
|
|
○
|
Texas decreased by $431 million, with
$253 million of the decrease driven by lower average
realized energy prices, $116 million of the decrease driven
by a reduction in generation, and a $62 million decrease in
margin on MWh sold from purchased energy. The average realized
energy price decreased by 9%, driven by a 45% decrease in
merchant prices, offset by a 23% increase in contract prices.
Lower merchant prices were driven by the combination of lower
gas prices in 2009 and unusually high pricing events that
occurred in 2008 that did not repeat in 2009. Generation
decreased by 4% driven by a 9% decrease in coal plant
generation. This decrease in generation was offset by a 12%
increase in gas plant generation primarily from Cedar Bayou 4
gas plant, and generation from Elbow Creek and Langford wind
farms, none of which were in operation in 2008. Coal plant
generation was adversely affected by lower energy prices driven
by a 56% decrease in average natural gas prices in combination
with increased wind generation which shifted the coal
units position in the bid stack, negatively affecting coal
plant generation.
|
80
|
|
|
|
○
|
Northeast decreased by $575 million,
with $295 million of the decrease driven by lower energy
prices and $334 million of the decrease attributable to a
reduction in generation offset by a $54 million increase
from higher net contract revenue. Merchant energy prices were
lower by an average of 40%. The lower energy prices reduced the
Companys net cost incurred to meet obligations under load
serving contracts in the PJM market. Generation decreased by
31%, with a 31% decrease in coal generation and a 31% decrease
in oil and gas generation. Weakened demand for power combined
with lower gas prices resulted in reduced merchant energy
prices. Lower merchant energy prices combined with higher costs
of production from the introduction of RGGI resulted in
increased hours where the coal plants were uneconomical to
dispatch. The decline in oil and gas generation is attributable
to fewer reliability run hours at Norwalk plant and higher
maintenance work at Arthur Kill.
|
|
|
○
|
South Central decreased by $118 million
due to a $80 million decline in contract revenue, a
$2 million decrease in merchant energy revenues and a
$36 million decrease in margin on MWh sold from purchased
energy. The contract revenue decrease was attributed to a 10%
decrease in sales volumes and a $5.15 per MWh lower average
realized price. The decline in contract energy price was driven
by a $16 million decrease in fuel cost pass-through to the
cooperatives reflecting an overall decline in natural gas
prices. Also contributing to the decline in contract revenue was
$60 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 $2 million decline in revenue.
Increased use of the regions tolled facility provided
additional energy to the merchant market.
|
|
|
○
|
Intercompany energy revenue intercompany
sales of $349 million by the Companys Texas region to
Reliant Energy were eliminated in consolidation.
|
|
|
|
|
|
Capacity revenue decreased $329 million
during the year ended December 31, 2009, compared to the
same period in 2008:
|
|
|
|
|
○
|
Texas decreased by $300 million due to a
lower proportion of baseload contracts which contain a capacity
component.
|
|
|
○
|
Northeast decreased by $8 million due to
lower capacity prices in the NYISO.
|
|
|
○
|
South Central increased by $36 million
resulting primarily from a new capacity agreement.
|
|
|
○
|
Intercompany capacity revenue intercompany
capacity revenue of $47 million by the Companys Texas
region to Reliant Energy were eliminated in consolidation.
|
|
|
|
|
|
Contract amortization revenue decreased by
$457 million in the year ended December 31, 2009, as
compared to the same period in 2008. The decrease resulted from
a reduction of $198 million in revenue from the Texas Genco
acquisition due to the lower volume of contracted energy. Also
reducing contract amortization revenue was the amortization
expense of net in-market C&I contracts related to the
Reliant Energy acquisition of $258 million.
|
|
|
|
Other revenues decreased by $85 million
driven by $51 million in lower ancillary revenue,
$51 million in lower emissions revenue, and a
$18 million decrease in fuels trading. Lower ancillary
revenue was driven by a lesser load on the power grid as opposed
to 2008 and lower ancillary prices. Lower emissions revenue was
driven by lower carbon financial instrument sales and a loss on
emission allowance sales. 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 at the time of acquisition. Other
revenue also included $3 million in intercompany ancillary
services in 2009 by the Companys Texas region and Reliant
Energy that were eliminated in consolidation.
|
Cost
of Operations
Cost of operations, excluding risk management activities,
increased $2.1 billion during the year ended
December 31, 2009, compared to the same period in 2008 and
increased as a percentage of revenues to 66% for 2009 as
compared to 56% for 2008.
81
|
|
|
|
|
Cost of sales increased $1.9 billion
during the year ended December 31, 2009, compared to the
same period in 2008, and increased as a percentage of revenues
to 53% for 2009 as compared to 41% for 2008 due to:
|
|
|
|
|
○
|
Retail Reliant Energy incurred
$3 billion of cost of energy during the eight months ended
December 31, 2009, which included $399 million of
intercompany supply costs.
|
|
|
○
|
Texas cost of energy decreased
$305 million due to lower natural gas, coal, purchased
energy and ancillary services costs.
|
|
|
|
|
|
Fuel expense Natural gas costs decreased
$281 million, reflecting a 56% decline in average natural
gas per MMBtu prices offset by a 12% increase in gas-fired
generation. Coal costs increased by $5 million driven by a
$44 million increase from higher coal prices and a
$9 million increase in higher transportation costs. These
increases were offset by a $28 million decrease from lower
coal volume resulting from reduced generation and a
$15 million loss reserve related to a coal contract dispute
in 2008.
|
|
|
|
Ancillary service expense Ancillary service
costs decreased $44 million due to a decrease in purchased
ancillary service costs incurred to meet contract obligations.
|
|
|
|
|
○
|
Northeast cost of energy decreased
$295 million due to a $187 million reduction in
natural gas and oil costs and a $129 million reduction in
coal costs.
|
|
|
|
|
|
Fuel expense Natural gas and oil costs
decreased due to 31% lower generation and 56% lower average
natural gas prices.
|
|
|
|
|
Coal costs
|
decreased primarily due to 31% lower coal generation.
|
|
|
|
|
|
RGGI expense These decreases were offset by a
$22 million increase in costs related to RGGI which became
effective in 2009.
|
|
|
|
|
○
|
South Central cost of energy decreased
$90 million due to a $58 million decrease in purchased
energy reflecting lower fuel costs associated with the
regions tolled facility and lower market energy prices, a
$15 million decrease in natural gas costs, an
$11 million decrease in coal costs, and an $8 million
decrease in transmission expense due to transmission line
outages. The decrease in natural gas cost is attributable to a
30% decrease in owned gas generation and a 54% decrease in
natural gas prices. The coal cost decreased due to a 6% decrease
in generation offset by a 1% increase in price.
|
|
|
○
|
West cost of energy decreased $6 million
due to a 29% decline in average natural gas per MMBtu prices
offset by an 8% increase in natural gas consumption and 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.
|
|
|
○
|
Intercompany cost of energy intercompany
purchases of $399 million by Reliant Energy from the
Companys Texas region were eliminated in consolidation.
|
|
|
|
|
|
Other cost of operations increased
$180 million during the year ended December 31, 2009,
compared to the same period in 2008. Reliant Energy incurred
$153 million which includes $98 million for customer
service operations and $55 million for gross receipt tax on
revenue. Further, property taxes increased by $14 million
due to reduction in eligibility related to Empire Zone tax
credits in New York. Plant maintenance expenses were relatively
flat during the period, however these expenses decreased in
Northeast region by $22 million offset by an increase of
$11 million in West region, a $6 million increase in
South Central region and a $3 million increase in Texas
region. In addition, NRG incurred a $12 million asset
write-down due to the expected cancellation of the Indian River
Unit 3 air pollution control equipment project and the
consequent write-off of previously incurred construction costs.
|
82
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 $338 million during the year ended
December 31, 2009, compared to the same period in 2008. The
breakdown of changes by region follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009
|
|
|
|
Reliant
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
Thermal
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
Net gains/(losses) on settled positions
|
|
$
|
(480
|
)
|
|
$
|
311
|
|
|
$
|
377
|
|
|
$
|
(2
|
)
|
|
$
|
(8
|
)
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
204
|
|
|
|
|
|
Mark-to-market
gains/(losses)
|
|
|
794
|
|
|
|
(110
|
)
|
|
|
(40
|
)
|
|
|
(90
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
552
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gains/(losses) included in revenues and cost of
operations
|
|
$
|
314
|
|
|
$
|
201
|
|
|
$
|
337
|
|
|
$
|
(92
|
)
|
|
$
|
(8
|
)
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The breakdown of gains and losses included in revenue and cost
of operations by region are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009
|
|
|
|
Reliant
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
Thermal
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
Net gains/(losses) on settled positions, or financial income in
revenues
|
|
$
|
|
|
|
$
|
330
|
|
|
$
|
384
|
|
|
$
|
7
|
|
|
$
|
(8
|
)
|
|
$
|
6
|
|
|
$
|
(11
|
)
|
|
$
|
708
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
results in revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
|
|
|
|
(73
|
)
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
(196)
|
|
|
|
|
|
Reversal of gain positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
|
|
|
|
(65
|
)
|
|
|
(34
|
)
|
|
|
(58
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(157)
|
|
|
|
|
|
Reversal of previously recognized unrealized gains due to the
termination of positions related to the CSRA unwind
|
|
|
|
|
|
|
(24
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(24)
|
|
|
|
|
|
Net unrealized gains/(losses) on open positions related to
economic hedges
|
|
|
1
|
|
|
|
80
|
|
|
|
50
|
|
|
|
(17
|
)
|
|
|
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
114
|
|
|
|
|
|
Net unrealized losses on open positions related to trading
activity
|
|
|
|
|
|
|
(20
|
)
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(26)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
mark-to-market
results
|
|
|
|
|
|
|
(102
|
)
|
|
|
(107
|
)
|
|
|
(78
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
(290)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gains/(losses) included in revenues
|
|
$
|
|
|
|
$
|
228
|
|
|
$
|
277
|
|
|
$
|
(71
|
)
|
|
$
|
(8
|
)
|
|
$
|
4
|
|
|
$
|
(12
|
)
|
|
$
|
418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009
|
|
|
|
Reliant
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Elimination
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
Net gains/(losses) on settled positions, or financial expense in
cost of operations
|
|
$
|
(480
|
)
|
|
$
|
(19
|
)
|
|
$
|
(7
|
)
|
|
$
|
(9
|
)
|
|
$
|
11
|
|
|
$
|
(504)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
results in cost of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized losses on settled
positions related to economic hedges
|
|
|
|
|
|
|
47
|
|
|
|
81
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009
|
|
|
657
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
657
|
|
|
|
|
|
Reversal of previously recognized unrealized losses due to the
termination of positions related to the CSRA unwind
|
|
|
104
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
104
|
|
|
|
|
|
Net unrealized gains/(losses) on open positions related to
economic hedges
|
|
|
33
|
|
|
|
(55
|
)
|
|
|
(14
|
)
|
|
|
(12
|
)
|
|
|
1
|
|
|
|
(47)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
mark-to-market
results
|
|
|
794
|
|
|
|
(8
|
)
|
|
|
67
|
|
|
|
(12
|
)
|
|
|
1
|
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gains/(losses) included in cost of
operations
|
|
$
|
314
|
|
|
$
|
(27
|
)
|
|
$
|
60
|
|
|
$
|
(21
|
)
|
|
$
|
12
|
|
|
$
|
338
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The $114 million
mark-to-market
gain in revenue related to economic hedges consisted of a
$217 million gain recognized in earnings from previously
deferred amounts in other comprehensive income, or 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, offset by a $103 million
decrease in value in forward sales of electricity and fuel
relating to economic hedges due to lower forward power and gas
prices. The $47 million mark-to-market loss in expense
related to economic hedges consisted of a $18 million
decrease in value of forward purchases of electricity and fuel
and a loss of $29 million resulting from discontinued
Normal Purchase Normal Sale, or 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.
Reliant Energys loss positions were acquired as of
May 1, 2009, and valued using forward prices on that date.
The $656 million roll-off amounts were offset by realized
losses at the settled prices and higher costs of physical power
which are reflected in revenues and cost of operations during
the same period. The $104 million gain from the reversal of
a loss was offset by a realized loss at the settled prices and
are reflected in cost of operations during the same period.
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 2009 through
2013 generation. During 2009, the settled prices of electricity
and natural gas decreased resulting in the recognition of
realized gains while forward power and gas prices decreased
resulting in the recognition of unrealized
mark-to-market
gains. During 2008, decreasing forward prices of electricity and
natural gas resulted in recognition of unrealized
mark-to-market
gains while the settled prices for power and gas increased
resulting in the recognition of realized losses.
In accordance with ASC
815-10-45-9,
the following table represents the results of the Companys
financial and physical trading of energy commodities for the
years ended December 31, 2009, and 2008. The realized
financial trading results and unrealized financial and physical
trading results are included in the risk management activities
84
above, while the realized physical trading results are included
in energy revenue. The Companys trading activities are
subject to limits in accordance with the Companys risk
management policy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
Trading gains/(losses)
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
|
|
$
|
216
|
|
|
$
|
67
|
|
|
|
|
|
Unrealized
|
|
|
(183
|
)
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading (losses)/gains
|
|
$
|
33
|
|
|
$
|
130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and Amortization
NRGs depreciation and amortization expense increased by
$169 million for the year ended December 31, 2009,
compared to the same period in 2008. Reliant Energys
depreciation and amortization expense for the eight month period
was $137 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, and the
Cedar Bayou 4 plant which came online in the second quarter 2009.
Selling,
General and Administrative Expenses
Selling, general and administrative expenses increased by
$231 million for the year ended December 31, 2009,
compared to the same period in 2008 and increased as a
percentage of revenues to 6% for 2009 from 5% for 2008. The
increase was due to:
|
|
|
|
|
Reliant Energys selling, general and administrative
expense totaled $203 million, including
$61 million of bad debt expense incurred during the eight
months ended December 31, 2009.
|
|
|
|
Wage and benefits expense increased
$19 million.
|
|
|
|
Consultant costs increased $12 million
consisting of a rise in non-recurring costs related to
Exelons exchange offer and proxy contest efforts of
$23 million offset by a decrease in other consulting costs
of $11 million.
|
Acquisition-Related
Transaction and Integration Costs
NRG incurred Reliant Energy acquisition-related transaction
costs of $23 million and integration costs of
$31 million for the year ended December 31, 2009.
Equity
in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates
decreased by $18 million for the year ended
December 31, 2009, compared to the same period in 2008.
During 2009, the Companys share in Gladstone Power Station
and MIBRAG decreased by $4 million and $16 million,
respectively. These decreases were offset by the Companys
share of NRG Saguaro, LLC earnings increasing $11 million
in 2009 as compared to 2008. In addition, there was a
$6 million decrease in Sherbinos
mark-to-market
unrealized loss as compared to 2008 as a result of a natural gas
swap executed to hedge to future power generation.
Gain
on Sale of Equity Method Investments and Other Income/(Loss),
Net
NRGs gain on sale of equity method investments was
$128 million for the year ended December 31, 2009.
Other income/(loss), net decreased by $22 million for the
year ended December 31, 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 realized loss on a forward contract for foreign
currency executed to hedge the sale proceeds from the MIBRAG
sale. In addition, interest income for 2009 was reduced by
$17 million as compared to
85
2008 due to lower interest rates. Further in 2008, a
$23 million impairment charge was incurred to restructure
distressed investments in commercial paper.
Refinancing
Expenses
In 2009, NRG incurred a $20 million expense associated with
the unwind of CSRA with Merrill Lynch. There were no such
expenses in 2008.
Interest
Expense
NRGs interest expense increased by $51 million for
the year ended December 31, 2009, compared to the same
period in 2008. This increase was primarily due to a
$32 million increase in fees incurred during the months of
May through December of 2009 on the CSRA facility, a
$34 million increase in interest expense as a result of the
2019 Senior Notes issued in June 2009, a $4 million
increase related to ineffective portion of the interest rate
cash flow hedges on the Companys Term Loan Facility and an
$8 million increase in the amortization of deferred
financing costs. These increases were offset by a
$33 million decrease in interest expense on the
Companys Term Loan Facility due to a decrease in the
outstanding notional amount and lower interest rates related to
the unhedged portion of Term Loan and fair value portion of
Senior Notes.
Income
Tax Expense
Income tax expense increased by $15 million for the year
ended December 31, 2009, compared to 2008. The effective
tax rate was 43.6% and 40.4% for the year ended
December 31, 2009, and 2008, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions
|
|
|
|
except as otherwise stated)
|
|
Income from continuing operations before income taxes
|
|
$
|
1,669
|
|
|
$
|
1,766
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
584
|
|
|
|
618
|
|
|
|
|
|
State taxes, net of federal benefit
|
|
|
23
|
|
|
|
74
|
|
|
|
|
|
Foreign operations
|
|
|
(53
|
)
|
|
|
(10
|
)
|
|
|
|
|
Subpart F taxable income
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Valuation allowance
|
|
|
119
|
|
|
|
(12
|
)
|
|
|
|
|
Expiration of capital losses
|
|
|
249
|
|
|
|
|
|
|
|
|
|
Reversal of valuation allowance on expired capital losses
|
|
|
(249
|
)
|
|
|
|
|
|
|
|
|
Change in state effective tax rate
|
|
|
(5
|
)
|
|
|
(11
|
)
|
|
|
|
|
Foreign dividends and foreign earnings
|
|
|
33
|
|
|
|
32
|
|
|
|
|
|
Non-deductible interest
|
|
|
10
|
|
|
|
12
|
|
|
|
|
|
FIN 48 interest
|
|
|
9
|
|
|
|
8
|
|
|
|
|
|
Production tax credits
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
728
|
|
|
$
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
43.6
|
%
|
|
|
40.4
|
%
|
|
|
|
|
The Companys effective tax rate differs from the
U.S. statutory rate of 35% due to:
|
|
|
|
|
Valuation Allowance The Company generated
capital losses in 2009 primarily due to the derivative contracts
that are eligible for capital treatment for tax purposes. The
valuation allowance is recorded primarily against capital loss
carryforwards. This resulted in an increase of $127 million
in income tax expense in 2009.
|
|
|
|
Tax Expense Reduction The Company recorded a
lower federal and state tax expense of $35 million
primarily due to lower pre-tax earnings.
|
|
|
|
Change in state effective tax rate The
Company decreased its estimated effective tax rate to 3% due to
increased operational activities within the state of Texas
resulting from the acquisition of Reliant Energy. This resulted
in a tax benefit of $5 million.
|
86
|
|
|
|
|
Foreign Operations The Company elected not to
permanently reinvest its earnings from foreign operations in
2008. In 2009, the Company sold its investment in the MIBRAG
facility for a book gain of $128 million and no tax gain
which resulted in minimal tax due in the local jurisdiction.
|
The effective income tax rate may vary from period to period
depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances
in accordance with ASC-740, Income Taxes, or ASC 740.
These factors and others, including the Companys history
of pre-tax earnings and losses, are taken into account in
assessing the ability to realize deferred tax assets.
Consolidated
Results of Operations
2008
compared to 2007
The following table provides selected financial information for
NRG Energy, Inc., for the years ended December 31, 2008 and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions
|
|
|
|
|
|
|
except otherwise noted)
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
4,519
|
|
|
$
|
4,265
|
|
|
|
6
|
%
|
Capacity revenue
|
|
|
1,359
|
|
|
|
1,196
|
|
|
|
14
|
|
Risk management activities
|
|
|
418
|
|
|
|
4
|
|
|
|
N/A
|
|
Contract amortization
|
|
|
278
|
|
|
|
242
|
|
|
|
15
|
|
Thermal revenue
|
|
|
114
|
|
|
|
125
|
|
|
|
(9
|
)
|
Other revenues
|
|
|
197
|
|
|
|
157
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
6,885
|
|
|
|
5,989
|
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,598
|
|
|
|
3,378
|
|
|
|
7
|
|
Depreciation and amortization
|
|
|
649
|
|
|
|
658
|
|
|
|
(1
|
)
|
General and administrative
|
|
|
319
|
|
|
|
309
|
|
|
|
3
|
|
Development costs
|
|
|
46
|
|
|
|
101
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,612
|
|
|
|
4,446
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on sale of assets
|
|
|
|
|
|
|
17
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
2,273
|
|
|
|
1,560
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
59
|
|
|
|
54
|
|
|
|
9
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
(100
|
)
|
Other income, net
|
|
|
17
|
|
|
|
55
|
|
|
|
(69
|
)
|
Refinancing expenses
|
|
|
|
|
|
|
(35
|
)
|
|
|
(100
|
)
|
Interest expense
|
|
|
(583
|
)
|
|
|
(702
|
)
|
|
|
(17
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(507
|
)
|
|
|
(627
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations before income tax
expense
|
|
|
1,766
|
|
|
|
933
|
|
|
|
89
|
|
Income tax expense
|
|
|
713
|
|
|
|
377
|
|
|
|
89
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from Continuing Operations
|
|
|
1,053
|
|
|
|
556
|
|
|
|
89
|
|
Income from discontinued operations, net of income tax expense
|
|
|
172
|
|
|
|
17
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
1,225
|
|
|
|
573
|
|
|
|
114
|
|
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
1,225
|
|
|
$
|
573
|
|
|
|
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub ($/MMbtu)
|
|
|
8.85
|
|
|
|
6.94
|
|
|
|
28
|
%
|
N/A Not applicable
87
Operating
Revenues
Operating revenues increased by $896 million for the year
ended December 31, 2008, compared to 2007. This was due to:
|
|
|
|
|
Energy revenue increased $254 million
during the year ended December 31, 2008, compared to the
same period in 2007:
|
|
|
|
|
○
|
Texas increased $172 million, with
$430 million of this increase driven by higher prices,
offset by $42 million reduced generation and a
$216 million decrease on net margin on MWh sold from market
purchases. The price variance was attributable to a more
favorable mix of merchant versus contract sales, as well as a
28% increase in merchant prices partially offset by a 14%
decrease in contract energy prices. The 839 thousand MWh or 2%
reduction in generation was comprised of a 3% reduction from
nuclear plant generation, a 14% reduction from gas plant
generation, offset by a 1% increase in coal plant generation.
The reduction in gas plant generation was attributable to the
effects of hurricane Ike in September 2008.
|
|
|
○
|
Northeast decreased $40 million, with
$66 million reduced generation, a $38 million decrease
from lower net contract revenue offset by a $64 million
increase driven by higher energy prices. The decline due to
generation was driven by a net 6% reduction in the regions
generation, due to a decrease in oil-fired generation as a
result of higher average oil prices as well as decrease in
gas-fired generation related to a cooler summer in 2008 compared
to 2007. The increase due to energy prices reflects an average
6% rise in merchant energy prices offset by lower contract
revenue, driven by higher costs required to service the PJM
contracts, as a result of the increase in market energy prices.
|
|
|
○
|
South Central increased $74 million,
attributable to a $41 million increase caused by higher
energy prices and a $33 million increase on net margin on
MWh sold from market purchases. The growth in merchant energy
revenues reflected 577 thousand more merchant MWh sold, as a
decrease in contract load MWh allowed more sales to the merchant
market at higher prices.
|
|
|
○
|
West increased $35 million due to the
dispatch of the El Segundo plant outside of the tolling
agreement in 2008. In 2007, no such dispatch occurred.
|
|
|
|
|
|
Capacity revenue increased $163 million
during the year ended December 31, 2008, compared to the
same period in 2007:
|
|
|
|
|
○
|
Texas increased $130 million due to a
greater proportion of base-load contracts, which contain a
capacity component.
|
|
|
○
|
Northeast increased $13 million
reflecting $31 million higher capacity revenues in the PJM
and NEPOOL markets offset by a $18 million reduction in
capacity revenue in NYISO.
|
|
|
○
|
South Central increased $12 million due
to a $10 million higher capacity payment from the
regions cooperative customers and an $8 million rise
in RPM capacity payments from the PJM market. These increases
were offset by a $6 million reduction related to lower
contract volume to other customers.
|
|
|
○
|
West increased $3 million due to a
tolling arrangement at Long Beach plant offset by the reduction
of revenue from the El Segundo tolling arrangement.
|
|
|
|
|
|
Contract amortization revenue increased
$36 million during the year ended December 31, 2008,
compared to the same period in 2007 due to the volume of
contracted energy affected by a greater spread between contract
prices and market prices used in the Texas Genco purchase
accounting.
|
|
|
|
Other revenues increased by $40 million
during the year ended December 31, 2008, compared to the
same period in 2007. The increases arose from greater ancillary
services revenue of $28 million and increased activity in
the trading of emission allowances and carbon financial
instruments of $21 million. These increases were offset by
$14 million in lower gas and coal trading activities.
|
88
Cost
of Operations
Cost of operations excluding risk management activities,
increased $220 million during the year ended
December 31, 2008, compared to the same period in 2007 and
remained flat as a percentage of revenues at 56% for 2008 and
2007.
|
|
|
|
|
Cost of energy increased $213 million
during the year ended December 31, 2008, compared to the
same period in 2007 and remained flat as a percentage of
revenues at 41% for 2008 and 2007. This increase was due to :
|
|
|
|
|
○
|
Texas Cost of energy increased
$59 million due to a net increase in fuel expense and
ancillary service costs offset by reductions in nuclear fuel
expenses, purchased power expense and amortization of contracts
cost.
|
|
|
|
|
|
Fuel expense Natural gas costs rose
$99 million due to an increase of 28% in average natural
gas prices, offset by a 14% decrease in gas-fired generation. In
addition, coal costs increased by $44 million as a result
of higher coal prices and the settlement payment related to a
coal contract dispute. These increases were offset by a decrease
of $19 million in nuclear fuel expense as amortization of
nuclear fuel inventory established under Texas Genco purchase
accounting ended in early 2008.
|
|
|
|
Purchased energy Purchased energy expense
decreased $26 million as a result of lower forced outage
rates at the regions base-load plants.
|
|
|
|
Ancillary service expense Ancillary services
and other costs increased by $14 million as a result of
higher ERCOT ISO fees offset by reduced purchased ancillary
services costs.
|
|
|
|
Fuel contract amortization Amortized contract
costs decreased by $59 million due to a $36 million
decrease in the amortization of water supply contracts which
ended in 2007. In addition, the amortization of coal contracts
decreased by a net $22 million as a result of a reduction
in expense related to
in-the-money
coal contract amortization. These contracts were established
under Texas Genco purchase accounting.
|
|
|
|
|
○
|
Northeast Cost of energy increased
$54 million due to higher fuel costs. Coal costs increased
$61 million due to higher coal prices and fuel
transportation surcharges. Natural gas costs rose
$22 million as a result of 32% higher average natural gas
prices, despite 12% lower generation. These increases were
offset by a $27 million reduction in oil costs as a result
of 55% lower oil-fired generation.
|
|
|
○
|
South Central Cost of energy increased
$56 million due to higher fuel costs and increased
purchased energy expense.
|
|
|
|
|
|
Fuel expense Coal costs increased
$16 million resulting from an increase in coal consumption
and higher fuel transportation surcharges; natural gas costs
rose by $14 million as the regions peaker plants ran
extensively to support transmission system stability after
hurricane Gustav.
|
|
|
|
Purchased energy Higher purchased energy
expenses of $16 million reflected higher natural gas costs
for tolling contracts.
|
|
|
|
Transmission costs increased by
$9 million due to additional
point-to-point
transmission costs driven by an increase in merchant energy
sales.
|
|
|
|
|
○
|
West Cost of energy increased
$30 million due to the dispatch of the El Segundo plant
outside of the tolling agreement in 2008. In 2007, no such
dispatch occurred.
|
|
|
|
|
|
Other operating costs increased
$7 million during the year ended December 31, 2008,
compared to the same period in 2007. This increase was due to:
|
|
|
|
|
○
|
Texas increased $30 million due to a
second planned outage at STP and the acceleration of planned
outages at the base-load plants.
|
89
|
|
|
|
○
|
Northeast decreased $3 million due to
$18 million in lower operating and maintenance expenses
resulting from less outage work at the Norwalk plants and Indian
River plants. This decrease was offset by a $16 million
increase in utilities cost. The 2007 utilities cost included a
benefit of $19 million due to a lower than planned
settlement of the station service agreement with CL&P.
|
|
|
○
|
South Central decreased by $10 million
due to reduction in major maintenance expense. The 2007 expense
included more extensive outage work that was performed at the
Big Cajun II plant.
|
|
|
○
|
West decreased by $4 million due to a
$3 million reduction in lease expenses and an environmental
liability of $2 million which was recognized in 2007
related to the El Segundo plant.
|
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. Such revenues increased by
$414 million during the year ended December 31, 2008,
compared to the same period in 2007. The breakdown of changes by
region was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
Thermal
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
Net (losses)/gains on settled positions, or financial income in
revenues
|
|
$
|
(95
|
)
|
|
$
|
3
|
|
|
$
|
(16
|
)
|
|
$
|
1
|
|
|
$
|
(107
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mark-to-market
results
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
|
(25
|
)
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
(38
|
)
|
|
|
|
|
Reversal of previously recognized unrealized losses/(gains) on
settled positions related to trading activity
|
|
|
1
|
|
|
|
(14
|
)
|
|
|
(19
|
)
|
|
|
|
|
|
|
(32
|
)
|
|
|
|
|
Net unrealized gains on open positions related to economic hedges
|
|
|
400
|
|
|
|
96
|
|
|
|
|
|
|
|
4
|
|
|
|
500
|
|
|
|
|
|
Net unrealized gains on open positions related to trading
activity
|
|
|
37
|
|
|
|
13
|
|
|
|
45
|
|
|
|
|
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
mark-to-market
results
|
|
|
413
|
|
|
|
82
|
|
|
|
26
|
|
|
|
4
|
|
|
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gain
|
|
$
|
318
|
|
|
$
|
85
|
|
|
$
|
10
|
|
|
$
|
5
|
|
|
$
|
418
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total derivative gain included in revenues
|
|
|
318
|
|
|
|
85
|
|
|
|
10
|
|
|
|
5
|
|
|
|
418
|
|
|
|
|
|
Total derivative gain included in cost of operations
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRGs 2008 gain is comprised of $525 million of
mark-to-market
gains and a $107 million in settled losses, or financial
revenue. Of the $525 million of
mark-to-market
gains, the $38 million loss represents the reversal of
mark-to-market
gains recognized on economic hedges and the $32 million
loss represents the reversal of
mark-to-market
gains recognized on trading activity. Both of these losses
ultimately settled as financial or physical revenues during
2008. The $500 million gain from economic hedge positions
included a $524 million increase in value of forward sales
of electricity as the result of the reduction in forward power
and gas prices at the close of the year ended December 31,
2008. These hedges are considered effective economic hedges that
do not receive cash flow hedge accounting treatment. In addition
there was a $24 million loss primarily from hedge
accounting ineffectiveness related to gas trades in the Texas
region which was driven by decreasing forward gas prices while
forward power prices declined at a slower pace. NRG also
recognized a $95 million unrealized gain associated with
the companys trading activity. This gain was primarily due
to declining forward electricity and fuel prices.
Since these hedging activities are intended to mitigate the risk
of commodity price movements on revenues the changes in such
results should not be viewed in isolation, but rather should be
taken together with the effects of pricing and cost changes on
energy revenues. During and throughout 2008, NRG hedged a
portion of the Companys 2008 through 2013 generation.
Since that time, the settled and forward prices of electricity
and natural gas have decreased, resulting in the recognition of
unrealized
mark-to-market
forward gains.
90
In accordance with ASC
815-10-45-9,
the following table represents the results of the Companys
financial and physical trading of energy commodities for the
years ended December 31, 2008, and 2007. The realized
financial trading results and unrealized financial and physical
trading results are included in the risk management activities
above, while the realized physical trading results are included
in energy revenue. The Companys trading activities are
subject to limits in accordance with the Companys risk
management policy.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions)
|
|
|
Trading gains
|
|
|
|
|
|
|
|
|
|
|
|
|
Realized
|
|
$
|
67
|
|
|
$
|
396
|
|
|
|
|
|
Unrealized
|
|
|
63
|
|
|
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total trading gains
|
|
$
|
130
|
|
|
$
|
414
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General
and Administrative
NRGs G&A costs for the year ended December 31,
2008, increased by $10 million compared to 2007, and as a
percentage of revenues was 5% in both 2008 and 2007.
|
|
|
|
|
Wage and benefit costs increased
$19 million attributable to higher wages and related
benefits cost increases.
|
|
|
|
Consultant cost increased by $3 million
resulting from $8 million spent on Exelons exchange
offer offset by a $5 million reduction in information
technology consultants.
|
|
|
|
Franchise tax The Companys Louisiana
state franchise tax decreased by approximately $4 million.
Prior year franchise tax was assessed based on the
Companys total debt and equity that increased
significantly following the acquisition of Texas Genco.
|
|
|
|
Insurance cost decreased by $4 million
due to favorable rates.
|
Development
Costs
NRGs development costs for the year ended
December 31, 2008 decreased by $55 million compared to
2007. These costs were due to the Companys
RepoweringNRG projects:
|
|
|
|
|
Texas STP Units 3 and 4 projects No
development expense was reflected in results of operations for
2008 as NRG began to capitalize STP Units 3 and 4 development
costs incurred after January 1, 2008, following the
NRCs docketing of the Companys COLA in late 2007.
The Company recorded $52 million in development expenses
during 2007.
|
|
|
|
Wind projects The Company incurred
$21 million in costs related to wind development which is a
$4 million decrease from the same period in 2007.
|
|
|
|
Other projects The Company incurred
$25 million in development costs related to other domestic
RepoweringNRG projects in 2008, which decreased
$7 million from the same period in 2007 as a result of the
capitalization of costs to develop the El Segundo Energy Center
in 2008.
|
Gain
on Sale of Assets
The Company reported no gains on sales of assets for 2008. For
2007, NRGs gain on the sale of assets was
$17 million. On January 3, 2007, NRG completed the
sale of the Companys Red Bluff and Chowchilla II
power plants resulting in a pre-tax gain of $18 million.
Equity
in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates for
the year ended December 31, 2008, increased by
$5 million compared to 2007. This increase was due to a
$9 million
mark-to-market
unrealized gain on a forward contract for a natural gas swap
executed to hedge the future power generation of Sherbino I Wind
Farm LLC, offset by a $4 million reduction in earnings from
international equity investments.
91
Other
Income, Net
NRGs other income, net decreased by $38 million for
2008 compared to the same period in 2007. The Company recorded a
further $23 million impairment charge in 2008 to
restructure distressed investments in commercial paper, for
which an $11 million impairment charge was taken in the
fourth quarter of 2007. The impairment charge resulted from a
change in the Companys fair value assessment as a result
of a public auction of the assets in the structured investment
vehicle holding the investments; this auction was the first
observable market participation since the structured investment
vehicle became illiquid in 2007. This 2008 impairment charge,
along with cash receipts of $2 million, reduced the
carrying value of the commercial paper to $7 million. In
addition, the 2008 results reflect reduced interest income of
$25 million from lower market interest rates on cash
deposits.
Interest
Expense
NRGs interest expense decreased by $119 million for
2008 compared to the same period in 2007. This decrease was due
to interest savings on $531 million debt repayments
accompanied by a reduction on the variable interest rates on
long-term debt. The debt repayments included a $300 million
prepayment in December 2007 and an additional payment of
$143 million in March 2008 of the Term Loan Facility in
connection with the mandatory offer under the Senior Credit
Facility. Interest capitalized on RepoweringNRG projects
under construction also contributed to this decrease in interest
expense.
NRG has interest rate swaps with the objective of fixing the
interest rate on a portion of NRGs Senior Credit Facility.
These swaps were designated as cash flow hedges under ASC 815,
and the impact associated with ineffectiveness was immaterial to
NRG financial results. For the year ended December 31,
2008, NRG had a deferred loss of $90 million in other
comprehensive income compared to a deferred loss of
$31 million in 2007.
Refinancing
Expense
There was no refinancing activity in 2008. In 2007, NRG
completed a $4.4 billion refinancing of the Companys
Senior Credit Facility, resulting in a charge of
$35 million from the write-off of deferred financing costs
as the lenders for 45% of the Term Loan Facility either exited
the financing or reduced their holdings and were replaced by
other institutions.
Income
Tax Expense
Income tax expense increased by $336 million for the year
ended December 31, 2008, compared to 2007. The effective
tax rate was 40.4% for the years ended December 31, 2008,
and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions
|
|
|
|
except as otherwise stated)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,766
|
|
|
$
|
933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
618
|
|
|
|
327
|
|
|
|
|
|
State taxes, net of federal benefit
|
|
|
74
|
|
|
|
46
|
|
|
|
|
|
Foreign operations
|
|
|
(10
|
)
|
|
|
(13
|
)
|
|
|
|
|
Subpart F taxable income
|
|
|
2
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(12
|
)
|
|
|
6
|
|
|
|
|
|
Change in state effective tax rate
|
|
|
(11
|
)
|
|
|
|
|
|
|
|
|
Change in local German effective tax rates
|
|
|
|
|
|
|
(29
|
)
|
|
|
|
|
Foreign dividends and foreign earnings
|
|
|
32
|
|
|
|
26
|
|
|
|
|
|
Non-deductible interest
|
|
|
12
|
|
|
|
10
|
|
|
|
|
|
FIN 48 interest
|
|
|
8
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
713
|
|
|
$
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
40.4
|
%
|
|
|
40.4
|
%
|
|
|
|
|
92
The increase in income tax expense was primarily due to:
|
|
|
|
|
Increase in income pre-tax income
increased by $833 million, with a corresponding increase of
$336 million in income tax expense.
|
|
|
|
Permanent differences The Companys
effective tax rate differs from the U.S. statutory rate of
35% due to:
|
|
|
|
|
○
|
Taxable dividends from foreign subsidiaries
due to the provision of deferred taxes in 2008
on foreign income no longer expected to be permanently
reinvested overseas offset by decreased dividends from foreign
operations in the current year, tax expense increased by
approximately $6 million as compared to 2007.
|
|
|
○
|
Non-deductible interest resulted in an
additional income tax expense of $2 million in 2008 as
compared to the same period in 2007.
|
|
|
○
|
Change in German tax rate as a result of
revaluing the Companys deferred tax assets, income tax
expense benefited by $29 million in 2007, with no
comparable benefit in 2008.
|
|
|
○
|
Valuation Allowance The Company generated
capital gains in 2008 primarily due to the sale of ITISA and
derivative contracts that are eligible for capital treatment for
tax purposes. These gains enabled NRG to reduce the
Companys valuation allowance against capital loss
carryforwards. In addition, applicable changes to the state and
local effective tax rate are captured in the current period.
This resulted in a decrease of $18 million income tax
expense in 2008 as compared to 2007.
|
|
|
○
|
Change in state effective tax rate The
Company reduced its domestic state and local deferred income tax
rate from 7% to 6% in the current period.
|
The effective income tax rate may vary from period to period
depending on, among other factors, the geographic and business
mix of earnings and losses and changes in valuation allowances
in accordance with ASC 740. These factors and others, including
the Companys history of pre-tax earnings and losses, are
taken into account in assessing the ability to realize deferred
tax assets.
Income
from Discontinued Operations, Net of Income Tax
Expense
Discontinued operations included ITISA results for 2008 and the
same period in 2007. For 2008 and the same period in 2007, NRG
recorded income from discontinued operations, net of income tax
expense, of $172 million and $17 million,
respectively. NRG closed the sale of ITISA during the second
quarter 2008 and recognized an after-tax gain of
$164 million.
93
Results
of Operations for Reliant Energy
Selected
Income Statement Data
|
|
|
|
|
|
|
Period Ended
|
|
|
|
December 31,
|
|
|
|
2009(a)
|
|
|
|
(In millions except
|
|
|
|
otherwise noted)
|
|
|
Operating Revenues
|
|
|
|
|
Mass revenues
|
|
$
|
2,597
|
|
Commercial and industrial revenues
|
|
|
1,592
|
|
Supply management revenues
|
|
|
251
|
|
Contract amortization
|
|
|
(258
|
)
|
|
|
|
|
|
Total operating revenues
|
|
|
4,182
|
|
Operating Costs and Expenses
|
|
|
|
|
Cost of energy (including risk management activities)
|
|
|
2,688
|
|
Other operating expenses
|
|
|
356
|
|
Depreciation and amortization
|
|
|
137
|
|
|
|
|
|
|
Operating Income
|
|
$
|
1,001
|
|
|
|
|
|
|
Electricity sales volume-GWh (in thousands):
|
|
|
|
|
Mass
|
|
|
17,152
|
|
Commercial and
Industrial
(b)
|
|
|
20,915
|
|
Business Metrics
|
|
|
|
|
Weighted average retail customers count (in thousands, metered
locations)
|
|
|
|
|
Mass
|
|
|
1,566
|
|
Commercial and
Industrial
(b)
|
|
|
68
|
|
Retail customers count (in thousands, metered locations)
|
|
|
|
|
Mass
|
|
|
1,531
|
|
Commercial and
Industrial
(b)
|
|
|
66
|
|
Cooling Degree Days, or
CDDs (c)
|
|
|
2,972
|
|
CDDs
30-year
average
|
|
|
2,713
|
|
Heating Degree Days, or
HDDs (c)
|
|
|
699
|
|
HDDs
30-year
average
|
|
|
644
|
|
|
|
|
(a)
|
|
For the period May 1, 2009, to
December 31, 2009.
|
(b)
|
|
Includes customers of the Texas
General Land Office for whom the Company provides services.
|
(c)
|
|
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.
|
94
Year
to date results
Operating
Income
Operating income for the period ended December 31, 2009,
was $1,001 million, which consisted of the following:
|
|
|
|
|
|
|
Period Ended
|
|
|
|
December 31, 2009
|
|
|
Reliant Energy Operating Income:
|
|
|
|
|
Mass revenues
|
|
$
|
2,597
|
|
Commercial and industrial revenues
|
|
|
1,592
|
|
Supply management revenues
|
|
|
251
|
|
|
|
|
|
|
Total retail
revenues
(a)
|
|
|
4,440
|
|
|
|
|
|
|
Retail cost of
sales (a)
|
|
|
3,531
|
|
|
|
|
|
|
Total retail gross margin
|
|
|
909
|
|
Unrealized gains on energy derivatives
|
|
|
794
|
|
Contract amortization, net
|
|
|
(209
|
)
|
Other operating expenses
|
|
|
(356
|
)
|
Depreciation and amortization
|
|
|
(137
|
)
|
|
|
|
|
|
Operating Income
|
|
$
|
1,001
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Amounts exclude unrealized
gains/(losses) on energy derivatives and contract amortization.
|
|
|
|
|
|
Gross margin Reliant Energys gross
margin totaled $909 million, which was driven by strong
margins in the Mass customer class and expanding margins in the
C&I customer class. Volumes were higher due to greater
customer usage driven by favorable weather as compared to the
30 year CDD and HDD averages, although partially offset by
a decrease in number of customers during the period ended
December 31, 2009. The Company acquired Reliant Energy
customers on prices more consistent with 2008 costs of natural
gas. Reliant Energy announced and enacted price reductions
effective June 1 and July 1, 2009, that cumulatively
lowered prices up to 20% for certain Mass customer classes.
These reduced prices, relative to lower short-term supply costs,
delivered strong margins. Competition, price reductions, and
supply costs based on forward market prices, will likely drive
lower margins in the future.
|
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 supply costs continue to
remain low, the Company expects competitive retail prices to
continue their decline and to place pressure on unit margins.
Additionally, the Companys customer counts have declined
approximately by 6% since May 1, 2009.
Operating
Revenues
Total operating revenues, including risk management activities,
for the period ended December 31, 2009, were
$4.2 billion and consisted of the following:
Mass revenues
totaled $2.6 billion 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 the current costs of natural
gas. These acquired revenue rates were reduced by Reliant
Energys announced and enacted price reductions effective
June 1 and July 1, 2009 of up to 20% for certain Mass
customer classes. Also, favorable weather, as compared to the
30-year CDD
and HDD averages, caused an increase in customer usage. The
higher prices, along with higher usage, were accompanied by a 5%
decrease in the number of customers since May 1, 2009.
Commercial and industrial
revenue C&I revenues for the period ended
December 31, 2009, totaled $1.6 billion on volume
sales of approximately 20,915 GWh. Variable rate contracts tied
to the market price of natural gas accounted for approximately
73% of the contracted volumes as of December 31, 2009.
95
Contract amortization
reduced operating revenues by $258 million
resulting from net in-market C&I contracts acquired in the
Reliant Energy acquisition. These contracts will be amortized
over the life of the contracts with the longest contract term
being approximately four years.
Supply management
revenues totaled $251 million from the sale
of excess supply into various markets in Texas.
Cost
of Energy
Cost of energy for the period ended December 31, 2009, was
$2.7 billion and consisted of the following:
Supply costs
totaled $2 billion. The market cost of
energy is significantly down due to the decline in natural gas
prices since the same period last year. Also, favorable weather
for the period, as compared to the
30-year CDD
and HDD averages, caused an increase in purchased supply volumes
at a relatively low cost.
Risk management activities
Unrealized gains of $794 million on
economic hedges relate to supply contracts that were recognized
for the period ended December 2009, including $657 million
of gains representing a roll-off of loss positions acquired at
May 1, 2009, valued at forward prices on that date,
reversal of losses of $104 million due to the termination
of positions related to the CSRA unwind, and $33 million of
gains that represent
mark-to-market
changes in the forward value of purchased electricity and gas.
The $657 million gain from the roll-off of loss positions
was offset by realized losses at the settled prices and higher
cost of physical power which are reflected in the cost of
operations during the same period. The $104 million gain
from reversal of losses was offset by realized losses at the
settled prices and is reflected in cost of operations during the
same period.
Transmission and distribution
charges totaled $964 million for the cost
to transport the power from the generation sources to the
end-use customers.
Financial settlements
totaled $480 million resulting from
financial settlement of energy related derivatives.
Contract amortization
reduced cost of energy by $49 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 with
the longest contract term being approximately seven years.
Other
Operating Expenses
Other operating expenses for the period ended December 31,
2009, were $356 million, or 9% of Reliant Energys
total operating revenues. Other operating expenses consisted of
the following:
Operations and maintenance
expenses totaled $98 million. Theses
expenses primarily consisted of the labor and external costs
associated with customer activities, including the call center,
billing, remittance processing and credit and collections, as
well as the information technology costs associated with those
activities.
Selling, general and
administrative expenses totaled
$142 million. These expenses 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 $55 million or 1.3% of Mass and
C&I revenues.
Bad debt expense
totaled $61 million or 1.5% of Mass and
C&I revenues which was driven by higher summer bills due to
warmer weather and economic factors including unemployment in
Dallas and Houston which is approaching national averages.
96
Results
of Operations for Wholesale Power Generation Regions
Texas
Region
2009
compared to 2008
The following table provides selected financial information for
the Texas region for the years ended December 31, 2009, and
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
2,439
|
|
|
$
|
2,870
|
|
|
|
(15
|
)%
|
|
|
|
|
Capacity revenue
|
|
|
193
|
|
|
|
493
|
|
|
|
(61
|
)
|
|
|
|
|
Risk management activities
|
|
|
229
|
|
|
|
318
|
|
|
|
(28
|
)
|
|
|
|
|
Contract amortization
|
|
|
57
|
|
|
|
255
|
|
|
|
(78
|
)
|
|
|
|
|
Other revenues
|
|
|
28
|
|
|
|
90
|
|
|
|
(69
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
2,946
|
|
|
|
4,026
|
|
|
|
(27
|
)
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
963
|
|
|
|
1,240
|
|
|
|
(22
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
472
|
|
|
|
451
|
|
|
|
5
|
|
|
|
|
|
Other operating expenses
|
|
|
671
|
|
|
|
650
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
840
|
|
|
$
|
1,685
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
47,259
|
|
|
|
47,806
|
|
|
|
(1
|
)
|
|
|
|
|
MWh generated (in thousands)
|
|
|
44,993
|
|
|
|
46,937
|
|
|
|
(4
|
)
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
35.43
|
|
|
$
|
86.23
|
|
|
|
(59
|
)
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
2,881
|
|
|
|
2,719
|
|
|
|
6
|
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
2,647
|
|
|
|
2,647
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
1,890
|
|
|
|
1,961
|
|
|
|
(4
|
)%
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
1,997
|
|
|
|
2,007
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income decreased by $845 million for the year
ended December 31, 2009, compared to the same period in
2008, primarily due to:
Operating revenues
decreased by $1.1 billion due to
unfavorable energy and capacity revenue offset by a favorable
impact of risk management activities.
Cost of energy
decreased by $277 million driven by lower
natural gas costs.
Operating
Revenues
Total operating revenues decreased by $1.1 billion during
the year ended December 31, 2009, compared to the same
period in 2008, due to:
|
|
|
|
|
Energy revenue decreased $431 million
due to:
|
|
|
|
|
○
|
Energy prices decreased by $253 million
as the average realized merchant price was lower in 2009 due to
the combination of lower gas prices and unusually high pricing
events that occurred in 2008 but did not repeat in 2009. Higher
MWh sold under merchant market was offset by lower merchant
prices. The average realized energy price decreased by 9%,
driven by a 45% decrease in merchant prices offset by a 23%
increase in contract prices.
|
97
|
|
|
|
○
|
Generation decreased by 4% resulting in a
$116 million decrease in sales volume. This decrease was
driven by a 9% decrease in coal plant generation. This decrease
was offset by a 12% increase in gas plant generation, and
generation from the recently constructed Cedar Bayou 4 gas
plant, the Elbow Creek wind farm, and the Langford wind farm
which began commercial operations in June 2009, December 2008
and December 2009, respectively. Coal plant generation was
adversely affected by lower energy prices driven by a 56%
decrease in average natural gas prices in combination with
increased wind generation in the region.
|
|
|
○
|
Margin on MWH sold from market purchases
decreased by $62 million.
|
Capacity revenue
decreased by $300 million due to a lower
proportion of baseload contracts which contain a capacity
component.
Risk management
activities decreased by $89 million
reflecting the difference between gains of $228 million
recorded for the year ended December 31, 2009, compared to
gains of $318 million during the same period in 2008. The
$89 million decrease included $102 million of
unrealized
mark-to-market
losses and $330 million in gains on settled transactions,
or financial income, compared to $413 million in unrealized
mark-to-market
gains and $95 million in financial losses during the same
period in 2008. For further discussion of the Companys
risk management activities, see Consolidated Results of
Operations.
Contract amortization revenue
resulting from the Texas Genco acquisition
decreased by $198 million due to the reduced volume of
contracted energy in 2009 as compared to 2008.
Other revenues
decreased by $62 million primarily due to
lower ancillary services revenue of $47 million provided to
the market, and lower emissions credit revenue of
$11 million.
Cost
of Energy
Cost of energy decreased by $277 million during the year
ended December 31, 2009, compared to the same period in
2008, due to:
Natural gas costs
decreased by $281 million due to a 56%
decline in average natural gas prices offset by a 12% increase
in gas-fired generation.
Ancillary service costs
decreased by $44 million due to a decrease
in purchased ancillary services costs incurred to meet contract
obligations.
These decreases were offset by:
Fuel risk management activities
losses of $27 million were recorded for the
year ended December 31, 2009. In the first quarter 2009,
all NPNS coal contracts were discontinued and reclassified into
mark-to-market
accounting. The $27 million loss included $8 million
of unrealized
mark-to-market
losses, largely associated with forward coal positions and
$19 million in losses on settled transactions, or financial
cost of energy. For further discussion of the Companys
risk management activities, see Consolidated Results of
Operations.
Coal costs
increased by $5 million driven by a $44 million
increase in coal prices, offset by a $28 million decrease
in coal volume. Additionally, an increase in higher
transportation costs of $9 million was offset by a
$15 million loss reserve related to a coal contract dispute
in the first quarter of 2008, combined with a decrease of
$3 million due to lower lignite royalties.
Cost Contract
Amortization increased $19 million driven
primarily by the reduction in amortization for
out-of-the
money coal contracts assumed in the acquisition of Texas Genco
as coal is delivered under that contract.
Other
Operating Expenses
Other operating expenses increased by $21 million during
the year ended December 31, 2009, compared to the same
period in 2008, driven by an increase of $14 million in
general and administrative expense due to higher corporate
allocations as a result of the change in method in allocating
corporate costs as described in Item 14
Note 18, Segment Reporting, to the Consolidated
Financial Statements. In addition, there was an increase of
98
$3 million for operations and maintenance costs, as well as
an increase of $3 million in property and other taxes due
to the recently constructed Cedar Bayou 4 and Elbow Creek
facilities.
Depreciation
and Amortization
Depreciation and amortization expense increased by
$21 million for the year ended December 31, 2009,
compared to the same period in 2008. This increase was the
result of Cedar Bayou 4 and Elbow Creek reaching commercial
operations in June 2009 and December 2008, respectively.
2008
compared to 2007
The following table provides selected financial information for
the Texas region for the years ended December 31, 2008 and
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
2,870
|
|
|
$
|
2,698
|
|
|
|
6
|
%
|
Capacity revenue
|
|
|
493
|
|
|
|
363
|
|
|
|
36
|
|
Risk management activities
|
|
|
318
|
|
|
|
(33
|
)
|
|
|
N/A
|
|
Contract amortization
|
|
|
255
|
|
|
|
219
|
|
|
|
16
|
|
Other revenues
|
|
|
90
|
|
|
|
40
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
4,026
|
|
|
|
3,287
|
|
|
|
22
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
1,240
|
|
|
|
1,181
|
|
|
|
5
|
|
Depreciation and amortization
|
|
|
451
|
|
|
|
469
|
|
|
|
(4
|
)
|
Other operating expenses
|
|
|
650
|
|
|
|
668
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
1,685
|
|
|
$
|
969
|
|
|
|
74
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
47,806
|
|
|
|
49,220
|
|
|
|
(3
|
)
|
MWh generated (in thousands)
|
|
|
46,937
|
|
|
|
47,779
|
|
|
|
(2
|
)
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
86.23
|
|
|
$
|
60.98
|
|
|
|
41
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
2,719
|
|
|
|
2,707
|
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
2,647
|
|
|
|
2,647
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
1,961
|
|
|
|
1,949
|
|
|
|
1
|
|
HDDs
30-year
rolling average
|
|
|
2,007
|
|
|
|
1,997
|
|
|
|
1
|
%
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income increased by $716 million for the year
ended December 31, 2008, compared to the same period in
2007, primarily due to:
Operating revenues
increased by $739 million due to favorable
risk management activities, energy and capacity revenues.
Cost of energy
increased by $59 million reflecting the
effects of increased natural gas and coal prices.
Operating
Revenues
Total operating revenues increased by $739 million during
the year ended December 31, 2008, compared to 2007 due to
the following:
Risk management activities
gains of $318 million were recognized for
the year ended December 31, 2008, compared to a
$33 million loss in the same period in 2007. The
$318 million included $413 million of unrealized
mark-to-market
gains and $95 million in settled losses, or financial
99
revenue. The $413 million was the net effect of a
$400 million gain from economic hedge positions and a
$25 million loss on reversals of
mark-to-market
gains on economic hedges. In addition, there were
$37 million in unrealized
mark-to-market
gains on trading transactions combined with a $1 million
gain on reversals of
mark-to-market
losses on trading activity. The $400 million gain from
economic hedges incorporated $424 million in unrealized
gains in the value of forward sales of electricity and fuel
driven by lower power and natural gas prices. These hedges were
considered effective economic hedges that do not receive cash
flow hedge accounting treatment. The remaining $24 million
in losses were from hedge ineffectiveness which was driven by
decreasing gas prices while power prices decreased at a slower
pace.
|
|
|
|
|
Energy revenue increased by $172 million
due to:
|
|
|
|
|
○
|
Energy prices increased by $430 million
as the average realized merchant price was higher in 2008 due to
the combination of higher gas prices and unusually high pricing
events. The average realized energy price increased by 18%,
driven by a 44% increase in merchant prices offset by a 16%
decrease in contract prices.
|
|
|
○
|
Generation decreased by 2% resulting in a
$42 million decline in sales volume. This decrease in
generation was due to a 3% decline in nuclear generation at STP,
as a result of additional plant outages, and a 14% decline in
overall gas plant generation for the year ended December 2008.
Hurricane Ike in September 2008 caused major damage to the
Houston area transmission grid which reduced significantly the
demand for power causing a decrease in gas-fired generation.
These declines were offset by a 1% increase in coal generation
in 2008.
|
|
|
○
|
Margin on MWh sold from market purchases
decreased by $216 million.
|
Capacity revenue
increased by $130 million due to a greater
proportion of base-load contracts which contain a capacity
component.
Other revenue
increased by $50 million related to a $23 million
increase in ancillary services revenue in 2008, a
$22 million increase of allocations for trading of emission
allowances and carbon financial instruments, and increased
activity in trading natural gas and coal of $4 million.
Contract amortization revenue
increased by $36 million due to the volume
of contracted energy being positively affected by a greater
spread between contract prices and market prices used in the
Texas Genco purchase accounting.
Cost
of Energy
Cost of energy increased by $59 million for the year ended
December 31, 2008, compared to 2007 due to the following:
Natural gas costs
increased by $99 million due to a 28% rise
in average gas prices offset by a 14% decrease in gas-fired
generation.
Coal costs
increased by $44 million due to higher coal
prices and the settlement of a coal contract dispute.
Ancillary service costs
increased by $14 million due to a
$16 million rise in ancillary service costs purchased
through ERCOT, offset by a $2 million decrease in other
purchased ancillary service costs.
These increases were partially offset by:
Amortized contract costs
decreased by $59 million due to a
$36 million decrease in the amortization of water supply
contracts which ended in 2007. In addition, the amortization of
coal contracts decreased by a net $22 million as a result
of a reduction in expense related to
in-the-money
coal contract amortization. These contracts were established
under Texas Genco purchase accounting.
Nuclear fuel expense
decreased by $19 million as amortization of
nuclear fuel inventory established under Texas Genco purchase
accounting ended in early 2008.
100
Purchased power
decreased by $26 million due to lower
forced outage rates at the regions baseload plants.
Other
Operating Expenses
Other operating expenses decreased by $18 million for the
year ended December 31, 2008, compared to 2007 due to the
following:
Development costs
decreased by $59 million primarily due to
the initial costs for developing the nuclear Units 3 and 4 at
STP associated with the RepoweringNRG initiative that
began in 2007. Costs for STP nuclear Units 3 and 4 are being
capitalized in 2008.
This decrease was primarily offset by:
Operations and maintenance
expense increased by $32 million due to an
additional planned outage at STP and the acceleration of planned
outages at the baseload plants.
General and administrative
expense increased by $10 million driven by
higher corporate allocations.
Northeast
Region
2009
compared to 2008
The following table provides selected financial information for
the Northeast region for the years ended December 31, 2009,
and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
489
|
|
|
$
|
1,064
|
|
|
|
(54
|
)%
|
|
|
|
|
Capacity revenue
|
|
|
407
|
|
|
|
415
|
|
|
|
(2
|
)
|
|
|
|
|
Risk management activities
|
|
|
277
|
|
|
|
85
|
|
|
|
N/A
|
|
|
|
|
|
Other revenues
|
|
|
28
|
|
|
|
66
|
|
|
|
(58
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,201
|
|
|
|
1,630
|
|
|
|
(26
|
)
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
341
|
|
|
|
695
|
|
|
|
(51
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
118
|
|
|
|
109
|
|
|
|
8
|
|
|
|
|
|
Other operating expenses
|
|
|
399
|
|
|
|
392
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
343
|
|
|
$
|
434
|
|
|
|
(21
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
9,220
|
|
|
|
13,349
|
|
|
|
(31
|
)
|
|
|
|
|
MWh generated (in thousands)
|
|
|
9,220
|
|
|
|
13,349
|
|
|
|
(31
|
)
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
46.14
|
|
|
$
|
91.68
|
|
|
|
(50
|
)
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
475
|
|
|
|
611
|
|
|
|
(22
|
)
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
537
|
|
|
|
537
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
6,286
|
|
|
|
6,057
|
|
|
|
4
|
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
6,262
|
|
|
|
6,294
|
|
|
|
(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.
|
101
Operating
Income
Operating income decreased by $91 million for the year
ended December 31, 2009, compared to the same period in
2008, due to:
Operating revenues
decreased by $429 million due to
unfavorable energy revenues, other revenues and capacity
revenues partially offset by a favorable impact from risk
management activities.
Cost of
energy decreased by $354 million due
to lower generation and fuel prices.
Operating
Revenues
Operating revenues decreased by $429 million for the year
ended December 31, 2009, compared to the same period in
2008, due to:
|
|
|
|
|
Energy revenue decreased by $575 million
due to:
|
|
|
|
|
○
|
Energy prices decreased by $295 million
reflecting an average 40% decline in merchant energy prices.
|
|
|
○
|
Generation decreased by $334 million due
to a 31% decrease in generation in 2009 compared to 2008, driven
by a 31% decrease in coal generation and a 31% decrease in oil
and gas generation. Coal generation declined 24%, or
1,471,726 MWhs, in western New York; 39%, or
1,503,975 MWhs, at Indian River; and 80%, or
476,537 MWh, at Somerset. The decline in generation at
these plants is due to a combination of weakened demand for
power, low gas prices and higher cost of production from the
introduction of RGGI resulting 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
Norwalk plant and higher maintenance work at the Arthur Kill
plant in 2009.
|
|
|
○
|
Margin on MWh sold from market purchases
increased by $54 million driven by lower
net costs incurred in meeting obligations under load serving
contracts in the PJM market.
|
Other revenues
decreased by $38 million due to
$20 million from decreased activity in the trading of
emission allowances and $17 million lower allocations of
net physical gas sales.
Capacity revenue
decreased by $8 million due to lower
capacity cash flow revenue in New York in 2009.
These decreases were offset by:
Risk management activities
gains of $277 million were recorded for the
year ended December 31, 2009, compared to gains of
$85 million during the same period in 2008. The
$277 million gain included $107 million of unrealized
mark-to-market
losses and $384 million in gains on settled transactions,
or financial income, compared to $82 million in unrealized
mark-to-market
gains and $3 million in financial gains during the same
period in 2008. For further discussion of the Companys
risk management activities, see Consolidated Results of
Operations.
Cost
of Energy
Cost of energy decreased by $354 million for the year ended
December 31, 2009, compared to the same period in 2008, due
to:
Natural gas and oil costs
decreased by $187 million, or 60%, due to
31% lower generation and 56% lower average natural gas prices.
Coal costs
decreased by $129 million, or 35%, due to
lower coal generation of 31% accounting for $111 million
and lower prices accounting for $18 million. The lower
prices are due to lower fuel transportation surcharges.
Fuel risk management activities
gains of $60 million were recorded for the
year ended December 31, 2009. In the first quarter 2009,
all NPNS coal contracts were discontinued and reclassified to
102
mark-to-market
accounting. The $60 million gain included $67 million
of unrealized
mark-to-market
gains, largely associated with forward coal positions and
$7 million in losses on settled transactions, or financial
cost of energy. For further discussion of the Companys
risk management activities, see Consolidated Results of
Operations.
These decreases were offset by:
Carbon emission expense
increased by $22 million due to the
January 1, 2009, implementation of RGGI and the recognition
of carbon compliance cost under this program.
Depreciation
and Amortization
Depreciation and amortization increased by $9 million
primarily due to depreciation from the 2009 baghouse projects at
NRGs Western New York coal plants.
Other
Operating Expenses
Other operating expenses increased by $7 million for the
year ended December 31, 2009, compared to the same period
in 2008, due to:
|
|
|
|
|
Property taxes increased by $14 million
due to lower Empire Zone tax benefits recognized in 2009 at the
Oswego plant due to the plant receiving notice of
decertification from the Empire Zone program in 2009 from the
State of New York which decision is under appeal by the Company.
|
|
|
|
Write-down of assets increased by
$12 million for the year ended December 31, 2009,
compared to the same period in 2008. The write-down was due to
the cancellation and subsequent write off of construction costs
incurred through year end 2009 on the Indian River Unit 3 air
pollution control equipment project. NRG and DNREC announced a
proposed plan, subject to definitive documentation, that would
shut down Unit 3 by December 31, 2013, and relieve NRG of
the requirement to install this back-end control equipment. Unit
4 is not affected by this plan and construction on similar
equipment continues with an expected in-service date of year-end
2011.
|
|
|
|
General and administrative expense increased
by $2 million due to higher labor and employee benefit
costs.
|
|
|
|
Development costs increased by
$2 million due to increased repowering efforts at the
Astoria plant and a biomass project at the Montville plant.
|
These increases was offset by:
|
|
|
|
|
Operations and maintenance expenses decreased
by $22 million due to lower chemical spending and routine
maintenance work as a result of lower generation and lower
planned major maintenance work at the Huntley and Indian River
plants.
|
103
2008
compared to 2007
The following table provides selected financial information for
the Northeast region for the years ended December 31, 2008,
and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
1,064
|
|
|
$
|
1,104
|
|
|
|
(4
|
)%
|
|
|
|
|
Capacity revenue
|
|
|
415
|
|
|
|
402
|
|
|
|
3
|
|
|
|
|
|
Risk management activities
|
|
|
85
|
|
|
|
27
|
|
|
|
215
|
|
|
|
|
|
Other revenues
|
|
|
66
|
|
|
|
72
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
1,630
|
|
|
|
1,605
|
|
|
|
2
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
695
|
|
|
|
641
|
|
|
|
8
|
|
|
|
|
|
Depreciation and amortization
|
|
|
109
|
|
|
|
102
|
|
|
|
7
|
|
|
|
|
|
Other operating expenses
|
|
|
392
|
|
|
|
404
|
|
|
|
(3
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
434
|
|
|
$
|
458
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
(6
|
)
|
|
|
|
|
MWh generated (in thousands)
|
|
|
13,349
|
|
|
|
14,163
|
|
|
|
(6
|
)
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
91.68
|
|
|
$
|
76.37
|
|
|
|
20
|
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
611
|
|
|
|
702
|
|
|
|
(13
|
)
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
537
|
|
|
|
537
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
6,057
|
|
|
|
6,074
|
|
|
|
|
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
6,294
|
|
|
|
6,261
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income decreased by $24 million for the year
ended December 31, 2008, compared to 2007, due to:
Cost of energy
increased by $54 million due to higher coal
costs, increased coal transportation surcharges and higher
natural gas prices. The increase was offset by lower oil costs
from lower oil-fired generation.
This unfavorable variance was offset by:
Operating revenues
increased by $25 million due to higher capacity revenue
and risk management revenues partially offset by lower energy
revenue.
Other operating expenses
decreased by $12 million due to lower major
maintenance expenses and property taxes offset by higher
utilities expense.
Operating
Revenues
Operating revenues increased by $25 million for the year
ended December 31, 2008, compared to 2007, due to:
Risk management activities
gains of $85 million were recorded for the
year ended December 31, 2008, compared to gains of
$27 million during the same period in 2007. The
$85 million gain includes $82 million of unrealized
mark-to-market
gains and $3 million of gains in settled transactions, or
financial revenue. The $82 million unrealized gains is the
net effect of a $96 million gain from economic hedge
positions, the $13 million loss due to the reversal of
previously recognized
mark-to-market
gains on economic hedges, the $14 million loss due to the
reversal of
mark-to-market
gains on trading activity and $13 million in unrealized
mark-to-market
gains on trading activity. Gains are driven by increases in
power and gas prices.
104
|
|
|
|
|
Capacity revenue increased by
$13 million due to:
|
|
|
|
|
○
|
PJM capacity revenue increased by
$20 million reflecting recognition of a year of revenue
from the RPM capacity market (effective on June 1,
2007) in 2008 compared to seven months in 2007.
|
|
|
○
|
NEPOOL capacity revenue increased
$11 million due to increased revenue recognized on the
Norwalk RMR contract (effective on June 19, 2007) in
2008 compared to seven months in 2007.
|
|
|
○
|
NYISO capacity revenue decreased by
$18 million due to unfavorable market prices. The lower
capacity market prices are a result of NYISOs reductions
in Installed Reserve Margins and installed capacity in-city
mitigation rules effective March 2008. These decreases were
offset by higher capacity contract revenue.
|
These gains were offset by:
|
|
|
|
|
Energy revenues decreased by $40 million
due to:
|
|
|
|
|
○
|
Energy prices increased by $64 million
due to an average 6% rise in merchant energy prices.
|
|
|
○
|
Generation decreased by $66 million due
to a net 6% decrease in generation. The decrease in generation
represented a 55% decrease in oil-fired generation as these
oil-fired plants were not dispatched due to 41% higher average
oil prices. In addition, there was a 12% decrease in gas-fired
generation related to a cooler summer in 2008 as compared to
2007. Coal generation was flat in 2008 compared to 2007.
|
|
|
○
|
Margin on MWh sold from market purchases
decreased by $38 million driven by higher
net costs incurred to service PJM contracts as a result of the
increase in market energy prices.
|
Other revenues
decreased by $6 million due to lower
allocations of net physical sales in 2008 of $17 million
offset by higher allocations for trading of emission allowances
and carbon financial instruments of $10 million.
Cost
of Energy
Cost of energy increased by $54 million for the year ended
December 31, 2008, compared to the same period in 2007, due
to:
|
|
|
|
|
Coal costs increased by $61 million due
to higher coal costs and fuel transportation surcharges.
|
|
|
|
Natural gas costs increased by
$22 million, despite 12% lower generation, due to a 32%
higher average natural gas prices.
|
These increases were offset by:
Oil costs
decreased by $27 million due to lower
oil-fired generation of 55% as these plants were not dispatched
in 2008 due to 41% higher average oil prices.
Other
Operating Expenses
Other operating expenses decreased by $12 million for the
year ended December 31, 2008, compared to the same period
in 2007, due to:
|
|
|
|
|
Major maintenance decreased $18 million
as a result of less outage work at the Norwalk and Indian River
plants.
|
Property taxes
decreased $10 million due to
$4 million in property tax credits received in 2008 at the
regions New York City plants and higher property credits
received in 2008 at the regions Western New York
plants.
These decreases were offset by:
Utilities expense
increased by $16 million as a result of a
$19 million benefit included in the 2007 utilities cost due
to a lower than planned settlement of the station service
agreement with CL&P.
105
South
Central Region
2009
compared to 2008
The following table provides selected financial information for
the South Central region for the years ended December 31,
2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
360
|
|
|
$
|
478
|
|
|
|
(25
|
)%
|
|
|
|
|
Capacity revenue
|
|
|
269
|
|
|
|
233
|
|
|
|
15
|
|
|
|
|
|
Risk management activities
|
|
|
(71
|
)
|
|
|
10
|
|
|
|
N/A
|
|
|
|
|
|
Contract amortization
|
|
|
22
|
|
|
|
23
|
|
|
|
(4
|
)
|
|
|
|
|
Other revenues
|
|
|
1
|
|
|
|
2
|
|
|
|
(50
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
581
|
|
|
|
746
|
|
|
|
(22
|
)
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
399
|
|
|
|
468
|
|
|
|
(15
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
67
|
|
|
|
67
|
|
|
|
|
|
|
|
|
|
Other operating expenses
|
|
|
109
|
|
|
|
111
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
6
|
|
|
$
|
100
|
|
|
|
(94
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
12,144
|
|
|
|
12,447
|
|
|
|
(2
|
)
|
|
|
|
|
MWh generated (in thousands)
|
|
|
10,398
|
|
|
|
11,148
|
|
|
|
(7
|
)
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
33.58
|
|
|
$
|
71.25
|
|
|
|
(53
|
)
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
1,549
|
|
|
|
1,618
|
|
|
|
(4
|
)
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
1,548
|
|
|
|
1,547
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,521
|
|
|
|
3,672
|
|
|
|
(4
|
)
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
3,604
|
|
|
|
3,623
|
|
|
|
(1
|
)%
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income decreased by $94 million for the year
ended December 31, 2009, compared to the same period in
2008 due to:
Operating revenues
declined by $165 million as a result of
decreases in energy revenue, risk management activities and
other revenue. These decreases were offset by an increase in
capacity revenue.
Cost of energy
declined by $69 million due to lower purchased energy, fuel
and transmission costs, offset by higher fuel risk management
activities.
Operating
Revenues
Operating revenues decreased by $165 million for the year
ended December 31, 2009, compared to the same period in
2008, due to:
Energy revenue
decreased by $118 million due to a
$80 million decline in contract revenue, a $2 million
decrease in merchant energy revenue and a $36 million
decrease in margin on MWh sold from market purchases. The
contract revenue decrease was attributed to a 10% decrease in
sales volumes and a $5.15 per MWh lower average realized price.
The decline in contract energy price was driven by a
$16 million decrease in fuel cost pass-through to the
cooperatives reflecting an overall decline in natural gas
prices. Also contributing to the decline in contract revenue was
a $60 million decrease due to the expiration of a
106
contract with a regional utility. The expiration of the contract
allowed more energy to be sold into the merchant market, but at
lower prices resulting in a $2 million decline in revenue.
Risk management activities
losses of $71 million were recorded for the
year ended December 31, 2009, compared to gains of
$10 million during the same period in 2008. The
$71 million loss included $78 million of unrealized
mark-to-market
losses offset by $7 million in gains on settled
transactions, or financial income, compared to $26 million
in unrealized
mark-to-market
gains offset by $16 million in financial losses during the
same period in 2008. For further discussion of the
Companys risk management activities, see Consolidated
Results of Operations.
These decreases were offset by:
Capacity revenue
grew by $36 million driven by a
$40 million increase from new capacity agreements with
regional utilities and a $5 million increase in capacity
revenue contributed by the regions Rockford plants which
dispatch into the PJM market, offset by reduced contract
capacity revenue of $9 million.
Cost
of Energy
Cost of energy is down by $69 million for the year ended
December 31, 2009, compared to the same period in 2008,
reflecting:
Purchased energy
declined by $58 million while purchased
capacity rose by $3 million. The lower purchased energy was
driven by lower fuel costs associated with the regions
tolled facility and lower market energy prices. The energy
declines were offset by increased capacity payments of
$3 million on tolled facilities.
Natural gas expense
decreased by $15 million reflecting a 30%
drop in owned gas generation and a 54% decline in gas prices.
The regions gas facilities ran extensively to support
transmission system stability following hurricane Gustav in
September 2008.
Coal expense
decreased $11 million as coal generation
was down 6%, offset by a 1% increase in cost per ton.
Transmission expense
declined by $8 million due to certain
transmission line outages between electrical power regions which
limited merchant energy volumes that would incur transmission
costs as well as lower network interchange transmission costs
associated with reduced contract customer energy volumes.
These decreases were offset by:
Fuel risk management activities
losses of $21 million were recorded for the
year ended December 31, 2009. In the first quarter 2009,
all NPNS coal contracts were discontinued and reclassified into
mark-to-market
accounting. The $21 million loss included $12 million
of unrealized
mark-to-market
losses largely associated with forward coal positions and
$9 million in losses on settled transactions, or financial
cost of energy. For further discussion of the Companys
risk management activities, see Consolidated Results of
Operations.
Other
Operating Expenses
Other operating expenses decreased by $2 million for the
year ended December 31, 2009, compared to 2008, associated
with:
General and administrative
expense Corporate allocations declined by
$8 million in 2009 versus the same period in 2008.
Franchise tax expense grew by $2 million due to credits
recorded in 2008 related to prior years.
Operating and maintenance
expense Labor costs increased by $2 million
because of higher benefit costs. Major maintenance rose by
$2 million due to more extensive outage work performed at
the Big Cajun II plant in 2009 compared to the same period
in 2008.
107
2008
compared to 2007
The following table provides selected financial information for
the South Central region for the years ended December 31,
2008, and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
478
|
|
|
$
|
404
|
|
|
|
18
|
%
|
|
|
|
|
Capacity revenue
|
|
|
233
|
|
|
|
221
|
|
|
|
5
|
|
|
|
|
|
Risk management activities
|
|
|
10
|
|
|
|
10
|
|
|
|
|
|
|
|
|
|
Contract amortization
|
|
|
23
|
|
|
|
23
|
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
2
|
|
|
|
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
746
|
|
|
|
658
|
|
|
|
13
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
468
|
|
|
|
412
|
|
|
|
14
|
|
|
|
|
|
Depreciation and amortization
|
|
|
67
|
|
|
|
68
|
|
|
|
(1
|
)
|
|
|
|
|
Other operating expenses
|
|
|
111
|
|
|
|
121
|
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
100
|
|
|
$
|
57
|
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
12,447
|
|
|
|
12,452
|
|
|
|
|
|
|
|
|
|
MWh generated (in thousands)
|
|
|
11,148
|
|
|
|
10,930
|
|
|
|
2
|
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
71.25
|
|
|
$
|
59.63
|
|
|
|
19
|
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
1,618
|
|
|
|
1,963
|
|
|
|
(18
|
)
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
1,547
|
|
|
|
1,547
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,672
|
|
|
|
3,236
|
|
|
|
13
|
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
3,623
|
|
|
|
3,604
|
|
|
|
1
|
%
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD represents
the number of degrees that the mean temperature for a particular
day is above 65 degrees Fahrenheit in each region. An HDD
represents the number of degrees that the mean temperature for a
particular day is below 65 degrees Fahrenheit in each region.
The CDDs/HDDs for a period of time are calculated by adding the
CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income increased by $43 million for the year
ended December 31, 2008, compared to the same period in
2007, due to:
|
|
|
|
|
Operating revenues increased by
$88 million due to increases in energy revenue and capacity
revenue.
|
Cost of energy
increased by $56 million due to higher
purchased energy, coal transportation costs, natural gas and
transmission costs.
Operating
Revenues
Operating revenues increased by $88 million for the year
ended December 31, 2008, compared to 2007, due to:
Energy revenue
increased by $74 million due to a
$41 million increase in merchant energy revenues and a
$33 million increase in margin on MWh sold from market
purchases. A decline in contract sales of 577 thousand MWh
allowed for increased sales into the merchant market at higher
prices. Revenue from contract load was flat as higher fuel cost
pass-through adjustments for the regions cooperative
customers were offset by reductions in contract volume to other
contract customers.
Capacity revenue
increased by
$12 million. Capacity payments from the
regions cooperative customers increased by
$10 million due to new peak loads set by the regions
cooperative customers and increased transmission and
environmental pass-through costs. Increased RPM capacity
payments from the regions Rockford facilities in the PJM
market contributed an additional
108
$8 million. These increases were offset by a reduction in
contract volumes to other customers of $6 million.
Risk management activities
gains of $10 million were recognized during
2008 compared to $10 million in gains recognized during the
same period in 2007. Unrealized gains in 2008 of
$26 million were offset by realized losses of
$16 million. The $26 million unrealized gain was the
net effect of a $45 million unrealized
mark-to-market
gain from trading activities in the region offset by the
reversal of $19 million loss of previously recognized
mark-to-market
gains on trading activity. Unrealized gains were primarily
driven by decreases in power and gas prices relative to the
Companys forward positions.
Cost
of Energy
Cost of energy increased by $56 million for the year ended
December 31, 2008, compared to 2007, due to:
Purchased energy
increased by $16 million reflecting a 21%
increase in the average cost per MWh of purchased energy which
reflects higher gas costs associated with the regions
tolling agreements. This increase was offset by an 8% decrease
in purchased MWh as increased plant availability and lower
contract load requirements reduced the need to purchase power.
Coal costs
increased by $16 million due to a $2 per
ton increase in fuel transportation surcharges combined with a
1% increase in coal generation. These increases were offset by a
$3 million decrease in allocated rail car lease fees.
Natural gas costs
increased $14 million. The regions
Bayou Cove and Big Cajun I peaker plants ran extensively to
support transmission system stability after hurricane Gustav in
September 2008.
Transmission costs
increased by $9 million due to additional
point-to-point
transmission costs driven by an increase in merchant energy
sales.
Other
Operating Expenses
Other operating expenses decreased by $10 million for the
year ended December 31, 2008, compared to 2007, due to:
General and administrative
expense Franchise tax decreased by
$5 million due to retroactive charges recorded in 2007. The
Louisiana state franchise tax is assessed on the Companys
total debt and equity that significantly increased following the
acquisition of Texas Genco. This decrease was offset by
$6 million in higher corporate allocations in 2008 compared
to the same period in 2007.
Operating and maintenance
expense Major maintenance decreased by
$9 million due to more extensive spring outage work
performed at the Big Cajun II plant in 2007 compared to the
same period in 2008. Normal maintenance rose $2 million as
a result of increased forced outages and higher contractor
costs. Asset retirements decreased by $4 million reflecting
disposals associated with the 2007 outage work at Big Cajun II.
109
West
Region
2009
compared to 2008
The following table provides selected financial information for
the West region for the years ended December 31, 2009, and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Change %
|
|
|
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
34
|
|
|
$
|
39
|
|
|
|
(13
|
)%
|
|
|
|
|
Capacity revenue
|
|
|
122
|
|
|
|
125
|
|
|
|
(2
|
)
|
|
|
|
|
Risk management activities
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues
|
|
|
2
|
|
|
|
7
|
|
|
|
(71
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
150
|
|
|
|
171
|
|
|
|
(12
|
)
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
29
|
|
|
|
35
|
|
|
|
(17
|
)
|
|
|
|
|
Depreciation and amortization
|
|
|
8
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
Other operating expenses
|
|
|
81
|
|
|
|
70
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
32
|
|
|
$
|
58
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
1,279
|
|
|
|
1,532
|
|
|
|
(17
|
)
|
|
|
|
|
MWh generated (in thousands)
|
|
|
1,279
|
|
|
|
1,532
|
|
|
|
(17
|
)
|
|
|
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
40.10
|
|
|
$
|
82.20
|
|
|
|
(51
|
)
|
|
|
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
908
|
|
|
|
953
|
|
|
|
(5
|
)
|
|
|
|
|
CDDs
30-year
rolling average
|
|
|
704
|
|
|
|
704
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,105
|
|
|
|
3,190
|
|
|
|
(3
|
)%
|
|
|
|
|
HDDs
30-year
rolling average
|
|
|
3,228
|
|
|
|
3,243
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
Operating
Income
Operating income decreased by $26 million for the year
ended December 31, 2009, compared to the same period in
2008, due to decreases in capacity revenue, energy revenue, risk
management activities and other revenues.
Operating
Revenues
Operating revenues decreased by $21 million for the year
ended December 31, 2009, compared to the same period in
2008, due to:
Capacity revenue
decreased by $3 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.
Energy
revenue decreased by $5 million
primarily due to a 16% decrease in merchant prices in 2009
compared to 2008. This decrease was offset by a 5% increase in
merchant generation in 2009 compared to 2008.
Other revenues
decreased by $5 million due to lower
emission allowance sales partially offset by an increase in
ancillary services revenue.
110
Risk management activities
realized losses of $8 million on settled
transactions were recognized during the period. There was no
risk management activity in 2008. For further discussion of the
Companys risk management activities, see Consolidated
Results of Operations.
Cost
of Energy and Other Operating Expenses
Cost of energy and other operating expenses increased by
$5 million for the year ended December 31, 2009,
compared to the same period in 2008, due to:
Cost of energy
decreased by $6 million due to a 29%
decline in average natural gas prices per MMBtu. This decrease
was partially offset by an 8% increase in natural gas
consumption and 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 $11 million due to higher
maintenance expense associated with a major overhaul at El
Segundo and higher maintenance at Long Beach.
2008
compared to 2007
The following table provides selected financial information for
the West region for the years ended December 31, 2008, and
2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Change%
|
|
|
|
(In millions except otherwise noted)
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue
|
|
$
|
39
|
|
|
$
|
4
|
|
|
|
N/A
|
|
Capacity revenue
|
|
|
125
|
|
|
|
122
|
|
|
|
2
|
%
|
Risk management activities
|
|
|
|
|
|
|
|
|
|
|
N/A
|
|
Other revenues
|
|
|
7
|
|
|
|
1
|
|
|
|
N/A
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
|
171
|
|
|
|
127
|
|
|
|
35
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy
|
|
|
35
|
|
|
|
5
|
|
|
|
N/A
|
|
Depreciation and amortization
|
|
|
8
|
|
|
|
3
|
|
|
|
167
|
|
Other operating expenses
|
|
|
70
|
|
|
|
80
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
$
|
58
|
|
|
$
|
39
|
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands)
|
|
|
1,532
|
|
|
|
1,246
|
|
|
|
23
|
|
MWh generated (in thousands)
|
|
|
1,532
|
|
|
|
1,246
|
|
|
|
23
|
|
Business Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh)
|
|
$
|
82.20
|
|
|
$
|
66.46
|
|
|
|
24
|
|
Cooling Degree Days, or
CDDs(a)
|
|
|
953
|
|
|
|
785
|
|
|
|
21
|
|
CDDs
30-year
rolling average
|
|
|
704
|
|
|
|
704
|
|
|
|
|
|
Heating Degree Days, or
HDDs(a)
|
|
|
3,190
|
|
|
|
3,048
|
|
|
|
5
|
%
|
HDDs
30-year
rolling average
|
|
|
3,243
|
|
|
|
3,228
|
|
|
|
|
|
|
|
|
(a)
|
|
National Oceanic and Atmospheric
Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a
particular day is above 65 degrees Fahrenheit in each region. An
HDD represents the number of degrees that the mean temperature
for a particular day is below 65 degrees Fahrenheit in each
region. The CDDs/HDDs for a period of time are calculated by
adding the CDDs/HDDs for each day during the period.
|
111
Operating
Income
Operating income increased by $19 million for the year
ended December 31, 2008, compared to the same period in
2007, due to:
Operating
Revenues
Operating revenues increased by $44 million for the year
ended December 31, 2008, compared to the same period in
2007, due to:
Energy revenue
increased by $35 million due to the 2008
dispatch of the El Segundo plant outside of the tolling
agreement in 2008. In 2007, no such dispatch occurred.
Other revenues
increased by $6 million due to higher
allocations for trading of emission allowances in 2008.
Capacity revenue
increased by $3 million primarily due to
the tolling agreement at the Long Beach plant partially offset
by the expiration of a two year tolling agreement at the El
Segundo facility:
|
|
|
|
¡
|
Long Beach On August 1, 2007, NRG
successfully completed the repowering of a 260 MW natural
gas-fueled generating plant at its Long Beach generating
facility. The plant contributed $15 million in incremental
capacity revenues for the year ended December 31, 2008.
|
|
|
¡
|
El Segundo The expiration of the two year
tolling agreement at the end of April resulted in a decrease of
$11 million in capacity revenues for the year ended
December 31, 2008.
|
Cost
of Energy and Other Operating Expenses
Cost of energy and other operating expenses increased by
$25 million for the year ended December 31, 2008,
compared to the same period in 2007, due to:
Cost of energy
increased by $30 million due to the dispatch of the El
Segundo plant outside of the tolling agreement in 2008. In 2007,
no such dispatch occurred.
Depreciation and amortization
increased by $5 million, reflecting
depreciation associated with the repowered plant at the Long
Beach generating facility.
Other operating expenses
decreased by $10 million as a result of a
$5 million reduction in RepoweringNRG expenses due
to the capitalization of cost for the El Segundo Energy Center
project in 2008. In addition there was a $3 million
reduction in lease expenses in 2008 and the recognition of a
$2 million environmental liability for the El Segundo plant
in 2007.
Liquidity
and Capital Resources
Liquidity
Position
As of December 31, 2009, and 2008, NRGs liquidity,
excluding collateral received, was approximately
$3.8 billion and $3.4 billion, respectively, comprised
of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
2,304
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
177
|
|
|
|
754
|
|
Restricted cash
|
|
|
2
|
|
|
|
16
|
|
|
|
|
|
|
|
|
|
|
Total cash
|
|
|
2,483
|
|
|
|
2,264
|
|
Synthetic Letter of Credit Facility availability
|
|
|
583
|
|
|
|
860
|
|
Revolving Credit Facility availability
|
|
|
905
|
|
|
|
1,000
|
|
|
|
|
|
|
|
|
|
|
Total liquidity
|
|
|
3,971
|
|
|
|
4,124
|
|
Less: Funds deposited as collateral by hedge counterparties
|
|
|
(177
|
)
|
|
|
(760
|
)
|
|
|
|
|
|
|
|
|
|
Total liquidity, excluding collateral received
|
|
$
|
3,794
|
|
|
$
|
3,364
|
|
|
|
|
|
|
|
|
|
|
112
For the year ended December 31, 2009, total liquidity,
excluding collateral received, increased by $430 million
due to a higher cash balance of $810 million, partially
offset by decreased availability of the Synthetic Letter of
Credit Facility and the Revolving Credit Facility of
$277 million and $95 million, respectively. Changes in
cash balances are further discussed hereinafter under Cash
Flow Discussion. Cash and cash equivalents and funds
deposited by counterparties at December 31, 2009, are
predominantly held in money market funds invested in treasury
securities, treasury repurchase agreements or government agency
debt.
The line item Funds deposited by counterparties
represents the amounts that are held by NRG as a result of
collateral posting obligations from the Companys
counterparties due to positions in the Companys hedging
program. These amounts are segregated into separate accounts
that are not contractually restricted but, based on the
Companys intention, are not available for the payment of
NRGs general corporate obligations. Depending on market
fluctuation and the settlement of the underlying contracts, the
Company will refund this collateral to the counterparties
pursuant to the terms and conditions of the underlying trades.
Since collateral requirements fluctuate daily and the Company
cannot predict if any collateral will be held for more than
twelve months, the funds deposited by counterparties are
classified as a current asset on the Companys balance
sheet, with an offsetting liability for this cash collateral
received within current liabilities. 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 Item 14 Note 3,
Business Acquisitions, to the Consolidated Financial
Statements), offset by a increase of
in-the-money
positions as a result of decreasing forward prices.
Management believes that the Companys liquidity position
and cash flows from operations will be adequate to finance
operating and maintenance capital expenditures, to fund
dividends to NRGs preferred shareholders, and other
liquidity commitments. Management continues to regularly monitor
the Companys ability to finance the needs of its
operating, financing and investing activity in a manner
consistent with its intention to maintain a net debt to capital
ratio in the range of
45-60%.
Credit
Ratings
Credit rating agencies rate a firms public debt
securities. These ratings are utilized by the debt markets in
evaluating a firms credit risk. Ratings influence the
price paid to issue new debt securities by indicating to the
market the Companys ability to pay principal, interest and
preferred dividends. Rating agencies evaluate a firms
industry, cash flow, leverage, liquidity, and hedge profile,
among other factors, in their credit analysis of a firms
credit risk.
The following table summarizes the credit ratings for NRG
Energy, Inc., its Term Loan Facility and its Senior Notes as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
S&P
|
|
Moodys
|
|
Fitch
|
|
NRG Energy, Inc.
|
|
BB−
|
|
Ba3
|
|
B
|
8.5% Senior Notes due 2019
|
|
BB−
|
|
B1
|
|
B+
|
7.375% Senior Notes, due 2016, 2017
|
|
BB−
|
|
B1
|
|
B+
|
7.25% Senior Notes due 2014
|
|
BB−
|
|
B1
|
|
B+
|
Term Loan Facility
|
|
BB+
|
|
Baa3
|
|
BB
|
SOURCES
OF FUNDS
The principal sources of liquidity for NRGs future
operating and capital expenditures are expected to be derived
from new and existing financing arrangements, asset sales,
existing cash on hand and cash flows from operations.
Financing
Arrangements
Senior
Credit Facility
As of December 31, 2009, NRG has a Senior Credit Facility
which is comprised of a senior first priority secured term loan,
or the Term Loan Facility, a $1.0 billion senior first
priority secured revolving credit facility, or the Revolving
Credit Facility, and a $1.3 billion senior first priority
secured synthetic letter of credit facility, or the
113
Synthetic Letter of Credit Facility. The Senior Credit Facility
was last amended on June 8, 2007. As of December 31,
2009, NRG had issued $717 million of letters of credit
under the Synthetic Letter of Credit Facility, leaving
$583 million available for future issuances. Under the
Revolving Credit Facility as of December 31, 2009, NRG had
issued letters of credit of $95 million, of which
$59 million supports the tax exempt bonds issued by Dunkirk
Power LLC as described in Item 14 Note 12,
Debt and Capital Leases, to the Consolidated Financial
Statements.
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
Item 14 Note 12, Debt and Capital
Leases, to the Consolidated Financial Statements. The
Company used a portion of the net proceeds of $678 million
to facilitate the early termination on October 5, 2009 of
NRGs obligations pursuant to the CSRA Amendment. Net
proceeds in excess of this amount are available for general
corporate purposes. See further discussion of the CSRA Amendment
in Item 14 Note 3, Business
Acquisitions, to the Consolidated Financial Statements.
Merrill
Lynch Credit Sleeve Facility
See discussion in Item 14 Note 3,
Business Acquisitions, to the Consolidated Financial
Statements, regarding the CSRA entered into to support the
retail business as a result of the acquisition of Reliant Energy
on May 1, 2009. Effective October 5, 2009, the Company
executed the CSRA Amendment. In connection with this amendment,
the Company posted $366 million of cash collateral to
Merrill Lynch and other counterparties, returned
$53 million of counterparty collateral, issued
$206 million of letters of credit, and received
$45 million of counterparty collateral. In addition,
Merrill Lynch returned $250 million of previously posted
cash collateral, and released liens on $322 million of
unrestricted cash held by Reliant Energy. Upon execution of the
CSRA Amendment, the Company was required to post collateral for
any net liability derivatives, and other static margin
associated with supply for Reliant Energy.
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 December 31, 2009, no
amounts had been borrowed 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 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
December 31, 2009, were $52 million with the remaining
balance being released over time as construction costs are paid.
On February 1, 2010, the Company fixed the rate on the
bonds at 5.875%. Interest will be payable semiannually. In
addition, the $59 million letter of credit issued by NRG in
support of the bonds was cancelled and replaced with a parent
guarantee. These bonds are part of the Companys first lien
debt.
114
GenConn
Energy LLC related financings
In April 2009, NRG Connecticut Peaking LLC., a wholly-owned
subsidiary of NRG, executed 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 $54 million, on the
earlier of Devons commercial operations date or
January 27, 2011. The proceeds of the EBL received through
December 31, 2009, were $108 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. In August 2009, GenConn began to draw under the
GenConn Facility to cover costs related to the Devon project and
as of December 31, 2009, has drawn $48 million.
First and
Second Lien Structure
NRG has granted first and second liens to certain counterparties
on substantially all of the Companys assets. NRG uses the
first or second lien structure to reduce the amount of cash
collateral and letters of credit that it would otherwise be
required to post from time to time to support its obligations
under
out-of-the-money
hedge agreements for forward sales of power or MWh equivalents.
To the extent that the underlying hedge positions for a
counterparty are
in-the-money
to NRG, the counterparty would have no claim under the lien
program. The lien program limits the volume that can be hedged,
not the value of underlying
out-of-the-money
positions. The first lien program does not require NRG to post
collateral above any threshold amount of exposure. Within the
first and second lien structure, the Company can hedge up to 80%
of its baseload capacity and 10% of its non-baseload assets with
these counterparties for the first 60 months and then
declining thereafter. Net exposure to a counterparty on all
trades must be positively correlated to the price of the
relevant commodity for the first lien to be available to that
counterparty. The first and second lien structure is not subject
to unwind or termination upon a ratings downgrade of a
counterparty and has no stated maturity date.
NRGs lien counterparties may have a claim on the
Companys assets to the extent market prices exceed the
hedged price. As of December 31, 2009 and February 9,
2010, all hedges under the first and second lien 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 February 9, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales Secured by First and Second Lien
Structure(a)
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
In MW(b)
|
|
|
3,358
|
|
|
|
2,931
|
|
|
|
1,520
|
|
|
|
732
|
|
As a percentage of total forecasted baseload
capacity(c)
|
|
|
49
|
%
|
|
|
43
|
%
|
|
|
22
|
%
|
|
|
11
|
%
|
|
|
|
(a)
|
|
Equivalent Net Sales include
natural gas swaps converted using a weighted average heat rate
by region.
|
(b)
|
|
2010 MW value consists of
March through December positions only.
|
(c)
|
|
Forecasted baseload capacity under
the first and second lien structure represents 80% of the total
Companys baseload assets.
|
Asset
Sales
MIBRAG On June 10, 2009, NRG completed
the sale of its 50% ownership interest in Mibrag B.V. to a
consortium of Severoćeské doly Chomutov, a member of
the CEZ Group, and J&T Group. Mibrag B.V.s principal
115
holding was MIBRAG, which was 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
($284 million at an exchange rate of 1.40 U.S.$/EUR), net
of transaction costs. During the year ended December 31,
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 year ended
December 31, 2009, NRG recorded an exchange loss of
$24 million on the contract within Other
income/(loss), net.
ITISA On April 28, 2008, NRG completed
the sale of its 100% interest in Tosli Acquisition B.V., or
Tosli, which held all NRGs interest in ITISA, to
Brookfield Renewable Power Inc. (previously Brookfield Power
Inc.), a wholly-owned subsidiary of Brookfield Asset Management
Inc. In addition, the purchase price adjustment contingency
under the sale agreement was resolved on August 7, 2008. In
connection with the sale, NRG received $300 million of cash
proceeds from Brookfield, and removed $163 million of
assets, including $59 million of cash, $122 million of
liabilities, including $63 million of debt, and
$15 million in foreign currency translation adjustment from
its 2008 consolidated balance sheet. As discussed in
Item 14 Note 4, Discontinued Operations
and Dispositions, to the Consolidated Financial Statements,
the activities of Tosli and ITISA have been classified as
discontinued operations.
USES
OF FUNDS
The Companys requirements for liquidity and capital
resources, other than for operating its facilities, can
generally be categorized by the following: (i) commercial
operations activities; (ii) debt service obligations;
(iii) capital expenditures including RepoweringNRG
and environmental; and (iv) corporate financial
transactions including return of capital to shareholders.
Commercial
Operations
NRGs commercial operations activities require a
significant amount of liquidity and capital resources. These
liquidity requirements are primarily driven by: (i) margin
and collateral posted with counterparties; (ii) initial
collateral required to establish trading relationships;
(iii) timing of disbursements and receipts (i.e., buying
fuel before receiving energy revenues); and (iv) initial
collateral for large structured transactions. As of
December 31, 2009, commercial operations had total cash
collateral outstanding of $359 million, and
$508 million outstanding in letters of credit to third
parties primarily to support its economic hedging activities for
both wholesale and retail transactions. As of December 31,
2009, total collateral held from counterparties was
$177 million, and $24 million of letters of credit.
Upon execution of the CSRA Amendment, effective October 5,
2009, the Company was required to post collateral for any net
liability derivatives, and other static margin associated with
supply for Reliant Energy that was transferred to NRG. As of
January 29, 2010, all wholesale energy supply contracts
relating to retail supply hedging were transferred to the
Company, so that Merrill Lynch was no longer providing any
credit support for wholesale energy supply contracts relating to
retail supply hedging.
Future liquidity requirements may change based on the
Companys hedging activities and structures, fuel
purchases, and future market conditions, including forward
prices for energy and fuel and market volatility. In addition,
liquidity requirements are dependent on NRGs credit
ratings and general perception of its creditworthiness.
Debt
Service Obligations
NRG must annually offer a portion of its excess cash flow (as
defined in the Senior Credit Facility) to its first lien lenders
under the Term Loan Facility. The percentage of excess cash flow
offered to these lenders is dependent
116
upon the Companys consolidated leverage ratio (as defined
in the Senior Credit Facility) at the end of the preceding year.
The 2010 mandatory offer related to 2009 is expected to be
$430 million, against which the Company made a prepayment
of $200 million in December 2009. Based on current credit
market conditions, the Company expects that its lenders will
accept in full the 2010 mandatory offer related to 2009, and, as
such, the Company has reclassified approximately
$230 million of Term Loan Facility maturity from a
non-current to a current liability as of December 31, 2009.
On October 9, 2009, NRG commenced the process of unwinding
the CSF II Debt, making a $181 million capital contribution
to a CSF II cash account, effectively restricting the cash for
the benefit of Credit Suisse Group, or CS. On October 13,
2009, CS began the process of unwinding their hedges in
connection with the CSF II structure, which they completed by
November 24, 2009. Once complete, CS returned
5,400,000 shares of NRG common stock borrowed under the
Share Lending Agreements, and released 9,528,930 common shares
held as collateral for the CSF II Debt, and the Company remitted
payment to CS of the $181 million for outstanding principal
and interest. The CSF II Debt contained an embedded derivative
feature, or CFS II CAGR, which required NRG to pay CS at
maturity, either in cash or stock at NRGs option, the
excess of NRGs then current stock price over a Threshold
Price of $40.80 per share. On November 24, 2009, the CSF II
CAGR expired with no payment due.
Principal payments on debt and capital leases as of
December 31, 2009, are due in the following periods:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subsidiary/Description
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
2013
|
|
|
2014
|
|
|
Thereafter
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.5% Notes due 2019
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
700
|
|
|
$
|
700
|
|
7.375% Notes due 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,100
|
|
|
|
1,100
|
|
7.375% Notes due 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,400
|
|
|
|
2,400
|
|
7.25% Notes due 2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,200
|
|
|
|
|
|
|
|
1,200
|
|
Term Loan Facility, due 2013
|
|
|
261
|
|
|
|
32
|
|
|
|
32
|
|
|
|
1,888
|
|
|
|
|
|
|
|
|
|
|
|
2,213
|
|
CSF I notes and preferred interests, due June 2010
|
|
|
190
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
190
|
|
NRG Energy Center Minneapolis LLC, due 2013 and 2017
|
|
|
11
|
|
|
|
12
|
|
|
|
13
|
|
|
|
10
|
|
|
|
6
|
|
|
|
21
|
|
|
|
73
|
|
Dunkirk Power LLC tax-exempt bonds, due April 2042
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
52
|
|
|
|
52
|
|
NRG Connecticut Peaking LLC, equity bridge loan facility
|
|
|
54
|
|
|
|
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
108
|
|
Nuclear Innovation North America LLC, due 2010
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
NRG Repowering Holdings LLC, due 2011
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
NRG Peaker Finance Co. LLC, due June 2019
|
|
|
20
|
|
|
|
21
|
|
|
|
22
|
|
|
|
23
|
|
|
|
29
|
|
|
|
136
|
|
|
|
251
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal Debt, Bonds and Notes
|
|
|
556
|
|
|
|
138
|
|
|
|
67
|
|
|
|
1,921
|
|
|
|
1,235
|
|
|
|
4,409
|
|
|
|
8,326
|
|
Capital Lease:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau
|
|
|
22
|
|
|
|
10
|
|
|
|
8
|
|
|
|
8
|
|
|
|
7
|
|
|
|
68
|
|
|
|
123
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Payments and Capital Leases
|
|
$
|
578
|
|
|
$
|
148
|
|
|
$
|
75
|
|
|
$
|
1,929
|
|
|
$
|
1,242
|
|
|
$
|
4,477
|
|
|
$
|
8,449
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In addition to the debt and capital leases shown in the
preceding table, NRG had issued $717 million of letters of
credit under the Companys $1.3 billion Synthetic
Letter of Credit Facility and $95 million of letters of
credit under the Companys Revolving Credit Facility as of
December 31, 2009. The Companys Revolving Credit
Facility matures on February 2, 2011, and the Synthetic
Letter of Credit Facility matures on February 1, 2013.
117
Capital
Expenditures
For the year ended December 31, 2009, the Companys
capital expenditures, including accruals, were approximately
$783 million. The following table summarizes the
Companys capital expenditures for the year ended
December 31, 2009 and the estimated capital expenditure and
repowering investments forecast for 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maintenance
|
|
|
Environmental
|
|
|
Repowering
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Northeast
|
|
$
|
30
|
|
|
$
|
172
|
|
|
$
|
5
|
|
|
$
|
207
|
|
Texas
|
|
|
160
|
|
|
|
|
|
|
|
29
|
|
|
|
189
|
|
South Central
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
West
|
|
|
4
|
|
|
|
|
|
|
|
4
|
|
|
|
8
|
|
Reliant Energy
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
Wind
|
|
|
|
|
|
|
|
|
|
|
120
|
|
|
|
120
|
|
Nuclear Development
|
|
|
|
|
|
|
|
|
|
|
197
|
|
|
|
197
|
|
Other
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
256
|
|
|
$
|
172
|
|
|
$
|
355
|
|
|
$
|
783
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated capital expenditures for 2010
|
|
$
|
241
|
|
|
$
|
233
|
|
|
$
|
707
|
|
|
$
|
1,181
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RepoweringNRG capital expenditures and
investments RepoweringNRG project capital
expenditures consisted of approximately $197 million
related to the development of STP Units 3 and 4 in Texas,
$120 million related to the Companys Langford wind
farm project which became commercially operational in December
2009 and $29 million for the construction of Cedar Bayou
Unit 4 in Texas.
The Companys repowering capital expenditures for 2010 are
expected to be approximately $707 million. Of this amount,
$684 million is estimated for STP Units 3 and 4 without
giving effect to any partner contributions or potential equity
sell down.
Major maintenance and environmental capital
expenditures The Companys maintenance
capital expenditures were $256 million, of which
$160 million was related to the Texas regions assets
including approximately $61 million in nuclear fuel
expenditures related to STP Units 1 and 2. The Companys
environmental capital expenditures were $172 million
consisting of $130 million at the Huntley and Dunkirk
plants due to the baghouse projects and $31 million at the
Indian River plant due to a project to install selective
catalytic reduction systems, scrubbers and fabric filters on
Units 3 and 4. On February 3, 2010, NRG and DNREC announced
a proposed plan, subject to definitive documentation, that would
shut down Unit 3 by December 31, 2013 and relieve NRG of
the requirement to install this back end control equipment on
this unit. Unit 4 is not affected by this plan and construction
on similar equipment continues with an expected in service date
of year end 2011.
NRG anticipates funding these 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 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. During 2009, these loans were repaid with
proceeds from the EBL financing. Subsequent to the financing,
the equity portion of construction costs for GenConn is funded
through the EBLs of NRG Connecticut Peaking and United
Illuminating. These funds are made available to GenConn through
convertible interest bearing promissory notes that convert to
equity upon repayment of the EBL loans by NRG Connecticut
Peaking and United Illuminating. As of December 31, 2009,
there was $108 million outstanding under the loan from NRG
Connecticut Peaking.
118
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures to be incurred from 2010
through 2014 to meet NRGs environmental commitments will
be approximately $0.9 billion. These capital expenditures,
in general, are related to installation of particulate,
SO2,
NOx,
and mercury controls to comply with federal and state air
quality rules and consent orders, as well as installation of
Best Technology Available under the Phase II
316(b) rule. NRG continues to explore cost effective
alternatives that can achieve desired results. While this
estimate reflects schedules and controls to meet anticipated
reduction requirements, the full impact on the scope and timing
of environmental retrofits cannot be determined until issuance
of final rules by the U.S. EPA.
The following table summarizes the estimated environmental
capital expenditures for the referenced periods by region:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
South Central
|
|
|
Total
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
2010
|
|
$
|
|
|
|
$
|
230
|
|
|
$
|
3
|
|
|
$
|
233
|
|
2011
|
|
|
|
|
|
|
179
|
|
|
|
52
|
|
|
|
231
|
|
2012
|
|
|
6
|
|
|
|
45
|
|
|
|
108
|
|
|
|
159
|
|
2013
|
|
|
39
|
|
|
|
9
|
|
|
|
109
|
|
|
|
157
|
|
2014
|
|
|
50
|
|
|
|
4
|
|
|
$
|
68
|
|
|
|
122
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
95
|
|
|
$
|
467
|
|
|
$
|
340
|
|
|
$
|
902
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
This estimate reflects the recent announcement to retrofit only
Unit 4 at the Indian River Generating Station and shifts in the
timing of other projects to reflect anticipated issuance dates
for revised regulations.
NRGs current contracts with the Companys rural
electrical customers in the South Central region allow for
recovery of a significant portion of the regions capital costs,
along with a capital return incurred by complying with new laws,
including interest over the asset life of the required
expenditures. Actual recoveries will depend, among other things,
on the duration of the contracts.
Capital
Allocation
2009 Capital Allocation Plan 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
included the completion of the 2008 Capital Allocation Plan with
the 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. In
July 2009, as part of the Companys 2009 Capital Allocation
Program, the Board of Directors approved an increase to the
Companys previously authorized common share repurchases
under its capital allocation plan from the existing
$330 million to $500 million. The Companys
repurchases during the year ended December 31, 2009, were
$500 million.
2010 Capital Allocation Plan On
February 23, 2010, the Company announced its 2010 Capital
Allocation Plan to purchase $180 million in common stock.
The Companys share repurchases are subject to market
prices, financial restrictions under the Companys debt
facilities, and as permitted by securities laws. As part of the
2010 plan, the Company will invest approximately
$474 million in maintenance and environmental capital
expenditures in existing assets and $707 million in
projects under RepoweringNRG that are currently under
construction or for which there exists current obligations.
Finally, in addition to scheduled debt amortization payment, in
the first quarter 2010 the Company will offer its first lien
lenders $430 million of its 2009 excess cash flow (as
defined in the Senior Credit Facility) of which the Company made
a prepayment of $200 million in December 2009.
Preferred
Stock Dividend Payments
For the year ended December 31, 2009, NRG paid
$6 million, $17 million and $10 million in
dividend payments to holders of the Companys 5.75%, 4% and
3.625% Preferred Stock. 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. During 2009, a total
of 265,870 shares of the 4% Preferred Stock were converted
into common stock and 73 shares were redeemed for cash.
119
Benefit
Plans Obligations
As of December 31, 2009, NRG contributed $27 million
towards its three defined benefit pension plans to meet the
Companys 2009 benefit obligation. Based on the
Companys December 31, 2009 measurement of its benefit
obligation for its three defined benefit pension plans, the
Company is expected to contribute another $18 million to
these plans during 2010, $5 million of which also relates
to the Companys 2009 benefit obligation.
Reliant
Energy Customer Deposits
Revisions in the PUCT rules will require that NRG keep a
segregated account, or that the Company post a fully
collateralized letter of credit on or before May 21, 2010
to cover outstanding customer deposits and residential advance
payments. The Companys current plan is to file for an
amendment to its Retail Energy Provider recertification
applications during the first quarter 2010 and post a letter of
credit to satisfy the rule changes. The amount of deposits
subject to segregation or collateralization at December 31,
2009, was $54 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2009
|
|
2008
|
|
Change
|
|
|
(In millions)
|
|
Net cash provided by operating activities
|
|
$
|
2,106
|
|
|
$
|
1,479
|
|
|
$
|
627
|
|
Net cash used by investing activities
|
|
|
(954
|
)
|
|
|
(672
|
)
|
|
|
(282
|
)
|
Net cash used by financing activities
|
|
|
(343
|
)
|
|
|
(487
|
)
|
|
|
144
|
|
Net Cash
Provided By Operating Activities
For the year ended December 31, 2009, net cash provided by
operating activities increased by $627 million compared to
the same period in 2008, due to:
|
|
|
|
|
Cash generated by Reliant Energy Reliant
Energy contributed approximately $855 million to
the Companys consolidated cash flow from operations
in 2009, primarily reflecting $966 million in
pre-tax income since the May 1, 2009, acquisition
date, adjusted for the non-cash effects of depreciation
and amortization and changes in derivatives.
|
|
|
|
Lower cash flows from Wholesale Power Generation
The Companys cash flow from
operation excluding Reliant Energy was lower by
approximately $228 million in 2009 compared to 2008,
as decreases in generation and power prices impacted
results from operations. In addition, $16 million more
cash was used for working capital in 2009 compared to 2008, as
higher coal inventory balances were partially offset by
$72 million in lower pension contributions.
|
Net Cash
Used By Investing Activities
For the year ended December 31, 2009, net cash used in
investing activities increased by $282 million compared to
the same period in 2008, due to:
|
|
|
|
|
Acquisition of businesses During 2009, the
Company paid $427 million, net of cash acquired
of $6 million, to acquire three businesses.
|
|
|
|
Proceeds from sale of equity method investment and
discontinued operations Net proceeds
from investing activities increased by $43 million in
2009 as compared to 2008 due to the sale of MIBRAG in June
2009 for net proceeds of $284 million compared to the sale
of ITISA for proceeds, net of divested cash, of
$241 million in April 2008.
|
120
|
|
|
|
|
Capital expenditures and loans to affiliates
NRGs capital expenditures decreased by
$165 million due to decreased spending on
RepoweringNRG.
|
|
|
|
Trading of emission allowances Net purchases
and sales of emission allowances resulted in a decrease in
cash of $105 million for 2009 as compared to 2008.
|
Net Cash
Used By Financing Activities
For the year ended December 31, 2009, net cash used by
financing activities decreased by $144 million compared to
the same period in 2008, due to:
|
|
|
|
|
Issuance of debt During 2009, the Company
received $688 million in gross proceeds from the
2019 Senior Notes, $108 million in NRG Connecticut
Peaking financing, $52 million from the Dunkirk
bonds and $19 million from other borrowings. During
2008, the Company received $20 million in
proceeds from borrowings which resulted in a net cash
increase of $872 million.
|
|
|
|
Term Loan Facility debt payment In 2009, the
Company paid down $429 million of its Term
Loan Facility, including the payment of excess cash flow,
as discussed above under Debt Service
Obligations. The Company paid down $174 million of
its Term Loan Facility during 2008 which resulted in a net
cash decrease of $255 million.
|
|
|
|
Other debt payments In November 2009, the
Company paid $181 million to CS for the benefit of
CSF II to unwind the Companys CSF II notes and
preferred interests.
|
|
|
|
Share repurchase During 2009, the Company
repurchased common stock of $500 million as
compared to $185 million in 2008, which resulted in a
net cash decrease of $315 million.
|
NOLs,
Deferred Tax Assets and Uncertain Tax Position Implications,
under ASC-740, Income Taxes, or ASC 740
As of December 31, 2009, the Company had generated total
domestic pre-tax book income of $1.5 billion and foreign
continuing pre-tax book income of $161 million. The Company
has net operating losses for tax return purposes available to
offset taxable income in the current period. The tax return net
operating losses have been classified as capital loss
carryforwards for financial statement purposes and a full
valuation allowance has been established. As of
December 31, 2009, these capital losses have expired for
financial statement purposes. In addition, NRG has cumulative
foreign NOL carryforwards of $280 million, of which
$82 million will expire starting in 2011 through 2017 and
of which $198 million do not have an expiration date.
In addition to these amounts, the Company has $643 million
of tax effected unrecognized tax benefits which relate primarily
to net operating losses for tax return purposes but have been
classified as capital loss carryforwards for financial
statements purposes and for which a full valuation allowance has
been established. As a result of the Companys tax
position, and based on current forecasts, we anticipate income
tax payments of up to $75 million in 2010.
However, as the position remains uncertain for the
$643 million of tax effected unrecognized tax benefits, the
Company has recorded a non-current tax liability of
$347 million and may accrue the remaining balance as an
increase to non-current liabilities until final resolution with
the related taxing authority. The $347 million non-current
tax liability for unrecognized tax benefits is primarily due to
taxable earnings for the period for which there are no NOLs
available to offset for financial statement purposes.
The Company is under examination by the Internal Revenue Service
for years 2004 through 2006. It is possible that the IRS
examination may conclude during 2010 but because of a possible
extension, an estimate of the range of reasonably possible
changes in unrecognized tax benefits cannot be made.
121
Off-Balance
Sheet Arrangements
Obligations
under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee
arrangements in the normal course of business to facilitate
commercial transactions with third parties. These arrangements
include financial and performance guarantees, stand-by letters
of credit, debt guarantees, surety bonds and indemnifications.
See also Item 14 Note 26, Guarantees,
to the Consolidated Financial Statements for additional
discussion.
Retained
or Contingent Interests
NRG does not have any material retained or contingent interests
in assets transferred to an unconsolidated entity.
Derivative
Instrument Obligations
The Companys 3.625% Preferred Stock includes a feature
which is considered an embedded derivative per ASC 815. Although
it is considered an embedded derivative, it is exempt from
derivative accounting as it is excluded from the scope pursuant
to ASC 815. As of December 31, 2009, based on the
Companys stock price, the embedded derivative was
out-of-the-money
and had no redemption value. See also Item 14
Note 15, Capital Structure, to the Consolidated
Financial Statements for additional discussion.
Obligations
Arising Out of a Variable Interest in an Unconsolidated
Entity
Variable interest in Equity investments As of
December 31, 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 Energy
LLC, is a variable interest entity for which NRG is not the
primary beneficiary.
NRGs pro-rata share of non-recourse debt held by
unconsolidated affiliates was approximately $93 million as
of December 31, 2009. This indebtedness may restrict the
ability of these subsidiaries to issue dividends or
distributions to NRG. See also Item 14
Note 16, Investments Accounted for by the Equity Method,
to the Consolidated Financial Statements for additional
discussion.
Letter of Credit Facilities The
Companys $1.3 billion Synthetic Letter of Credit
Facility is unfunded by NRG and is secured by a
$1.3 billion cash deposit at Deutsche Bank AG, New York
Branch that was funded using proceeds from the Term Loan
Facility investors who participated in the facility syndication.
Under the Synthetic Letter of Credit Facility, NRG is allowed to
issue letters of credit for general corporate purposes including
posting collateral to support the Companys commercial
operations activities.
122
Contractual
Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other
commercial commitments that represent prospective cash
requirements in addition to the Companys capital
expenditure programs. The following tables summarize NRGs
contractual obligations and contingent obligations for
guarantee. See also Item 14 Note 12,
Debt and Capital Leases, Note 22, Commitments and
Contingencies, and Note 26, Guarantees , to the
Consolidated Financial Statements for additional discussion.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
|
2009
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2008
|
|
Contractual Cash Obligations
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total(b)
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Long-term debt (including estimated interest)
|
|
$
|
1,074
|
|
|
$
|
1,195
|
|
|
$
|
3,950
|
|
|
$
|
5,171
|
|
|
$
|
11,390
|
|
|
$
|
11,142
|
|
Capital lease obligations (including estimated interest)
|
|
|
28
|
|
|
|
30
|
|
|
|
27
|
|
|
|
107
|
|
|
|
192
|
|
|
|
321
|
|
Operating leases
|
|
|
100
|
|
|
|
120
|
|
|
|
98
|
|
|
|
264
|
|
|
|
582
|
|
|
|
421
|
|
Fuel purchase and transportation
obligations(a)
|
|
|
1,011
|
|
|
|
405
|
|
|
|
140
|
|
|
|
600
|
|
|
|
2,156
|
|
|
|
2,378
|
|
Purchased power
commitments(c)
|
|
|
55
|
|
|
|
56
|
|
|
|
10
|
|
|
|
|
|
|
|
121
|
|
|
|
|
|
Pension minimum funding
requirement(d)
|
|
|
21
|
|
|
|
55
|
|
|
|
56
|
|
|
|
31
|
|
|
|
163
|
|
|
|
194
|
|
Other postretirement benefits minimum funding
requirement(e)
|
|
|
4
|
|
|
|
6
|
|
|
|
8
|
|
|
|
5
|
|
|
|
23
|
|
|
|
19
|
|
Other
liabilities(f)
|
|
|
53
|
|
|
|
75
|
|
|
|
38
|
|
|
|
230
|
|
|
|
396
|
|
|
|
98
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
2,346
|
|
|
$
|
1,942
|
|
|
$
|
4,327
|
|
|
$
|
6,408
|
|
|
$
|
15,023
|
|
|
$
|
14,573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes only those coal
transportation and lignite commitments for 2010 as no other
nominations were made as of December 31, 2009. Natural gas
nomination is through February 2011.
|
(b)
|
|
Excludes $347 million
non-current payable relating to NRGs uncertain tax
benefits under ASC-740 as the period of payment cannot be
reasonably estimated. Also excludes $415 million of asset
retirement obligations which are discussed in
Item 14 Note 13, Asset Retirement
Obligations, to the Consolidated Financial Statements.
|
(c)
|
|
Includes commitments with both
fixed and variable components.
|
(d)
|
|
These amounts represent the
Companys estimated minimum pension contributions required
under the Pension Protection Act of 2006. These amounts
represent estimates that are based on assumptions that are
subject to change. The minimum required contribution for years
after 2015 is currently not available.
|
(e)
|
|
These amounts represent estimates
that are based on assumptions that are subject to change. The
minimum required contribution for years after 2015 are currently
not available.
|
(f)
|
|
Includes water right agreements,
service and maintenance agreements, stadium naming rights and
other contractual obligations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31, 2009
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2008
|
|
Guarantees, Indemnifications and Other Contingent
Obligations
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Synthetic letters of credit
|
|
$
|
531
|
|
|
$
|
186
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
717
|
|
|
$
|
440
|
|
Unfunded standby letters of credit and surety bonds
|
|
|
61
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
97
|
|
|
|
5
|
|
Asset sales guarantee obligations
|
|
|
|
|
|
|
118
|
|
|
|
|
|
|
|
8
|
|
|
|
126
|
|
|
|
129
|
|
Commercial sales arrangements
|
|
|
104
|
|
|
|
44
|
|
|
|
103
|
|
|
|
965
|
|
|
|
1,216
|
|
|
|
1,005
|
|
Other guarantees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
117
|
|
|
|
117
|
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
696
|
|
|
$
|
384
|
|
|
$
|
103
|
|
|
$
|
1,090
|
|
|
$
|
2,273
|
|
|
$
|
1,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value of Derivative Instruments
NRG may enter into long-term power sales contracts, fuel
purchase contracts and other energy-related financial
instruments to mitigate variability in earnings due to
fluctuations in spot market prices and to hedge fuel
requirements at generation facilities. In addition, in order to
mitigate interest rate risk associated with the issuance of the
Companys variable rate and fixed rate debt, NRG enters
into interest rate swap agreements.
123
NRGs trading activities 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.
The tables below disclose the activities that include both
exchange and non-exchange traded contracts accounted for at fair
value in accordance with ASC 820, Fair Value Measurements and
Disclosures, or ASC 820. Specifically, these tables
disaggregate realized and unrealized changes in fair value;
disaggregate estimated fair values at December 31, 2009,
based on their level within the fair value hierarchy defined in
ASC 820; and indicate the maturities of contracts at
December 31, 2009. Also, in connection with the
Companys acquisition of Reliant Energy, NRG acquired
retail load and supply contracts. The tables below also includes
the fair value of these contracts receiving
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
|
|
|
(432
|
)
|
Contracts acquired in conjunction with Reliant Energy
|
|
|
(1,054
|
)
|
Changes in fair value
|
|
|
949
|
|
|
|
|
|
|
Fair value of contracts as of December 31, 2009
|
|
$
|
459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of December 31, 2009
|
|
|
|
Maturity
|
|
|
|
|
|
|
|
|
Maturity
|
|
|
|
|
|
|
Less Than
|
|
|
Maturity
|
|
|
Maturity
|
|
|
in Excess
|
|
|
Total Fair
|
|
Fair value hierarchy Gains/(Losses)
|
|
1 Year
|
|
|
1-3 Years
|
|
|
4-5 Years
|
|
|
4-5 Years
|
|
|
Value
|
|
|
|
(In millions)
|
|
|
Level 1
|
|
$
|
25
|
|
|
$
|
(13
|
)
|
|
$
|
(24
|
)
|
|
$
|
|
|
|
$
|
(12
|
)
|
Level 2
|
|
|
159
|
|
|
|
234
|
|
|
|
118
|
|
|
|
(27
|
)
|
|
|
484
|
|
Level 3
|
|
|
(21
|
)
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
|
|
(13
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
163
|
|
|
$
|
228
|
|
|
$
|
95
|
|
|
$
|
(27
|
)
|
|
$
|
459
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A small portion of NRGs contracts are exchange-traded
contracts with readily available quoted market prices. The
majority of NRGs contracts are non-exchange-traded
contracts valued using prices provided by external sources,
primarily price quotations available through brokers or
over-the-counter
and on-line exchanges. For the majority of NRG markets, the
Company receives quotes from multiple sources. To the extent
that NRG receives multiple quotes, the Companys prices
reflect the average of the bid-ask mid-point prices obtained
from all sources that NRG believes provide the most liquid
market for the commodity. If the Company receives one quote then
the mid point of the bid-ask spread for that quote is used. The
terms for which such price information is available vary by
commodity, region and product. A significant portion of the fair
value of the Companys derivative portfolio is based on
price quotes from brokers in active markets who regularly
facilitate the Companys transactions and the Company
believes such price quotes are executable. The Company does not
use third party sources that derive price based on proprietary
models or market surveys. The remainder of the assets and
liabilities represent contracts for which external sources or
observable market quotes are not available. These contracts are
valued based on various valuation techniques including but not
limited to internal models based on a fundamental analysis of
the market and extrapolation of observable market data with
similar characteristics. Contracts valued with prices provided
by models and other valuation techniques make up 3% of the total
fair value of all derivative contracts. The fair value of each
contract is discounted using a risk free interest rate. In
addition, the Company applies a credit reserve to reflect credit
risk which is calculated based on published default
probabilities. To the extent that NRGs net exposure after
cash collateral paid/received under a specific master agreement
is an asset, the Company calculates credit reserve applying the
counterpartys default swap rate. If the net exposure after
cash collateral paid/received under a specific master agreement
is a liability, the Company calculates credit reserve applying
NRGs default swap rate. The credit reserve is added to the
discounted fair value to reflect the exit price that a market
participant would be willing to receive to assume NRGs
liabilities or that a market participant would be willing to pay
for NRGs assets. As of December 31, 2009, the credit
reserve resulted in a $1 million increase in fair value
which is composed of a $1 million loss in OCI and a
$2 million gain in derivative revenue and cost of
operations.
124
The fair values in each category reflect the level of forward
prices and volatility factors as of December 31, 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.
The Company has elected to disclose derivative assets and
liabilities on a
trade-by-trade
basis and does not offset amounts at the counterparty master
agreement level. Also, collateral received or paid on the
Companys derivative assets or liabilities are recorded on
a separate line item on the balance sheet. Consequently, the
magnitude of the changes in individual current and non-current
derivative assets or liabilities is higher than the underlying
credit and market risk of the Companys portfolio. As
discussed in Item 6A Commodity Price
Risk, NRG measures the sensitivity of the Companys
portfolio to potential changes in market prices using Value at
Risk, or VaR, a statistical model which attempts to predict risk
of loss based on market price and volatility. NRGs risk
management policy places a limit on
one-day
holding period VaR, which limits the Companys net open
position. As the Companys
trade-by-trade
derivative accounting results in a
gross-up of
the Companys derivative assets and liabilities, the net
derivative assets and liability position is a better indicator
of NRGs hedging activity. As of December 31, 2009,
NRGs net derivative asset was $459 million, a
decrease to total fair value of $537 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 as well as the roll-off of trades that settled during the
period.
Based on a sensitivity analysis using simplified assumptions,
the impact of a $1 per MMBtu increase or decrease in natural gas
prices across the term of the derivative contracts would cause a
change of approximately $489 million in the net value of
derivatives as of December 31, 2009.
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. Any
effects on the Companys business, financial position or
results of operations resulting from revisions to these
estimates are recorded in the period in which the facts that
give rise to the revision become known.
NRGs significant accounting policies are summarized in
Item 14 Note 2, Summary of Significant
Accounting Policies, to the Consolidated Financial
Statements. The Company identifies its most critical accounting
policies as those that are the most pervasive and important to
the portrayal of the Companys
125
financial position and results of operations, and that require
the most difficult, subjective
and/or
complex judgments by management regarding estimates about
matters that are inherently uncertain.
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Accounting Policy
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Judgments/Uncertainties Affecting Application
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Derivative Instruments
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Assumptions used in valuation techniques
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Assumptions used in forecasting generation
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Market maturity and economic conditions
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Contract interpretation
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Market conditions in the energy industry, especially the effects
of price volatility on contractual commitments
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Income Taxes and Valuation Allowance for
Deferred Tax Assets
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Ability to withstand legal challenges of tax authority decisions
or appeals
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Anticipated future decisions of tax authorities
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Application of tax statutes and regulations to transactions
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Ability to utilize tax benefits through carry backs to prior
periods and carry forwards to future periods
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Impairment of Long Lived Assets
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|
Recoverability of investment through future operations
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Regulatory and political environments and requirements
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Estimated useful lives of assets
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Environmental obligations and operational limitations
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Estimates of future cash flows
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Estimates of fair value
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Judgment about triggering events
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Goodwill and Other Intangible Assets
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Estimated useful lives for finite-lived intangible assets
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Judgment about impairment triggering events
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Estimates of reporting units fair value
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Fair value estimate of intangible assets acquired in business
combinations
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Contingencies
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Estimated financial impact of event(s)
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Judgment about likelihood of event(s) occurring
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Regulatory and political environments and requirements
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Accrued Unbilled Revenues of Reliant Energy
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Estimates of unbilled volumes
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Derivative
Instruments
The Company follows the guidance of ASC 815, to account for
derivative instruments. ASC 815 requires the Company to
mark-to-market
all derivative instruments on the balance sheet, and recognize
changes in the fair value of non-hedge derivative instruments
immediately in earnings. In certain cases, NRG may apply hedge
accounting to the Companys derivative instruments. The
criteria used to determine if hedge accounting treatment is
appropriate are: (i) the designation of the hedge to an
underlying exposure; (ii) whether the overall risk is being
reduced; and (iii) if there is a correlation between the
fair value of the derivative instrument and the underlying
hedged item. Changes in the fair value of derivatives
instruments accounted for as hedges are either recognized in
earnings as an offset to the changes in the fair value of the
related hedged item, or deferred and recorded as a component of
OCI, and subsequently recognized in earnings when the hedged
transactions occur.
126
For purposes of measuring the fair value of derivative
instruments, NRG uses quoted exchange prices and broker quotes.
When external prices are not available, NRG uses internal models
to determine the fair value. These internal models include
assumptions of the future prices of energy commodities based on
the specific market in which the energy commodity is being
purchased or sold, using externally available forward market
pricing curves for all periods possible under the pricing model.
In order to qualify derivative instruments for hedged
transactions, NRG estimates the forecasted generation occurring
within a specified time period. Judgments related to the
probability of forecasted generation occurring are based on
available baseload capacity, internal forecasts of sales and
generation, and historical physical delivery on similar
contracts. The probability that hedged forecasted generation
will occur by the end of a specified time period could change
the results of operations by requiring amounts currently
classified in OCI to be reclassified into earnings, creating
increased variability in the Companys earnings. These
estimations are considered to be critical accounting estimates.
Certain derivative instruments that meet the criteria for
derivative accounting treatment also qualify for a scope
exception to derivative accounting, as they are considered NPNS.
The availability of this exception is based upon the assumption
that NRG has the ability and it is probable to deliver or take
delivery of the underlying item. These assumptions are based on
available baseload capacity, internal forecasts of sales and
generation and historical physical delivery on contracts.
Derivatives that are considered to be NPNS are exempt from
derivative accounting treatment, and are accounted for under
accrual accounting. If it is determined that a transaction
designated as NPNS no longer meets the scope exception due to
changes in estimates, the related contract would be recorded on
the balance sheet at fair value combined with the immediate
recognition through earnings.
Income
Taxes and Valuation Allowance for Deferred Tax
Assets
As of December 31, 2009, NRG had a valuation allowance of
$233 million. This amount is comprised of
U.S. domestic capital loss carryforwards and
non-depreciable property of $154 million, foreign net
operating loss carryforwards of $78 million and foreign
capital loss carryforwards of approximately $1 million. In
assessing the recoverability of NRGs deferred tax assets,
the Company considers whether it is more likely than not that
some portion or all of the deferred tax assets will be realized.
The ultimate realization of deferred tax assets is dependent
upon projected capital gains and available tax planning
strategies.
NRG continues to be under audit for multiple years by taxing
authorities in other jurisdictions. Considerable judgment is
required to determine the tax treatment of a particular item
that involves interpretations of complex tax laws. NRG is
subject to examination by taxing authorities for income tax
returns filed in the U.S. federal jurisdiction and various
state and foreign jurisdictions including major operations
located in Germany and Australia. The Company is no longer
subject to U.S. federal income tax examinations for years
prior to 2002. With few exceptions, state and local income tax
examinations are no longer open for years before 2003. The
Companys significant foreign operations are also no longer
subject to examination by local jurisdictions for years prior to
2000.
Evaluation
of Assets for Impairment and Other Than Temporary Decline in
Value
In accordance with ASC-360, Property, Plant, and
Equipment, or ASC 360, NRG evaluates property, plant and
equipment and certain intangible assets for impairment whenever
indicators of impairment exist. Examples of such indicators or
events are:
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Significant decrease in the market price of a long-lived asset;
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Significant adverse change in the manner an asset is being used
or its physical condition;
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Adverse business climate;
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Accumulation of costs significantly in excess of the amount
originally expected for the construction or acquisition of an
asset;
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Current-period loss combined with a history of losses or the
projection of future losses; and
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Change in the Companys intent about an asset from an
intent to hold to a greater than 50% likelihood that an asset
will be sold or disposed of before the end of its previously
estimated useful life.
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Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of the assets to the future
net cash flows expected to be generated by the asset, through
considering project specific assumptions for long-term power
pool prices, escalated future project operating costs and
expected plant operations. If such
127
assets are considered to be impaired, the impairment to be
recognized is measured by the amount by which the carrying
amount of the assets exceeds the fair value of the assets by
factoring in the probability weighting of different courses of
action available to the Company. Generally, fair value will be
determined using valuation techniques such as the present value
of expected future cash flows. NRG uses its best estimates in
making these evaluations and considers various factors,
including forward price curves for energy, fuel costs and
operating costs. However, actual future market prices and
project costs could vary from the assumptions used in the
Companys estimates, and the impact of such variations
could be material.
For assets to be held and used, if the Company determines that
the undiscounted cash flows from the asset are less than the
carrying amount of the asset, NRG must estimate fair value to
determine the amount of any impairment loss. Assets
held-for-sale
are reported at the lower of the carrying amount or fair value
less the cost to sell. The estimation of fair value under ASC
360, whether in conjunction with an asset to be held and used or
with an asset
held-for-sale,
and the evaluation of asset impairment are, by their nature
subjective. NRG considers quoted market prices in active markets
to the extent they are available. In the absence of such
information, the Company may consider prices of similar assets,
consult with brokers, or employ other valuation techniques. NRG
will also discount the estimated future cash flows associated
with the asset using a single interest rate representative of
the risk involved with such an investment or employ an expected
present value method that probability-weights a range of
possible outcomes. The use of these methods involves the same
inherent uncertainty of future cash flows as previously
discussed with respect to undiscounted cash flows. Actual future
market prices and project costs could vary from those used in
the Companys estimates, and the impact of such variations
could be material.
For the years ended December 31, 2008, and 2007, there were
reductions of $23 million and $11 million,
respectively, in income from continuing operation due to
impairment of an investment in commercial paper. The Company
recorded these impairments as a reduction to interest income.
There were no impairment charges on this investment in 2009.
NRG is also required to evaluate its equity-method and
cost-method investments to determine whether or not they are
impaired. ASC-323, Investments-Equity Method and Joint
Ventures, or ASC 323, provides the accounting requirements
for these investments. The standard for determining whether an
impairment must be recorded under ASC 323 is whether the value
is considered an other than a temporary decline in
value. The evaluation and measurement of impairments under ASC
323 involves the same uncertainties as described for long-lived
assets that the Company owns directly and accounts for in
accordance with ASC 360. Similarly, the estimates that NRG makes
with respect to its equity and cost-method investments are
subjective, and the impact of variations in these estimates
could be material. Additionally, if the projects in which the
Company holds these investments recognize an impairment under
the provisions of ASC 360, NRG would record its proportionate
share of that impairment loss and would evaluate its investment
for an other than temporary decline in value under ASC 323.
Goodwill
and Other Intangible Assets
As part of the acquisition of Texas Genco in 2006, NRG recorded
goodwill and intangible assets at its Texas segment reporting
unit. The Company also recorded intangible assets in connection
with the Reliant Energy acquisition in 2009, measured primarily
based on significant inputs that are not observable in the
market and thus represent a Level 3 measurement as defined
in ASC 820. See Item 14 Note 3,
Business Acquisitions, to the Consolidated Financial
Statements for a discussion of the Reliant Energy acquisition
fair value measurements. The Company applied ASC 805,
Business Combinations, or ASC 805, and ASC 350,
Intangibles Goodwill and Other, or ASC 350,
to account for its goodwill and intangible assets. Under these
standards, the Company amortizes all finite-lived intangible
assets over their respective estimated weighted-average useful
lives, while goodwill has an indefinite life and is not
amortized. However, goodwill and all intangible assets not
subject to amortization are tested for impairments at least
annually, or more frequently whenever an event or change in
circumstances occurs that would more likely than not reduce the
fair value of a reporting unit below its carrying amount. The
Company tests goodwill for impairment at the reporting unit
level, which is identified by assessing whether the components
of the Companys operating segments constitute businesses
for which discrete financial information is available and
whether segment management regularly reviews the operating
results of those components. If it is determined that the fair
value of a reporting unit is below its carrying amount, where
necessary the Companys goodwill
and/or
intangible asset with indefinite lives will be impaired at that
time.
128
The Company performed its annual goodwill impairment assessment
as of December 31, 2009, for its Texas reporting unit, or
NRG Texas, which is at the operating segment level. The Company
determined the fair value of this reporting unit using primarily
an income approach and then applied an overall market approach
reasonableness test to reconcile that fair value with NRGs
overall market capitalization. Significant inputs to the
determination of fair value were as follows:
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|
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For the three solid-fuel baseload plants that drive a majority
of the value in the reporting unit, and for the regions
Elbow Creek, Langford and Cedar Bayou facilities that recently
commenced operations, the Company applied a discounted cash flow
methodology to their long-term budgets in accordance with the
guidance in paragraphs B152 and B155 of SFAS 142. This
approach is consistent with that used to determine fair value at
December 31, 2008 and 2007. These budgets are based on the
Companys views of power and fuel prices, which consider
market prices in the near term and the Companys
fundamental view for the longer term as some relevant market
prices are illiquid beyond 24 months. Hedging is included
to the extent of contracts already in place. Projected
generation in the long-term budgets is based on
managements estimate of supply and demand within the
sub-markets
for each plant and the physical and economic characteristics of
each plant;
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|
For the reporting units remaining gas plants, the Company
applied a market-derived earnings multiple to the gas
plants aggregate estimated 2009 earnings before interest,
taxes, depreciation and amortization, in accordance with the
guidance in ASC-350-20-35-24. This approach is consistent with
that used to determine fair values at December 31, 2008 and
2007;
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|
|
The potential impact of carbon legislation was estimated using a
discounted cash flow methodology applied to the Companys
view of the impact of potential legislation that is based on
recent proposals to Congress.
|
If fair value of a reporting unit exceeds its carrying value,
goodwill of the reporting unit is not considered impaired. Under
the income approach described above, the Company estimated the
fair value of NRG Texas invested capital to exceed its
carrying value by approximately 25% at December 31, 2009.
This estimate of fair value is affected by assumptions about
projected power prices, generation, fuel costs, capital
expenditure requirements and environmental regulations, and the
Company believes that the most significant impact arises from
future power prices. Assuming all other factors are held
constant, a hypothetical $1 drop in the Companys long-term
natural gas price view would not have caused the fair value of
NRG Texas to fall below its carrying value at December 31,
2009.
To reconcile the fair value determined under the income approach
with NRGs market capitalization, the Company considered
historical and future budgeted earnings measures to estimate the
average percentage of total company value represented by NRG
Texas, and applied this percentage to an adjusted business
enterprise value of NRG. To derive this adjusted business
enterprise value, the Company applied a range of control
premiums based on recent market transactions to the business
enterprise value of NRG on a non-controlling, marketable basis,
and also made adjustments for some non-operating assets and for
some of the significant factors that impact NRG differently from
NRG Texas, such as environmental capital expenditures outside of
the Texas region, or limitations on the Companys Capital
Allocation Plans under NRGs debt. The Company was able to
reconcile the proportional value of NRG Texas to NRGs
market capitalization at a value that would not indicate an
impairment.
Contingencies
NRG records a loss contingency when management determines it is
probable that a liability has been incurred and the amount of
the loss can be reasonably estimated. Gain contingencies are not
recorded until management determines it is certain that the
future event will become or does become a reality. Such
determinations are subject to interpretations of current facts
and circumstances, forecasts of future events, and estimates of
the financial impacts of such events. NRG describes in detail
its contingencies in Item 14 Note 22,
Commitments and Contingencies, to the Consolidated
Financial Statements.
129
Accrued
Unbilled Revenues
Accrued unbilled revenues related to the Reliant Energy segment
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 were
$308 million as of December 31, 2009, which represents
3% of the Companys consolidated revenues for the year
ended December 31, 2009, and 7% of Reliant Energys
revenues for the eight-month period ended December 31,
2009. 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.
Recent
Accounting Developments
See Item 14 Note 2, Summary of
Significant Accounting Policies, to the Consolidated
Financial Statements for a discussion of recent accounting
developments.
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Item 6A
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Quantitative
and Qualitative Disclosures about Market Risk
|
NRG is exposed to several market risks in the Companys
normal business activities. Market risk is the potential loss
that may result from market changes associated with the
Companys merchant power generation or with an existing or
forecasted financial or commodity transaction. The types of
market risks the Company is exposed to are commodity price risk,
interest rate risk and currency exchange risk. In order to
manage these risks the Company uses various fixed-price forward
purchase and sales contracts, futures and option contracts
traded on the New York Mercantile Exchange, and swaps and
options traded in the
over-the-counter
financial markets to:
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Manage and hedge fixed-price purchase and sales commitments;
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Manage and hedge exposure to variable rate debt obligations;
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Reduce exposure to the volatility of cash market prices, and
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Hedge fuel requirements for the Companys generating
facilities.
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Commodity
Price Risk
Commodity price risks result from exposures to changes in spot
prices, forward prices, volatility in commodities, and
correlations between various commodities, such as natural gas,
electricity, coal, oil, and emissions credits. A number of
factors influence the level and volatility of prices for energy
commodities and related derivative products. These factors
include:
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|
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Seasonal, daily and hourly changes in demand;
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|
|
Extreme peak demands due to weather conditions;
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Available supply resources;
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Transportation availability and reliability within and between
regions; and
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Changes in the nature and extent of federal and state
regulations.
|
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 of electricity and purchases
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
markets. The portion of forecasted transactions hedged may vary
based upon managements assessment of market, weather,
operation and other factors.
While some of the contracts the Company uses to manage risk
represent commodities or instruments for which prices are
available from external sources, other commodities and certain
contracts are not actively traded and are valued using other
pricing sources and modeling techniques to determine expected
future market prices, contract quantities, or both. NRG uses the
Companys best estimates to determine the fair value of
those derivative contracts.
130
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 VaR. VaR is
a statistical model that attempts to predict risk of loss based
on market price and volatility. Currently, the company estimates
VaR using a Monte Carlo simulation based methodology.
NRG uses a diversified VaR model to calculate an estimate of the
potential loss in the fair value of the Companys energy
assets and liabilities, which includes generation assets, load
obligations, and bilateral physical and financial transactions.
The key assumptions for the Companys diversified model
include: (i) a lognormal distribution of prices;
(ii) one-day
holding period; (iii) a 95% confidence interval;
(iv) a rolling
36-month
forward looking period; and (v) market implied volatilities
and historical price correlations.
As of December 31, 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 $38 million.
The following table summarizes average, maximum and minimum VaR
for NRG for the year ended December 31, 2009, and 2008:
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VaR
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|
In millions
|
As of December 31, 2009
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$
|
38
|
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Average
|
|
|
41
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Maximum
|
|
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55
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Minimum
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|
|
28
|
|
As of December 31, 2008
|
|
$
|
43
|
|
Average
|
|
|
50
|
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Maximum
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65
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Minimum
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|
35
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Due to the inherent limitations of statistical measures such as
VaR, the evolving nature of the competitive markets for
electricity and related derivatives, and the seasonality of
changes in market prices, the VaR calculation may not capture
the full extent of commodity price exposure. As a result, actual
changes in the fair value of
mark-to-market
energy assets and liabilities could differ from the calculated
VaR, and such changes could have a material impact on the
Companys financial results.
In order to provide additional information for comparative
purposes to NRGs peers, the Company also uses VaR to
estimate the potential loss of derivative financial instruments
that are subject to
mark-to-market
accounting. These derivative instruments include transactions
that were entered into for both asset management and trading
purposes. The VaR for the derivative financial instruments
calculated using the diversified VaR model as of
December 31, 2009, for the entire term of these instruments
entered into for both asset management and trading, was
$24 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
131
counterparties are made monthly and the LIBOR is determined in
advance of each interest period. The total notional amount of
these swaps, which mature on February 1, 2013, is
$900 million.
In 2006, the Company entered into a series of interest rate
swaps which are intended to hedge the risk associated with
floating interest rates. For each of the interest rate swaps,
NRG pays its counterparty the equivalent of a fixed interest
payment on a predetermined notional value, and NRG receives the
equivalent of a floating interest payment based on a
3-month
LIBOR rate calculated on the same notional value. All interest
rate swap payments by NRG and its counterparties are made
quarterly, and the LIBOR is determined in advance of each
interest period. While the notional value of each of the swaps
does not vary over time, the swaps are designed to mature
sequentially. The total notional amount of these swaps as of
December 31, 2009, was $1.7 billion. The maturities
and notional amounts of each tranche of these swaps in
connection with the Senior Credit Facility are as follows:
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|
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Maturity
|
|
Notional Value
|
|
March 31, 2010
|
|
$
|
190 million
|
|
March 31, 2011
|
|
$
|
1.55 billion
|
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In addition to those discussed above, the Company had the
following additional interest rate swaps outstanding as of
December 31, 2009:
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Notional Value
|
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Maturity
|
|
|
Floating to fixed interest rate swap for NRG Peaker Financing LLC
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|
$
|
251 million
|
|
|
|
June 10, 2019
|
|
Fixed to floating interest rate swap for Senior Notes, due 2014
|
|
$
|
400 million
|
|
|
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December 15, 2013
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If all of the above swaps had been discontinued on
December 31, 2009, the Company would have owed the
counterparties $104 million. Based on the investment grade
rating of the counterparties, NRG believes its exposure to
credit risk due to nonperformance by counterparties to its hedge
contracts to be insignificant.
NRG has both long and short-term debt instruments that subject
the Company to the risk of loss associated with movements in
market interest rates. As of December 31, 2009, a 1% change
in interest rates would result in a $10 million change in
interest expense on a rolling twelve month basis.
As of December 31, 2009, the Companys long-term debt
fair value was $8.2 billion and the carrying amount was
$8.3 billion. NRG estimates that a 1% decrease in market
interest rates would have increased the fair value of the
Companys long-term debt by $415 million.
Liquidity
Risk
Liquidity risk arises from the general funding needs of
NRGs activities and in the management of the
Companys assets and liabilities. NRGs liquidity
management framework is intended to maximize liquidity access
and minimize funding costs. Through active liquidity management,
the Company seeks to preserve stable, reliable and
cost-effective sources of funding. This enables the Company to
replace maturing obligations when due and fund assets at
appropriate maturities and rates. To accomplish this task,
management uses a variety of liquidity risk measures that take
into consideration market conditions, prevailing interest rates,
liquidity needs, and the desired maturity profile of liabilities.
Based on a sensitivity analysis for power and gas positions
under marginable contracts, a $1 per MMBtu change in natural gas
prices across the term of the marginable contracts would cause a
change in margin collateral posted of approximately
$128 million as of December 31, 2009, and a
0.25 MMBtu/MWh change in heat rates for heat rate positions
would result in a change in margin collateral posted of
approximately $51 million as of December 31, 2009.
This analysis uses simplified assumptions and is calculated
based on portfolio composition and margin-related contract
provisions as of December 31, 2009. Currently, NRG is
exposed to additional margin if natural gas prices decrease.
Under the second lien, NRG is required to post certain letter of
credits as credit support for changes in commodity prices. As of
December 31, 2009, no letters of credit are outstanding to
second lien counterparties. With changes in commodity prices,
the letters of credit could grow to $64 million, the cap
under the agreements.
132
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, prepayment arrangements, or
volumetric limits; (iv) the use of payment netting
agreements; and (v) the use of master netting agreements
that allow for the netting of positive and negative exposures of
various contracts associated with a single counterparty. Risks
surrounding counterparty performance and credit could ultimately
impact the amount and timing of expected cash flows. The Company
seeks to mitigate counterparty risk with a diversified portfolio
of counterparties, including nine participants under its first
and second lien structure. The Company also has credit
protection within various agreements to call on additional
collateral support if and when necessary. Cash margin is
collected and held at NRG to cover the credit risk of the
counterparty until positions settle.
As of December 31, 2009, total credit exposure to
substantially all wholesale counterparties was $1.3 billion
and NRG held collateral (cash and letters of credit) against
those positions of $186 million resulting in a net exposure
of $1.1 billion. Total credit exposure is discounted at the
risk free rate.
The following table highlights the credit quality and the net
counterparty credit exposure by industry sector. Net
counterparty credit risk is defined as the aggregate net asset
position for NRG with counterparties where netting is permitted
under the enabling agreement and includes all cash flow,
mark-to-market
and NPNS, and non-derivative transactions. The exposure is shown
net of collateral held, and includes amounts net of receivables
or payables.
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
Financial institutions
|
|
|
69
|
%
|
Utilities, energy merchants, marketers and other
|
|
|
25
|
|
Coal suppliers
|
|
|
3
|
|
ISOs
|
|
|
3
|
|
|
|
|
|
|
Total as of December 31, 2009
|
|
|
100
|
%
|
|
|
|
|
|
|
|
Net
Exposure(a)
|
|
Category
|
|
(% of Total)
|
|
Investment grade
|
|
|
90
|
%
|
Non-rated
|
|
|
8
|
|
Non- Investment grade
|
|
|
2
|
|
|
|
|
|
|
Total as of December 31, 2009
|
|
|
100
|
%
|
|
|
|
(a)
|
|
Credit exposure excludes California
tolling, uranium, coal transportation/railcar leases, New
England RMR, certain cooperative load contracts and Texas
Westmoreland coal contracts. The aforementioned exposures were
excluded for various reasons including regulatory support 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.
|
NRG has credit risk exposure to certain wholesale counterparties
representing more than 10% of total net exposure and the
aggregate of such counterparties was $351 million.
Approximately 82% of NRGs positions relating to credit
risk roll-off by the end of 2012. Changes in hedge positions and
market prices will affect credit exposure and counterparty
concentration. Given the credit quality, diversification and
term of the exposure in the portfolio, NRG does not anticipate a
material impact on the Companys financial position or
results of operations from nonperformance by any of NRGs
counterparties.
NRG is exposed to retail credit risk through its competitive
electricity supply business, which serves C&I customers and
the Mass market in Texas. Retail credit risk results when a
customer fails to pay for services rendered. The losses could be
incurred from nonpayment of customer accounts receivable and any
in-the-money
forward value. NRG manages retail credit risk through the use of
established credit policies that include monitoring of the
portfolio, and the use of credit mitigation measures such as
deposits or prepayment arrangements.
133
As of December 31, 2009, the Companys credit exposure
to C&I customers was diversified across many customers and
various industries. No one customer represented more than 2% of
total exposure and the majority of the customers have investment
grade credit quality, as determined by NRG.
NRG is also exposed to credit risk relating to its
1.5 million Mass customers, which may result in a write-off
of a bad debt. The current economic conditions may affect the
Companys customers ability to pay bills in a timely
manner, which could increase customer delinquencies and may lead
to an increase in bad debt expense.
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. The collateral required for
out-of-the-money
positions and net accounts payable for contracts that have
adequate assurance clauses that are in a net liability position
as of December 31, 2009, was $80 million. The
collateral required for
out-of-the-money
positions and net accounts payable for contracts with credit
rating contingent features that are in a net liability position
as of December 31, 2009, was $49 million. The Company
is also a party to certain marginable agreements where NRG has a
net liability position but the counterparty has not called for
the collateral due, which is approximately $3 million as of
December 31, 2009.
Currency
Exchange Risk
NRG may be subject to foreign currency risk as a result of the
Company entering into purchase commitments with foreign vendors
for the purchase of major equipment associated with
RepoweringNRG initiatives. To reduce the risks to such
foreign currency exposure, the Company may enter into
transactions to hedge its foreign currency exposure using
currency options and forward contracts. At December 31,
2009, no foreign currency options and forward contracts were
outstanding.
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 year ended
December 31, 2009, NRG recorded an exchange loss of
$24 million on the contract within Other
income/(loss), net.
As a result of the Companys limited foreign currency
exposure to date, the effect of foreign currency fluctuations
has not been material to the Companys results of
operations, financial position and cash flows.
The effects of a hypothetical simultaneous 10% appreciation in
the U.S. dollar from year-end 2008 levels against all other
currencies of countries in which the Company has continuing
operations would result in an immaterial impact to NRGs
consolidated statements of operations and approximately
$79 million in pre-tax unrealized income reflected in the
currency translation adjustment component of OCI.
|
|
Item 7
|
Financial
Statements and Supplementary Data
|
The financial statements and schedules are listed in
Part IV, Item 14 of this
Form 10-K.
|
|
Item 8
|
Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosures
|
None.
|
|
Item 8A
|
Controls
and Procedures
|
Conclusion
Regarding the Effectiveness of Disclosure Controls and
Procedures
Under the supervision and with the participation of NRGs
management, including its principal executive officer, principal
financial officer and principal accounting officer, NRG
conducted an evaluation of the effectiveness of the design and
operation of its disclosure controls and procedures, as such
term is defined in
Rules 13a-15(e)
or 15d-15(e)
of the Securities Exchange Act of 1934, as amended, or the
Exchange Act. Based on this evaluation, the Companys
principal executive officer, principal financial officer and
principal accounting
134
officer concluded that the disclosure controls and procedures
were effective as of the end of the period covered by this
annual report on
Form 10-K.
Managements report on the Companys internal control
over financial reporting and the report of the Companys
independent registered public accounting firm are incorporated
under the caption Managements Report on Internal
Control over Financial Reporting and under the caption
Report of Independent Registered Public Accounting
Firm, of the Companys 2009 Annual Report to
Shareholders.
Changes
in Internal Control over Financial Reporting
There were no changes in the Companys internal control
over financial reporting (as such term is defined in
Rule 13a-15(f)
under the Exchange Act) that occurred in the fourth quarter of
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. The Companys
internal control over financial reporting includes those
policies and procedures that:
|
|
|
|
1.
|
Pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and
dispositions of our assets;
|
|
|
2.
|
Provide reasonable assurance that transactions are recorded as
necessary to permit preparation of consolidated financial
statements in accordance with generally accepted accounting
principles, and that our receipts and expenditures are being
made only in accordance with authorizations of our management
and directors; and
|
|
|
3.
|
Provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use or disposition of our
assets that could have a material effect on the consolidated
financial statements.
|
Internal control over financial reporting cannot provide
absolute assurance of achieving financial reporting objectives
because of its inherent limitations, including the possibility
of human error and circumvention by collusion or overriding of
controls. Accordingly, even an effective internal control system
may not prevent or detect material misstatements on a timely
basis. Also, projections of any evaluation of effectiveness to
future periods are subject to the risk that controls may become
inadequate because of changes in conditions or that the degree
of compliance with the policies or procedures may deteriorate.
|
|
Item 8B
|
Other
Information
|
None.
135
PART III
|
|
Item 9
|
Directors,
Executive Officers and Corporate Governance
|
NRG Energy, Inc. has adopted a code of ethics entitled NRG
Code of Conduct that applies to directors, officers and
employees, including the chief executive officer and senior
financial officers of NRG Energy, Inc. It may be accessed
through the Corporate Governance section of NRG Energy
Inc.s website at
http://www.nrgenergy.com/investor/corpgov.htm.
NRG Energy, Inc. also elects to disclose the information
required by
Form 8-K,
Item 5.05, Amendments to the registrants code
of ethics, or waiver of a provision of the code of ethics,
through the Companys website, and such information will
remain available on this website for at least a
12-month
period. A copy of the NRG Energy, Inc. Code of
Conduct is available in print to any shareholder who
requests it.
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
definitive Proxy Statement for its 2010 Annual Meeting of
Stockholders.
|
|
Item 10
|
Executive
Compensation
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
Definitive Proxy Statement for its 2010 Annual Meeting of
Stockholders.
|
|
Item 11
|
Security
Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
Definitive Proxy Statement for its 2010 Annual Meeting of
Stockholders.
|
|
Item 12
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
Definitive Proxy Statement for its 2010 Annual Meeting of
Stockholders.
|
|
Item 13
|
Principal
Accounting Fees and Services
|
Other information required by this Item will be incorporated by
reference to the similarly named section of NRGs
Definitive Proxy Statement for its 2010 Annual Meeting of
Stockholders.
136
PART IV
|
|
Item 14
|
Exhibits
and Financial Statement Schedules
|
(a)(1) Financial Statements
|
|
|
The following consolidated financial statements of NRG Energy,
Inc. and related notes thereto, together with the reports
thereon of KPMG LLP are included herein:
|
|
|
Consolidated Statements of Operations Years ended
December 31, 2009, 2008 and 2007
|
|
|
Consolidated Balance Sheets December 31, 2009
and 2008
|
|
|
Consolidated Statements of Cash Flows Years ended
December 31, 2009, 2008 and 2007
|
|
|
Consolidated Statement of Stockholders Equity and
Comprehensive Income/(Loss) Years ended
December 31, 2009, 2008 and 2007
|
|
|
Notes to Consolidated Financial Statements
|
(a)(2) Financial Statement Schedule
|
|
|
The following Consolidated Financial Statement Schedule of NRG
Energy, Inc. is filed as part of Item 14(d) of this report
and should be read in conjunction with the Consolidated
Financial Statements.
|
|
|
Schedule II Valuation and Qualifying Accounts
|
|
|
All other schedules for which provision is made in the
applicable accounting regulation of the Securities and Exchange
Commission are not required under the related instructions or
are inapplicable, and therefore, have been omitted.
|
(a)(3) Exhibits: See Exhibit Index submitted as a
separate section of this report.
(b) Exhibits
|
|
|
See Exhibit Index submitted as a separate section of this
report.
|
(c) Not applicable
137
MANAGEMENTS
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
NRG Energy Inc.s management is responsible for
establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act
Rule 13a-15(f).
Under the supervision and with the participation of the
Companys management, including its principal executive
officer, principal financial officer and principal accounting
officer, the Company conducted an evaluation of the
effectiveness of its internal control over financial reporting
based on the framework in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on the
Companys evaluation under the framework in Internal
Control Integrated Framework, the Companys
management concluded that its internal control over financial
reporting was effective as of December 31, 2009.
The effectiveness of the Companys internal control over
financial reporting as of December 31, 2009 has been
audited by KPMG LLP, the Companys independent registered
public accounting firm, as stated in its report which is
included in this
Form 10-K.
138
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited NRG Energy, Inc.s internal control over
financial reporting as of December 31, 2009, based on
criteria established in Internal Control Integrated
Framework issued by the Committee of Sponsoring Organizations of
the Treadway Commission (COSO). NRG Energy, Inc.s
management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting,
included in the accompanying Managements Report on
Internal Control over Financial Reporting. Our responsibility is
to express an opinion on the Companys internal control
over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control
over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of
internal control over financial reporting, assessing the risk
that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on
the assessed risk. Our audit also included performing such other
procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our
opinion.
A companys internal control over financial reporting is a
process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with
generally accepted accounting principles. A companys
internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance
of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions
are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of
management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
In our opinion, NRG Energy, Inc. maintained, in all material
respects, effective internal control over financial reporting as
of December 31, 2009, based on criteria established in
Internal Control Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of NRG Energy, Inc. and subsidiaries
as of December 31, 2009 and 2008, and the related
consolidated statements of operations, stockholders equity
and comprehensive income / (loss), and cash flows for
each of the years in the three-year period ended
December 31, 2009, and our report dated February 23,
2010 expressed an unqualified opinion on those consolidated
financial statements.
KPMG LLP
Philadelphia, Pennsylvania
February 23, 2010
139
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
NRG Energy, Inc.:
We have audited the accompanying consolidated balance sheets of
NRG Energy, Inc. and subsidiaries as of December 31, 2009
and 2008, and the related consolidated statements of operations,
stockholders equity and comprehensive
income / (loss), and cash flows for each of the years
in the three-year period ended December 31, 2009. In
connection with our audits of the consolidated financial
statements, we also have audited financial statement schedule
Schedule II. Valuation and Qualifying Accounts.
These consolidated financial statements and financial statement
schedule are the responsibility of the Companys
management. Our responsibility is to express an opinion on these
consolidated financial statements and financial statement
schedule based on our audits.
We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of NRG Energy, Inc. and subsidiaries as of
December 31, 2009 and 2008, and the results of their
operations and their cash flows for each of the years in the
three-year period ended December 31, 2009, in conformity
with U.S. generally accepted accounting principles. Also in
our opinion, the related financial statement schedule, when
considered in relation to the basic consolidated financial
statements taken as a whole, present fairly, in all material
respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial
statements, the Company adopted Statement of Financial
Accounting Standards (SFAS) 141R, Business Combinations
(incorporated into Accounting Standards Codification (ASC)
Topic 805, Business Combinations),
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements an amendment of
ARB No. 51, Consolidated Financial Statements
(incorporated into ASC Topic 810, Consolidation),
Financial Accounting Standards Board Staff Position (FSP FAS)
141R-1, Accounting for Assets and Liabilities Assumed in a
Business Combination That Arise from Contingencies
(incorporated into ASC Topic 805, Business
Combinations), and FSP Accounting Principles Board (APB)
No. 14-1,
Accounting for Convertible Debt Instruments That May Be
Settled in Cash upon Conversion (Including Partial Cash
Settlements) (incorporated into ASC Topic 825, Financial
Instruments), effective January 1, 2009;
SFAS No. 157, Fair Value Measurements
(incorporated into ASC Topic 820, Fair Value Measurements
and Disclosures), effective January 1, 2008; and FASB
Interpretation No. 48, Accounting for Uncertainty in
Income Taxes an Interpretation of
SFAS No. 109 (incorporated into ASC Topic 740,
Income Taxes), effective January 1, 2007.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of NRG Energy, Inc. and subsidiaries internal
control over financial reporting as of December 31, 2009,
based on criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report
dated February 23, 2010 expressed an unqualified opinion on
the effective operation of internal control over financial
reporting.
KPMG LLP
Philadelphia, Pennsylvania
February 23, 2010
140
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31,
|
|
(In millions, except per share amounts)
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
8,952
|
|
|
$
|
6,885
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
5,323
|
|
|
|
3,598
|
|
|
|
3,378
|
|
Depreciation and amortization
|
|
|
818
|
|
|
|
649
|
|
|
|
658
|
|
Selling, general and administrative
|
|
|
550
|
|
|
|
319
|
|
|
|
309
|
|
Acquisition-related transaction and integration costs
|
|
|
54
|
|
|
|
|
|
|
|
|
|
Development costs
|
|
|
48
|
|
|
|
46
|
|
|
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,793
|
|
|
|
4,612
|
|
|
|
4,446
|
|
Gain on sale of assets
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income
|
|
|
2,159
|
|
|
|
2,273
|
|
|
|
1,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
41
|
|
|
|
59
|
|
|
|
54
|
|
Gains on sales of equity method investments
|
|
|
128
|
|
|
|
|
|
|
|
1
|
|
Other income/(loss), net
|
|
|
(5
|
)
|
|
|
17
|
|
|
|
55
|
|
Refinancing expenses
|
|
|
(20
|
)
|
|
|
|
|
|
|
(35
|
)
|
Interest expense
|
|
|
(634
|
)
|
|
|
(583
|
)
|
|
|
(702
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other expenses
|
|
|
(490
|
)
|
|
|
(507
|
)
|
|
|
(627
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
1,669
|
|
|
|
1,766
|
|
|
|
933
|
|
Income tax expense
|
|
|
728
|
|
|
|
713
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
941
|
|
|
|
1,053
|
|
|
|
556
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
172
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
|
941
|
|
|
|
1,225
|
|
|
|
573
|
|
Less: Net loss attributable to noncontrolling interest
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income attributable to NRG Energy, Inc.
|
|
|
942
|
|
|
|
1,225
|
|
|
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends for preferred shares
|
|
|
33
|
|
|
|
55
|
|
|
|
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Available for Common Stockholders
|
|
$
|
909
|
|
|
$
|
1,170
|
|
|
$
|
518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share attributable to NRG Energy, Inc. Common
Stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
basic
|
|
|
246
|
|
|
|
235
|
|
|
|
240
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
3.70
|
|
|
$
|
4.25
|
|
|
$
|
2.09
|
|
Income from discontinued operations per weighted average common
share basic
|
|
|
|
|
|
|
0.73
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Basic
|
|
$
|
3.70
|
|
|
$
|
4.98
|
|
|
$
|
2.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
271
|
|
|
|
275
|
|
|
|
288
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
3.44
|
|
|
$
|
3.80
|
|
|
$
|
1.90
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
|
|
|
|
0.63
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income per Weighted Average Common Share
Diluted
|
|
$
|
3.44
|
|
|
$
|
4.43
|
|
|
$
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts Attributable to NRG Energy, Inc.:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
|
942
|
|
|
|
1,053
|
|
|
|
556
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
172
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
942
|
|
|
$
|
1,225
|
|
|
$
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
141
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
2,304
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
177
|
|
|
|
754
|
|
Restricted cash
|
|
|
2
|
|
|
|
16
|
|
Accounts receivable trade, less allowance for
doubtful accounts of $29 and $3
|
|
|
876
|
|
|
|
464
|
|
Current portion of note receivable affiliate and
capital leases
|
|
|
32
|
|
|
|
68
|
|
Inventory
|
|
|
541
|
|
|
|
455
|
|
Derivative instruments valuation
|
|
|
1,636
|
|
|
|
4,600
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
361
|
|
|
|
494
|
|
Prepayments and other current assets
|
|
|
279
|
|
|
|
147
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
6,208
|
|
|
|
8,492
|
|
|
|
|
|
|
|
|
|
|
Property, Plant and Equipment
|
|
|
|
|
|
|
|
|
In service
|
|
|
14,083
|
|
|
|
13,084
|
|
Under construction
|
|
|
533
|
|
|
|
804
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
14,616
|
|
|
|
13,888
|
|
Less accumulated depreciation
|
|
|
(3,052
|
)
|
|
|
(2,343
|
)
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
|
11,564
|
|
|
|
11,545
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
|
409
|
|
|
|
490
|
|
Note receivable affiliate and capital leases, less
current portion
|
|
|
504
|
|
|
|
435
|
|
Goodwill
|
|
|
1,718
|
|
|
|
1,718
|
|
Intangible assets, net of accumulated amortization of $648 and
$335
|
|
|
1,777
|
|
|
|
815
|
|
Nuclear decommissioning trust fund
|
|
|
367
|
|
|
|
303
|
|
Derivative instruments valuation
|
|
|
683
|
|
|
|
885
|
|
Other non-current assets
|
|
|
148
|
|
|
|
125
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
5,606
|
|
|
|
4,771
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
23,378
|
|
|
$
|
24,808
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
142
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions, except share data)
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
571
|
|
|
$
|
464
|
|
Accounts payable trade
|
|
|
693
|
|
|
|
447
|
|
Accounts payable affiliates
|
|
|
4
|
|
|
|
4
|
|
Derivative instruments valuation
|
|
|
1,473
|
|
|
|
3,981
|
|
Deferred income taxes
|
|
|
197
|
|
|
|
201
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
177
|
|
|
|
760
|
|
Accrued interest expense
|
|
|
207
|
|
|
|
178
|
|
Other accrued expenses
|
|
|
298
|
|
|
|
215
|
|
Other current liabilities
|
|
|
142
|
|
|
|
331
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
3,762
|
|
|
|
6,581
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
7,847
|
|
|
|
7,697
|
|
Nuclear decommissioning reserve
|
|
|
300
|
|
|
|
284
|
|
Nuclear decommissioning trust liability
|
|
|
255
|
|
|
|
218
|
|
Postretirement and other benefit obligations
|
|
|
287
|
|
|
|
277
|
|
Deferred income taxes
|
|
|
1,783
|
|
|
|
1,190
|
|
Derivative instruments valuation
|
|
|
387
|
|
|
|
508
|
|
Out-of-market
contracts
|
|
|
294
|
|
|
|
291
|
|
Other non-current liabilities
|
|
|
519
|
|
|
|
392
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
11,672
|
|
|
|
10,857
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities
|
|
|
15,434
|
|
|
|
17,438
|
|
|
|
|
|
|
|
|
|
|
3.625% convertible perpetual preferred stock; $0.01 par
value; 250,000 shares issued and outstanding (at
liquidation value of $250, net of issuance costs)
|
|
|
247
|
|
|
|
247
|
|
Commitments and Contingencies
|
|
|
|
|
|
|
|
|
Stockholders Equity
|
|
|
|
|
|
|
|
|
4% convertible perpetual preferred stock; $0.01 par value;
154,057 shares issued and outstanding at December 31,
2009 (at liquidation value of $154, net of issuance costs) and
420,000 shares issued and outstanding at December 31,
2008 (at liquidation value of $420, net of issuance costs)
|
|
|
149
|
|
|
|
406
|
|
5.75% convertible perpetual preferred stock; $0.01 par
value, 1,841,680 shares issued and outstanding at
December 31, 2008 (at liquidation value of $460, net of
issuance costs)
|
|
|
|
|
|
|
447
|
|
Common stock; $0.01 par value; 500,000,000 shares
authorized; 295,861,759 and 263,599,200 shares issued and
253,995,308 and 234,356,717 shares outstanding at
December 31, 2009 and 2008
|
|
|
3
|
|
|
|
3
|
|
Additional
paid-in
capital
|
|
|
4,948
|
|
|
|
4,350
|
|
Retained earnings
|
|
|
3,332
|
|
|
|
2,423
|
|
Less treasury stock, at cost - 41,866,451 and
29,242,483 shares at December 31, 2009 and 2008
|
|
|
(1,163
|
)
|
|
|
(823
|
)
|
Accumulated other comprehensive income
|
|
|
416
|
|
|
|
310
|
|
Noncontrolling interest
|
|
|
12
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
Total Stockholders Equity
|
|
|
7,697
|
|
|
|
7,123
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
23,378
|
|
|
$
|
24,808
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
143
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS
EQUITY AND COMPREHENSIVE INCOME
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
Total
|
|
|
|
Serial Preferred
|
|
|
Common
|
|
|
Paid-In
|
|
|
Retained
|
|
|
Treasury
|
|
|
Comprehensive
|
|
|
Noncontrolling
|
|
|
Stockholders
|
|
|
|
Stock
|
|
|
Shares
|
|
|
Stock
|
|
|
Shares
|
|
|
Capital
|
|
|
Earnings
|
|
|
Stock
|
|
|
Income/(Loss)
|
|
|
Interest
|
|
|
Equity
|
|
|
|
(In millions)
|
|
|
Balances at December 31, 2006
|
|
$
|
892
|
|
|
|
2.4
|
|
|
$
|
3
|
|
|
|
245
|
|
|
$
|
4,506
|
|
|
$
|
735
|
|
|
$
|
(732
|
)
|
|
$
|
282
|
|
|
$
|
|
|
|
$
|
5,686
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
573
|
|
Foreign currency translation adjustments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
73
|
|
|
|
|
|
|
|
73
|
|
Unrealized loss on derivatives, net of $310 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(474
|
)
|
|
|
|
|
|
|
(474
|
)
|
Available-for-sale
securities, net of $1 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
Defined benefit plan prior service cost of $4 and
net loss of $2, net of $2 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
176
|
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
Reduction to tax valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
56
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(9
|
)
|
|
|
|
|
|
|
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
|
|
|
|
(353
|
)
|
Retirement of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(447
|
)
|
|
|
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2007
|
|
|
892
|
|
|
|
2.4
|
|
|
|
3
|
|
|
|
237
|
|
|
|
4,124
|
|
|
|
1,253
|
|
|
|
(638
|
)
|
|
|
(115
|
)
|
|
|
|
|
|
|
5,519
|
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,225
|
|
Foreign currency translation adjustments, net of $22 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(112
|
)
|
|
|
|
|
|
|
(112
|
)
|
Reclassification adjustment for translation loss realized upon
sale of ITISA
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15
|
|
|
|
|
|
|
|
15
|
|
Unrealized gain on derivatives, net of $369 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
580
|
|
|
|
|
|
|
|
580
|
|
Available-for-sale
securities, net of $2 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
|
|
|
|
|
|
(4
|
)
|
Defined benefit plan prior service credit of $1 and
net loss of $55, net of $35 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,650
|
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
Payment to settle CSF I CAGR
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
Reduction to tax valuation allowance
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
162
|
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
NINA contribution, net of $17 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
33
|
|
5.75% preferred stock conversion to common stock
|
|
|
(39
|
)
|
|
|
(0.1
|
)
|
|
|
|
|
|
|
1
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2008
|
|
$
|
853
|
|
|
|
2.3
|
|
|
$
|
3
|
|
|
|
234
|
|
|
$
|
4,350
|
|
|
$
|
2,423
|
|
|
$
|
(823
|
)
|
|
$
|
310
|
|
|
$
|
7
|
|
|
$
|
7,123
|
|
Net income/(loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
942
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
941
|
|
Foreign currency translation adjustments, net of $21 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35
|
|
|
|
|
|
|
|
35
|
|
Reclassification adjustment for translation loss realized upon
sale of MIBRAG, net of tax benefit $13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22
|
)
|
|
|
|
|
|
|
(22
|
)
|
Unrealized gain on derivatives, net of $53 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
91
|
|
|
|
|
|
|
|
91
|
|
Available-for-sale
securities, net of $2 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
4
|
|
Defined benefit plan prior service credit of $1 and
net loss of $8, net of $1 tax benefit
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,047
|
|
Equity-based compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
Purchase of treasury stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
(500
|
)
|
|
|
|
|
|
|
|
|
|
|
(500
|
)
|
Preferred stock dividends
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33
|
)
|
ESPP share purchases
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
NINA contribution, net of $16 tax
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
34
|
|
5.75% preferred stock conversion to common stock
|
|
|
(447
|
)
|
|
|
(1.9
|
)
|
|
|
|
|
|
|
19
|
|
|
|
447
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4.00% preferred stock conversion to common stock
|
|
|
(257
|
)
|
|
|
(0.3
|
)
|
|
|
|
|
|
|
13
|
|
|
|
257
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares loaned to affiliate of CS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
|
|
(291
|
)
|
|
|
|
|
|
|
291
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares returned from affiliate of CS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
131
|
|
|
|
|
|
|
|
(131
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances at December 31, 2009
|
|
$
|
149
|
|
|
|
0.1
|
|
|
$
|
3
|
|
|
|
254
|
|
|
$
|
4,948
|
|
|
$
|
3,332
|
|
|
$
|
(1,163
|
)
|
|
$
|
416
|
|
|
$
|
12
|
|
|
$
|
7,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements
144
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
941
|
|
|
$
|
1,225
|
|
|
$
|
573
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity in earnings of unconsolidated affiliates
|
|
|
(41
|
)
|
|
|
(44
|
)
|
|
|
(33
|
)
|
Depreciation and amortization
|
|
|
818
|
|
|
|
649
|
|
|
|
661
|
|
Provision for bad debts
|
|
|
61
|
|
|
|
|
|
|
|
|
|
Amortization of nuclear fuel
|
|
|
36
|
|
|
|
39
|
|
|
|
58
|
|
Amortization of financing costs and debt discount/premiums
|
|
|
44
|
|
|
|
37
|
|
|
|
79
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
153
|
|
|
|
(270
|
)
|
|
|
(156
|
)
|
Amortization of unearned equity compensation
|
|
|
26
|
|
|
|
26
|
|
|
|
19
|
|
Loss/(gain) on disposals and sales of assets
|
|
|
17
|
|
|
|
25
|
|
|
|
(17
|
)
|
Impairment charges and asset write downs
|
|
|
|
|
|
|
23
|
|
|
|
20
|
|
Changes in derivatives
|
|
|
(225
|
)
|
|
|
(484
|
)
|
|
|
77
|
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
689
|
|
|
|
762
|
|
|
|
359
|
|
Gain on sales of equity method investments
|
|
|
(128
|
)
|
|
|
|
|
|
|
(1
|
)
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(273
|
)
|
|
|
|
|
Gain on sale of emission allowances
|
|
|
(4
|
)
|
|
|
(51
|
)
|
|
|
(31
|
)
|
Gain recognized on settlement of pre-existing relationship
|
|
|
(31
|
)
|
|
|
|
|
|
|
|
|
Changes in nuclear decommissioning trust liability
|
|
|
26
|
|
|
|
34
|
|
|
|
32
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
127
|
|
|
|
(417
|
)
|
|
|
(125
|
)
|
Cash provided/(used) by changes in other working capital, net of
acquisition and disposition effects: Accounts receivable, net
|
|
|
88
|
|
|
|
1
|
|
|
|
(102
|
)
|
Inventory
|
|
|
(83
|
)
|
|
|
(5
|
)
|
|
|
(38
|
)
|
Prepayments and other current assets
|
|
|
26
|
|
|
|
(7
|
)
|
|
|
22
|
|
Accounts payable
|
|
|
(176
|
)
|
|
|
(31
|
)
|
|
|
49
|
|
Option premiums collected
|
|
|
(282
|
)
|
|
|
268
|
|
|
|
8
|
|
Accrued expenses and other current liabilities
|
|
|
48
|
|
|
|
(6
|
)
|
|
|
98
|
|
Other assets and liabilities
|
|
|
(24
|
)
|
|
|
(22
|
)
|
|
|
(35
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided by Operating Activities
|
|
|
2,106
|
|
|
|
1,479
|
|
|
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of businesses, net of cash acquired
|
|
|
(427
|
)
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(734
|
)
|
|
|
(899
|
)
|
|
|
(481
|
)
|
Increase in restricted cash, net
|
|
|
14
|
|
|
|
13
|
|
|
|
12
|
|
(Increase)/decrease in notes receivable
|
|
|
(22
|
)
|
|
|
10
|
|
|
|
34
|
|
Decrease in trust fund balances
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Purchases of emission allowances
|
|
|
(78
|
)
|
|
|
(8
|
)
|
|
|
(161
|
)
|
Proceeds from sale of emission allowances
|
|
|
40
|
|
|
|
75
|
|
|
|
272
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(305
|
)
|
|
|
(616
|
)
|
|
|
(265
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
279
|
|
|
|
582
|
|
|
|
233
|
|
Proceeds from sale of assets, net
|
|
|
6
|
|
|
|
14
|
|
|
|
2
|
|
Proceeds from sale of equity method investment
|
|
|
284
|
|
|
|
|
|
|
|
|
|
Equity investment in unconsolidated affiliate
|
|
|
(6
|
)
|
|
|
(84
|
)
|
|
|
|
|
Purchases of securities
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
Proceeds from sale of discontinued operations and assets, net of
cash divested
|
|
|
|
|
|
|
241
|
|
|
|
57
|
|
Other
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used by Investing Activities
|
|
|
(954
|
)
|
|
|
(672
|
)
|
|
|
(327
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
(33
|
)
|
|
|
(55
|
)
|
|
|
(55
|
)
|
Net payments to settle acquired derivatives that include
financing elements
|
|
|
(79
|
)
|
|
|
(43
|
)
|
|
|
|
|
Payment for treasury stock
|
|
|
(500
|
)
|
|
|
(185
|
)
|
|
|
(353
|
)
|
Installment proceeds from sale of noncontrolling interest in
subsidiary
|
|
|
50
|
|
|
|
50
|
|
|
|
|
|
Payment to settle CSF I CAGR
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
2
|
|
|
|
9
|
|
|
|
7
|
|
Proceeds from issuance of long-term debt
|
|
|
892
|
|
|
|
20
|
|
|
|
1,411
|
|
Payment of deferred debt issuance costs
|
|
|
(31
|
)
|
|
|
(4
|
)
|
|
|
(5
|
)
|
Payments for short and long-term debt
|
|
|
(644
|
)
|
|
|
(234
|
)
|
|
|
(1,819
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Used by Financing Activities
|
|
|
(343
|
)
|
|
|
(487
|
)
|
|
|
(814
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
43
|
|
|
|
(25
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase in Cash and Cash Equivalents
|
|
|
810
|
|
|
|
362
|
|
|
|
355
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
1,494
|
|
|
|
1,132
|
|
|
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
2,304
|
|
|
$
|
1,494
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
See notes to Consolidated Financial Statements.
145
NRG
ENERGY, INC. AND SUBSIDIARIES
NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS
|
|
Note 1
|
Nature
of Business
|
General
NRG Energy, Inc., or NRG or the Company, is primarily a
wholesale power generation company with a significant presence
in major competitive power markets in the U.S., as well 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 U.S. and
select international markets, and supply of electricity and
energy services to retail electricity customers in the Texas
market.
As of December 31, 2009, NRG had a total global generation
portfolio of 187 active operating fossil fuel and nuclear
generation units, at 44 power generation plants, with an
aggregate generation capacity of approximately 24,115 MW,
and approximately 400 MW under construction which includes
partner interests of 200 MW. In addition to its fossil fuel
plant ownership, NRG has ownership interests in operating
renewable facilities with an aggregate generation capacity of
365 MW, consisting of three wind farms representing an
aggregate generation capacity of 345 MW (which includes
partner interest of 75 MW) and a solar facility with an
aggregate generation capacity of 20 MW. Within the U.S.,
NRG has large and diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with
approximately 23,110 MW of fossil fuel and nuclear
generation capacity in 179 active generating units at 42 plants.
The Companys power generation facilities are most heavily
concentrated in Texas (approximately 11,340 MW, including
345 MW from three wind farms), the Northeast (approximately
7,015 MW), South Central (approximately 2,855 MW), and
West (approximately 2,150 MW, including 20 MW from a
solar farm) regions of the U.S., with approximately 115 MW
of additional generation capacity from the Companys
thermal assets. In addition, through certain foreign
subsidiaries, NRG has investments in power generation projects
located in Australia and Germany with approximately
1,005 MW of generation capacity.
On May 1, 2009, NRG acquired Reliant Energy, which is the
second largest electricity provider to Mass customers in Texas.
Reliant Energy is also the largest electricity and energy
services provider, based on load, to C&I customers in
Texas. Based on metered locations, as of December 31, 2009,
Reliant Energy had approximately 1.5 million Mass customers
and approximately 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.
NRG was incorporated as a Delaware corporation on May 29,
1992. NRGs common stock is listed on the New York Stock
Exchange under the symbol NRG. The Companys
headquarters and principal executive offices are located at 211
Carnegie Center, Princeton, New Jersey 08540. NRGs
telephone number is
(609) 524-4500.
The address of the Companys website is
www.nrgenergy.com. NRGs recent annual reports,
quarterly reports, current reports, and other periodic filings
are available free of charge through the Companys website.
|
|
Note 2
|
Summary
of Significant Accounting Policies
|
Principles
of Consolidation and Basis of Presentation
The consolidated financial statements include NRGs
accounts and operations and those of its subsidiaries in which
the Company has a controlling interest. All significant
intercompany transactions and balances have been eliminated in
consolidation. The usual condition for a controlling financial
interest is ownership of a majority of the voting interests of
an entity. However, a controlling financial interest may also
exist in entities, such as a variable interest entity, through
arrangements that do not involve controlling voting interests.
As such, NRG applies the guidance of ASC 810, Consolidations,
or ASC 810, to consolidate variable interest entities, or
VIEs, for which the Company is the primary beneficiary. ASC 810
requires a variable interest holder to consolidate a VIE if that
party will absorb a majority of the expected losses of the VIE,
receive the majority of the
146
expected residual returns of the VIE, or both. This party is
considered the primary beneficiary. Conversely, NRG will not
consolidate a VIE in which it has a majority ownership interest
when the Company is not considered the primary beneficiary. In
determining the primary beneficiary, NRG thoroughly evaluates
the VIEs design, capital structure, and relationships
among variable interest holders.
As discussed in Note 16, Investments Accounted for by
the Equity Method, NRG has investments in partnerships,
joint ventures and projects, one of which is a VIE for which the
Company is not the primary beneficiary.
Accounting policies for all of NRGs operations are in
accordance with accounting principles generally accepted in the
U.S. Upon its emergence from bankruptcy on December 5,
2003, the Company qualified for and adopted fresh start
reporting, or Fresh Start, under ASC 852,
Reorganizations, or ASC 852.
These financial statements and notes reflect the Companys
evaluation of events occurring subsequent to the balance sheet
date through February 23, 2010, the date the financial
statements were issued.
Cash
and Cash Equivalents
Cash and cash equivalents include highly liquid investments with
an original maturity of three months or less at the time of
purchase.
Funds
Deposited by Counterparties
Funds deposited by counterparties consist of cash held by NRG as
a result of collateral posting obligations from the
Companys counterparties due to positions in NRGs
hedging program. These amounts are segregated into separate
accounts that are not contractually restricted but, based on the
Companys intention, are not available for the payment of
NRGs general corporate obligations. Depending on market
fluctuations and the settlement of the underlying contracts, the
Company will refund this collateral to the hedge counterparties
pursuant to the terms and conditions of the underlying trades.
Since collateral requirements fluctuate daily and the Company
cannot predict if any collateral will be held for more than
twelve months, the funds deposited by counterparties are
classified as a current asset on the Companys balance
sheet, with an offsetting liability for this cash collateral
received within current liabilities. Changes in funds deposited
by counterparties are closely associated with the Companys
operating activities, and are classified as an operating
activity in the Companys consolidated statements of cash
flows.
Restricted
Cash
Restricted cash consists primarily of funds held to satisfy the
requirements of certain debt agreements and funds held within
the Companys projects that are restricted in their use.
These funds are used to pay for current operating expenses and
current debt service payments, per the restrictions of the debt
agreements.
Trade
Receivables and Allowance for Doubtful Accounts
Trade receivables are reported in the balance sheet at
outstanding principal adjusted for any write-offs and the
allowance for doubtful accounts. For its Reliant Energy
business, the Company 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 aging
and other factors. Reliant Energy writes-off accounts receivable
balances against the allowance for doubtful accounts when it
determines a receivable is uncollectible.
Inventory
Inventory is valued at the lower of weighted average cost or
market, unless evidence indicates that the weighted average cost
will be recovered with a normal profit in the ordinary course of
business, and consists principally of fuel oil, coal and raw
materials used to generate electricity or steam. The Company
removes these inventories as they are used in the production of
electricity or steam. Spare parts inventory is valued at a
weighted average cost, since the Company expects to recover
these costs in the ordinary course of business. The Company
removes these
147
inventories when they are used for repairs, maintenance or
capital projects. Sales of inventory are classified as an
operating activity in the consolidated statements of cash flows.
Property,
Plant and Equipment
Property, plant and equipment are stated at cost; however
impairment adjustments are recorded whenever events or changes
in circumstances indicate that their carrying values may not be
recoverable. NRG also classifies nuclear fuel related to the
Companys 44% ownership interest in STP as part of the
Companys property, plant, and equipment. Significant
additions or improvements extending asset lives are capitalized
as incurred, while repairs and maintenance that do not improve
or extend the life of the respective asset are charged to
expense as incurred. Depreciation other than nuclear fuel is
computed using the straight-line method, while nuclear fuel is
amortized based on units of production over the estimated useful
lives. Certain assets and their related accumulated depreciation
amounts are adjusted for asset retirements and disposals with
the resulting gain or loss included in cost of operations in the
consolidated statements of operations.
Asset
Impairments
Long-lived assets that are held and used are reviewed for
impairment whenever events or changes in circumstances indicate
carrying values may not be recoverable. Such reviews are
performed in accordance with ASC 360. An impairment loss is
recognized if the total future estimated undiscounted cash flows
expected from an asset are less than its carrying value. An
impairment charge is measured by the difference between an
assets carrying amount and fair value with the difference
recorded in operating costs and expenses in the statements of
operations. Fair values are determined by a variety of valuation
methods, including appraisals, sales prices of similar assets
and present value techniques.
Investments accounted for by the equity method are reviewed for
impairment in accordance with ASC 323, which requires that a
loss in value of an investment that is other than a temporary
decline should be recognized. The Company identifies and
measures losses in the value of equity method investments based
upon a comparison of fair value to carrying value.
Discontinued
Operations
Long-lived assets or disposal groups are classified as
discontinued operations when all of the required criteria
specified in ASC 360 are met. These criteria include, among
others, existence of a qualified plan to dispose of an asset or
disposal group, an assessment that completion of a sale within
one year is probable and approval of the appropriate level of
management. In addition, upon completion of the transaction, the
operations and cash flows of the disposal group must be
eliminated from ongoing operations of the Company, and the
disposal group must not have any significant continuing
involvement with the Company. Discontinued operations are
reported at the lower of the assets carrying amount or
fair value less cost to sell.
Project
Development Costs and Capitalized Interest
Project development costs are expensed in the preliminary stages
of a project and capitalized when the project is deemed to be
commercially viable. Commercial viability is determined by one
or a series of actions including among others, Board of Director
approval pursuant to a formal project plan that subjects the
Company to significant future obligations that can only be
discharged by the use of a Company asset.
Interest incurred on funds borrowed to finance capital projects
is capitalized, until the project under construction is ready
for its intended use. The amount of interest capitalized for the
years ended December 31, 2009, 2008, and 2007, was
$37 million, $45 million, and $11 million,
respectively.
When a project is available for operations, capitalized interest
and project development costs are reclassified to property,
plant and equipment and amortized on a straight-line basis over
the estimated useful life of the projects related assets.
Capitalized costs are charged to expense if a project is
abandoned or management otherwise determines the costs to be
unrecoverable.
148
Debt
Issuance Costs
Debt issuance costs are capitalized and amortized as interest
expense on a basis which approximates the effective interest
method over the term of the related debt.
Intangible
Assets
Intangible assets represent contractual rights held by NRG. The
Company recognizes specifically identifiable intangible assets
including customer contracts, customer relationships, energy
supply contracts, trade names, emission allowances, and fuel
contracts when specific rights and contracts are acquired. In
addition, NRG also established values for emission allowances
and power contracts upon adoption of Fresh Start reporting.
These intangible assets are amortized based on expected volumes,
expected delivery, expected discounted future net cash flows,
straight line or units of production basis.
Intangible assets determined to have indefinite lives are not
amortized, but rather are tested for impairment at least
annually or more frequently if events or changes in
circumstances indicate that such acquired intangible assets have
been determined to have finite lives and should now be amortized
over their useful lives. NRG had no intangible assets with
indefinite lives recorded as of December 31, 2009.
Emission allowances
held-for-sale,
which are included in other non-current assets on the
Companys consolidated balance sheet, are not amortized;
they are carried at the lower of cost or fair value and reviewed
for impairment in accordance with ASC 360.
Goodwill
In accordance with ASC 350, the Company recognizes goodwill for
the excess cost of an acquired entity over the net value
assigned to assets acquired and liabilities assumed.
NRG performs goodwill impairment tests annually, typically
during the fourth quarter, and when events or changes in
circumstances indicate that the carrying value may not be
recoverable. Goodwill impairment is determined using a two step
process:
|
|
|
|
Step one
|
Identify potential impairment by comparing the fair value of a
reporting unit to the book value, including goodwill. If the
fair value exceeds book value, goodwill of the reporting unit is
not considered impaired. If the book value exceeds fair value,
proceed to step two.
|
|
|
Step two
|
Compare the implied fair value of the reporting units
goodwill to the book value of the reporting unit goodwill. If
the book value of goodwill exceeds fair value, an impairment
charge is recognized for the sum of such excess.
|
Income
Taxes
NRG accounts for income taxes using the liability method in
accordance with ASC 740, Income Taxes, or ASC 740, which
requires that the Company use the asset and liability method of
accounting for deferred income taxes and provide deferred income
taxes for all significant temporary differences.
NRG has two categories of income tax expense or
benefit current and deferred, as follows:
|
|
|
|
|
Current income tax expense or benefit consists solely of regular
tax less applicable tax credits, and
|
|
|
|
Deferred income tax expense or benefit is the change in the net
deferred income tax asset or liability, excluding amounts
charged or credited to accumulated other comprehensive income.
|
NRG reports some of the Companys revenues and expenses
differently for financial statement purposes than for income tax
return purposes resulting in temporary and permanent differences
between the Companys financial statements and income tax
returns. The tax effects of such temporary differences are
recorded as either deferred income tax assets or deferred income
tax liabilities in the Companys consolidated balance
sheets. NRG measures the Companys deferred income tax
assets and deferred income tax liabilities using income tax
rates that are
149
currently in effect. A valuation allowance is recorded to reduce
the Companys net deferred tax assets to an amount that is
more-likely-than-not to be realized.
The Company accounts for uncertain tax positions in accordance
with ASC 740, which applies to all tax positions related to
income taxes. Under ASC 740, tax benefits are recognized when it
is more-likely-than-not that a tax position will be sustained
upon examination by the authorities. The benefit from a position
that has surpassed the more-likely-than-not threshold is the
largest amount of benefit that is more than 50% likely to be
realized upon settlement. The Company recognizes interest and
penalties accrued related to unrecognized tax benefits as a
component of income tax expense.
Revenue
Recognition
Energy Both physical and financial
transactions are entered into to optimize the financial
performance of NRGs generating facilities. Electric energy
revenue is recognized upon transmission to the customer.
Physical transactions, or the sale of generated electricity to
meet supply and demand, are recorded on a gross basis in the
Companys consolidated statements of operations. Financial
transactions, or the buying and selling of energy for trading
purposes, are recorded net within operating revenues in the
consolidated statements of operations in accordance with ASC
815, Derivatives and Hedging, or ASC 815.
Capacity Capacity revenues are recognized
when contractually earned, and consist of revenues billed to a
third party at either the market or a negotiated contract price
for making installed generation capacity available in order to
satisfy system integrity and reliability requirements.
Sale of Emission Allowances NRG records the
Companys bank of emission allowances as part of the
Companys intangible assets. From time to time, management
may authorize the transfer of emission allowances in excess of
usage from the Companys emission bank to intangible assets
held-for-sale
for trading purposes. NRG records the sale of emission
allowances on a net basis within other revenue in the
Companys consolidated statements of operations.
Contract Amortization Assets and liabilities
recognized from power sales agreements assumed at Fresh Start
and through acquisitions related to the sale of electric
capacity and energy in future periods for which the fair value
has been determined to be significantly less (more) than market
is amortized to revenue over the term of each underlying
contract based on actual generation
and/or
contracted volumes.
Retail 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, which were
$251 million for the eight-month period ended
December 31, 2009. These revenues represent a sale of
excess supply to third parties in the market.
As of December 31, 2009, Reliant Energy recorded unbilled
revenues of $308 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.
Cost
of Energy for Reliant 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 ($69 million as of December 31,
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
150
ISO settlements. Volume estimates are then multiplied by the
supply rate and recorded as cost of operations in the applicable
reporting period.
Derivative
Financial Instruments
NRG accounts for derivative financial instruments under ASC 815,
which requires the Company to record all derivatives on the
balance sheet at fair value unless they qualify for a NPNS
exception. Changes in the fair value of non-hedge derivatives
are immediately recognized in earnings. Changes in the fair
value of derivatives accounted for as hedges are either:
|
|
|
|
|
Recognized in earnings as an offset to the changes in the fair
value of the related hedged assets, liabilities and firm
commitments; or
|
|
|
|
Deferred and recorded as a component of accumulated OCI until
the hedged transactions occur and are recognized in earnings.
|
NRGs primary derivative instruments are power sales
contracts, fuels purchase contracts, other energy related
commodities, and interest rate instruments used to mitigate
variability in earnings due to fluctuations in market prices and
interest rates. On an ongoing basis, NRG assesses the
effectiveness of all derivatives that are designated as hedges
for accounting purposes in order to determine that each
derivative continues to be highly effective in offsetting
changes in fair values or cash flows of hedged items. Internal
analyses that measure the statistical correlation between the
derivative and the associated hedged item determine the
effectiveness of such an energy contract designated as a hedge.
If it is determined that the derivative instrument is not highly
effective as a hedge, hedge accounting will be discontinued
prospectively. Hedge accounting will also be discontinued on
contracts related to commodity price risk previously accounted
for as cash flow hedges when it is probable that delivery will
not be made against these contracts. In this case, the gain or
loss previously deferred in OCI would be immediately
reclassified into earnings. If the derivative instrument is
terminated, the effective portion of this derivative in OCI will
be frozen until the underlying hedged item is delivered.
Revenues and expenses on contracts that qualify for the NPNS
exception are recognized when the underlying physical
transaction is delivered. While these contracts are considered
derivative financial instruments under ASC 815, they are not
recorded at fair value, but on an accrual basis of accounting.
If it is determined that a transaction designated as NPNS no
longer meets the scope exception, the fair value of the related
contract is recorded on the balance sheet and immediately
recognized through earnings.
NRGs trading activities 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.
Foreign
Currency Translation and Transaction Gains and
Losses
The local currencies are generally the functional currency of
NRGs foreign operations. Foreign currency denominated
assets and liabilities are translated at
end-of-period
rates of exchange. Revenues, expenses, and cash flows are
translated at the weighted-average rates of exchange for the
period. The resulting currency translation adjustments are not
included in the determination of the Companys statements
of operations for the period, but are accumulated and reported
as a separate component of stockholders equity until sale
or complete or substantially complete liquidation of the net
investment in the foreign entity takes place. Foreign currency
transaction gains or losses are reported within other
income/(expense) in the Companys statements of operations.
For the years ended December 31, 2009, 2008, and 2007,
amounts recognized as foreign currency transaction gains
(losses) were immaterial. The Companys cumulative
translation adjustment balances as of December 31, 2009,
2008, and 2007 were $21 million, $58 million and
$59 million, respectively.
Concentrations
of Credit Risk
Financial instruments which potentially subject NRG to
concentrations of credit risk consist primarily of cash, trust
funds, accounts receivable, notes receivable, derivatives, and
investments in debt securities. Cash and cash equivalents and
funds deposited by counterparties are predominantly held in
money market funds invested in
151
treasury securities, treasury repurchase agreements or
government agency debt. Trust funds are held in accounts managed
by experienced investment advisors. Certain accounts receivable,
notes receivable, and derivative instruments are concentrated
within entities engaged in the energy industry. These industry
concentrations may impact the Companys overall exposure to
credit risk, either positively or negatively, in that the
customers may be similarly affected by changes in economic,
industry or other conditions. Receivables and other contractual
arrangements are subject to collateral requirements under the
terms of enabling agreements. However, NRG believes that the
credit risk posed by industry concentration is offset by the
diversification and creditworthiness of the Companys
customer base. See Note 5, Fair Value of Financial
Instruments, for a further discussion of derivative
concentrations.
Fair
Value of Financial Instruments
The carrying amount of cash and cash equivalents, funds
deposited by counterparties, trust funds, receivables, accounts
payables, and accrued liabilities approximate fair value because
of the short-term maturity of these instruments. The carrying
amounts of long-term receivables usually approximate fair value,
as the effective rates for these instruments are comparable to
market rates at year-end, including current portions. Any
differences are disclosed in Note 5, Fair Value of
Financial Instruments. The fair value of long-term debt is
based on quoted market prices for those instruments that are
publicly traded, or estimated based on the income approach
valuation technique for non-publicly traded debt. For the years
ended December 31, 2009, 2008, and 2007, the Company
recorded an unrealized gain of $3 million, and impairment
charges of $23 million and $11 million respectively,
related to an investment in commercial paper. As of
December 31, 2009 the net carrying value of the investment
was $9 million.
Asset
Retirement Obligations
NRG accounts for its asset retirement obligations, or AROs, in
accordance with ASC
410-20,
Asset Retirement Obligations, or ASC
410-20.
Retirement obligations associated with long-lived assets
included within the scope of ASC
410-20 are
those for which a legal obligation exists under enacted laws,
statutes, and written or oral contracts, including obligations
arising under the doctrine of promissory estoppel, and for which
the timing
and/or
method of settlement may be conditional on a future event. ASC
410-20
requires an entity to recognize the fair value of a liability
for an ARO in the period in which it is incurred and a
reasonable estimate of fair value can be made.
Upon initial recognition of a liability for an ARO, NRG
capitalizes the asset retirement cost by increasing the carrying
amount of the related long-lived asset by the same amount. Over
time, the liability is accreted to its future value, while the
capitalized cost is depreciated over the useful life of the
related asset. See Note 13, Asset Retirement
Obligations, for a further discussion of AROs.
Pensions
NRG offers pension benefits through either a defined benefit
pension plan or a cash balance plan. In addition, the Company
provides postretirement health and welfare benefits for certain
groups of employees. NRG accounts for pension and other
postretirement benefits in accordance with ASC 715. NRG
recognizes the funded status of the Companys defined
benefit plans in the statement of financial position and records
an offset to other comprehensive income. In addition, NRG also
recognizes on an after-tax basis, as a component of other
comprehensive income, gains and losses as well as all prior
service costs that have not been included as part of the
Companys net periodic benefit cost. The determination of
NRGs obligation and expenses for pension benefits is
dependent on the selection of certain assumptions. These
assumptions determined by management include the discount rate,
the expected rate of return on plan assets and the rate of
future compensation increases. NRGs actuarial consultants
use assumptions for such items as retirement age. The
assumptions used may differ materially from actual results,
which may result in a significant impact to the amount of
pension obligation or expense recorded by the Company.
NRG measures the fair value of its pension assets in accordance
with ASC 820, Fair Value Measurements and Disclosures, or
ASC 820.
152
Stock-Based
Compensation
NRG accounts for its stock-based compensation in accordance with
ASC 718. The fair value of the Companys non-qualified
stock options and performance units are estimated on the date of
grant using the Black-Scholes option-pricing model and the Monte
Carlo valuation model, respectively. NRG uses the Companys
common stock price on the date of grant as the fair value of the
Companys restricted stock units and deferred stock units.
Forfeiture rates are estimated based on an analysis of
NRGs historical forfeitures, employment turnover, and
expected future behavior. The Company recognizes compensation
expense for both graded and cliff vesting awards on a
straight-line basis over the requisite service period for the
entire award.
Investments
Accounted for by the Equity Method
NRG has investments in various international and domestic energy
projects. The equity method of accounting is applied to such
investments in affiliates, which include joint ventures and
partnerships, because the ownership structure prevents NRG from
exercising a controlling influence over the operating and
financial policies of the projects. Under this method, equity in
pre-tax income or losses of domestic partnerships and,
generally, in the net income or losses of international
projects, are reflected as equity in earnings of unconsolidated
affiliates.
Issuance
of Subsidiarys Stock
The Company accounts for issuance of its subsidiaries
stock in accordance with ASC 810, which requires an entity to
account for a decrease in its ownership interest of a subsidiary
that does not result in a change of control of the subsidiary as
an equity transaction. In March 2008, NRG formed NINA, an NRG
development stage subsidiary focused on developing, financing,
and investing in nuclear projects in North America. TANE has
partnered with NRG on the NINA venture, receiving a 12% equity
ownership in NINA in exchange for $300 million to be
invested in NINA in six annual installments of $50 million,
the last three of which are subject to certain restrictions. NRG
continues to control NINA through its voting interest. Any
change in NRGs proportionate share of NINAs equity
resulting from cash invested by TANE directly into NINA is
accounted for by the Company as an equity transaction in
consolidation, and not a gain on sale, as long as there is no
change in control of NINA. Accordingly, receipt of TANEs
installment contributions results in increases in additional
paid in capital and noncontrolling interest on the
Companys consolidated balance sheet.
Gross
Receipts and Sales Taxes
In connection with its Reliant Energy business, the Company
records gross receipts taxes on a gross basis in revenues and
cost of operations in its consolidated statements of operations.
During the eight-month period ended December 31, 2009,
Reliant Energys revenues and cost of operations included
gross receipts taxes of $55 million. Additionally, 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
consolidated statement of operations.
Use of
Estimates
The preparation of financial statements in conformity with
accounting principles generally accepted in the
U.S. requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities at
the date of the financial statements, disclosure of contingent
assets and liabilities at the date of the financial statements,
and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these
estimates.
In recording transactions and balances resulting from business
operations, NRG uses estimates based on the best information
available. Estimates are used for such items as plant
depreciable lives, tax provisions, uncollectible accounts,
actuarially determined benefit costs, and the valuation of
energy commodity contracts, environmental liabilities, and legal
costs incurred in connection with recorded loss contingencies,
among others. In addition, estimates are used to test long-lived
assets and goodwill for impairment and to determine the fair
value of impaired assets. As better information becomes
available or actual amounts are determinable, the recorded
estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates.
153
Reclassifications
Certain prior-year amounts have been reclassified for
comparative purposes.
Recent
Accounting Developments
SFAS 168 In June 2009, the Financial
Accounting Standards Board, or FASB, issued
SFAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting
Principles, or SFAS 168. Effective July 1, 2009,
this guidance establishes the FASB Accounting Standards
Codification, or ASC, as the source of authoritative
U.S. GAAP recognized by the FASB to be applied by
nongovernmental entities. In addition, SFAS 168 also
specifies that rules and interpretive releases of the SEC under
authority of federal securities laws are also sources of
authoritative U.S. GAAP for SEC registrants. All guidance
contained in the ASC carries an equal level of authority. The
Company adopted SFAS 168 for the quarterly reporting period
ending September 30, 2009. SFAS 168 has been
incorporated into the ASC as ASC-105, Generally Accepted
Accounting Principles, or ASC 105.
Certain U.S. GAAP standards and interpretations were
adopted by the Company in 2009 prior to the July 1, 2009,
effective date of the ASC, and were subsequently incorporated
into one or more ASC topics. Further, certain U.S. GAAP
standards were ratified by the FASB in 2009 prior to
July 1, 2009, but are not yet effective and have therefore
not yet been incorporated into the ASC. This report retains the
original title of these standards and interpretations, and
references the ASC topic or topics in which they have been, or
are expected to be, incorporated.
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. 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. As discussed
in Note 3, Business Acquisitions, to the
Consolidated Financial Statements, the Company has applied the
provisions of SFAS 141R to the Reliant Energy acquisition,
as well as all other business acquisitions completed in 2009. As
discussed further in Note 19, 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. SFAS 141R has been
incorporated into ASC-805, Business Combinations, or ASC
805.
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 as well as all other business
acquisitions completed in 2009. The provisions of FSP
FAS 141R-1
have been incorporated into ASC 805.
SFAS 160 The Company adopted
SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements-an amendment of ARB
No. 51, Consolidated Financial Statements, or
SFAS 160, on January 1, 2009. SFAS 160
establishes 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. SFAS 160 has been incorporated into ASC-810,
Consolidation, or ASC 810.
154
ASU
No. 2010-02 -
In January 2010 the FASB issued ASU
No. 2010-02,
Consolidation (Topic 810): Accounting and Reporting for
Decreases in Ownership of a Subsidiarya Scope
Clarification, or ASU
2010-02. ASU
2010-02
amends ASC 810, Consolidation to resolve a conflict
between the consolidation guidance in the Accounting Standards
Codification and other sections of U.S. GAAP when there is
a decrease in ownership of a subsidiary. Entities are required
to apply the amendments in ASU
2010-02
retrospectively for the first reporting period in which they
applied SFAS 160. Although ASU
2010-02 is
effective for the Company beginning in the fourth quarter of
2009, no decrease in ownership transactions resulting in a
change in control within the scope of ASU
2010-02 and
related guidance had occurred as of December 31, 2009,
therefore there was no impact on the Companys results of
operations, financial position, or cash flows.
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)
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. The provisions of FSP APB
14-1 have
been incorporated into ASC-470, Debt, or ASC 470, and
ASC-825, Financial Instruments, or ASC 825.
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 embedded
derivatives, or CSF CAGRs, requiring NRG to pay to CS at
maturity, either in cash or stock at NRGs option, the
excess of NRGs then current stock price over a threshold
price. The CSF Debt and CSF CAGRs are accounted for under the
guidance in ASC 470. Upon adoption of FSP APB
14-1, the
fair value of the CSF CAGRs 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, 2006, was recorded as a $28 million
decrease to Long-Term Debt, a $32 million increase to
Additional Paid-In Capital, and a $4 million decrease to
Retained Earnings on the Condensed Consolidated Balance Sheet as
of December 31, 2006. In addition, in August 2008 the
Company paid $45 million to CS for the benefit of CSF I to
early settle the CSF CAGR in the Companys CSF I notes and
preferred interests, which was reclassified from interest
expense to Additional Paid-In Capital upon the adoption of FSP
APB 14-1.
The following table summarizes the effect of the adoption of FSP
APB 14-1 on
income and per-share amounts for all periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
2007
|
|
|
|
|
(In millions, except per share amounts)
|
|
Increase/(decrease):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense
|
|
$
|
6
|
|
|
$
|
(37
|
)
|
|
$
|
13
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
(6
|
)
|
|
|
37
|
|
|
|
(13
|
)
|
|
|
|
|
Net Income attributable to NRG Energy, Inc.
|
|
|
(6
|
)
|
|
|
37
|
|
|
|
(13
|
)
|
|
|
|
|
Basic Earnings Per Share
|
|
$
|
(0.03
|
)
|
|
$
|
0.16
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
Diluted Earnings Per Share
|
|
$
|
(0.02
|
)
|
|
$
|
0.14
|
|
|
$
|
(0.05
|
)
|
|
|
|
|
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 ASC-820, Fair Value Measurements and
Disclosure, or ASC 820, 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
155
June 15, 2009, and is 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. The
provisions of FSP
FAS 157-4
have been incorporated into ASC 820.
FSP
FAS 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 requires disclosures about fair value of financial
instruments for interim and annual reporting periods of publicly
traded companies ending after the FSPs effective date of
June 15, 2009. The Companys adoption of FSP
FAS 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. The provisions of FSP
FAS 107-1
and APB 28-1
have been incorporated in ASC-270, Interim Reporting, or
ASC 270, and ASC-825, Financial Instruments, or ASC 825.
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, and disclosure requirements apply only
to periods ending after the FSPs effective date. 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. The provisions of FSP
FAS 115-2
and
FAS 124-2
have been incorporated in ASC-320, Investments
Debt and Equity Securities, or ASC 320.
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 165 has been
incorporated in ASC-855, Subsequent Events, or ASC 855.
SFAS 167/ASU
No. 2009-17
In June 2009, the FASB issued SFAS No. 167,
Amendments to FASB Interpretation No. 46(R), or
SFAS 167. This guidance amends ASC 810 by altering how a
company determines when an entity that is insufficiently
capitalized or not controlled through its voting interests
should be consolidated. The previous ASC 810 guidance required a
quantitative analysis of the economic risk/rewards of a VIE to
determine the primary beneficiary. FAS 167 now specifies
that a qualitative analysis be performed, requiring the primary
beneficiary to have both the power to direct the activities of a
VIE that most significantly impact the entities economic
performance, as well as either the obligation to absorb losses
or the right to receive benefits that could potentially be
significant to the VIE. In December 2009 the FASB issued ASU
No. 2009-17,
Consolidations: Improvements to Financial Reporting by
Enterprises Involved with Variable Interest Entities, or ASU
2009-17. ASU
2009-17
formally incorporates the provisions of SFAS 167 into ASC
810 and is effective for NRG as of January 1, 2010. The
Companys adoption of ASU
2009-17 on
January 1, 2010 did not have an impact on its results of
operations, financial position, or cash flows.
ASU
2009-15/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
156
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. This statement did not have a material
impact on the Companys results of operations, financial
position and cash flows. In October 2009, the FASB issued
Accounting Standards Update, or ASU
No. 2009-15,
Accounting for Own-Share Lending Arrangements in
Contemplation of Convertible Debt Issuance or Other
Financing, or ASU
2009-15,
which formally incorporated the provisions of
EITF 09-1
into ASC 470.
ASU
2009-05
In August 2009, the FASB issued ASU
No. 2009-05,
Fair Value Measurement and Disclosures: Measuring Liabilities
at Fair Value, or ASU
2009-5. This
ASU, which amends ASC 820 and ASC 825, provides clarification on
measuring liabilities at fair value when a quoted price in an
active market is not available. The Companys adoption of
ASU 2009-5
beginning with the interim period ended September 30, 2009,
did not have an impact on the Companys results of
operations, financial position or cash flows.
ASU
2010-06
In January 2010, the FASB issued ASU
No. 2010-06,
Fair Value Measurement and Disclosures: Improving Disclosures
about Fair Value Measurements, or ASU
2010-6,
intending to improve disclosures about fair value measurements.
The guidance requires entities to disclose significant transfers
in and out of fair value hierarchy levels and the reasons for
the transfers and to present information about purchases, sales,
issuances and settlements separately in the reconciliation of
fair value measurements using significant unobservable inputs
(Level 3). Additionally, the guidance clarifies that a
reporting entity should provide fair value measurements for each
class of assets and liabilities and disclose the inputs and
valuation techniques used for fair value measurements using
significant other observable inputs (Level 2) and
significant unobservable inputs (Level 3). This guidance is
effective for interim and annual periods beginning after
December 15, 2009 except for the disclosures about
purchases, sales, issuances and settlements in the Level 3
reconciliation, which will be effective for interim and annual
periods beginning after December 15, 2010. As this guidance
provides only disclosure requirements, the adoption of this
standard will not impact the Companys results of
operations, cash flows or financial position.
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,
which has been incorporated in ASC-275, Risks and
Uncertainties, or ASC 275, and ASC-350,
Intangibles Goodwill and Other, or ASC 350.
FSP
No. FAS 157-2,
Effective Date of FASB Statement No. 157, which has
been incorporated in ASC 820.
SFAS No. 161,
Disclosures About Derivative Instruments and Hedging
Activities, which has been incorporated in ASC-815,
Derivatives and Hedging, or ASC 815.
FSP No. FAS 132(R)-1,
Employers Disclosures about Postretirement Benefit Plan
Assets, which has been incorporated in ASC-715,
Compensation-Retirement Benefits, or ASC 715.
EITF
No. 07-5,
Determining Whether an Instrument (or Embedded Feature) Is
Indexed to an Entitys Own Stock, which has been
incorporated in ASC 718, Compensation-Equity Compensation,
or ASC 718, and ASC 815.
EITF
No. 08-5,
Issuers Accounting for Liabilities Measured at Fair
Value with a Third-Party Credit Enhancement, which has been
incorporated in ASC 820.
EITF
No. 08-6,
Equity Method Investment Accounting Considerations, which
has been incorporated in ASC-323, Investments-Equity Method
and Joint Ventures, or ASC 323.
157
|
|
Note 3
|
Business
Acquisitions
|
Acquisition
of Reliant Energy
General
On May 1, 2009, NRG, through its wholly-owned subsidiary
NRG Retail LLC, acquired Reliant Energy, which consisted of the
entire Texas electric retail business operations of RRI,
including the exclusive use of the trade name
Reliant and related branding rights. 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
Mass customers in Texas, with approximately 1.5 million
Mass customers as of December 31, 2009. Reliant Energy is
also the largest electricity and energy services provider, based
on load, to C&I customers in Texas with approximately
0.1 million C&I customers, based on metered locations
as of December 31, 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 is
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. This combination of generation and
retail allows for a reduction in actual and contingent
collateral, initially through offsetting transactions and over
time by reducing the need to hedge the retail power supply
through third parties. In addition, with Reliant Energys
base of retail customers, NRG now has a customer interface with
the scale that is important to the successful deployment of
consumer facing energy technologies and services.
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 Power
Marketing LLC, or PML, and Reliant Energy Power Supply LLC, or
REPS, wholly-owned subsidiaries of NRG, modified or novated
certain transactions with counterparties to transfer PMLs
in-the-money
transactions to REPS and moved $522 million of cash
collateral held by NRG to Merrill Lynch, thereby reducing
Merrill Lynchs actual and contingent collateral supporting
Reliant Energy
out-of-money
positions. Through October 5, 2009, these trades with
counterparties were still open, thus there was no impact on
NRGs consolidated financial statements, and NRG continued
to record unrealized and realized gains/losses for these novated
trades in its Texas and Northeast segments. The monthly fee for
the CSRA was 5.875% on an annualized basis of the predetermined
exposure.
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
required that the Company comply with all terms of the CSRA. NRG
initially drew $25 million under the facility, which
accrued interest at the prime rate. The $25 million
outstanding under this facility was repaid, and the facility was
terminated on October 5, 2009. See further discussion below.
Reliant Energy conducts its business through RERH Holdings, LLC
and subsidiaries, or RERH, Reliant Energy Texas Retail, LLC, and
Reliant Energy Services Texas, LLC. Through October 5,
2009, the obligations of Reliant Energy under the CSRA were
secured by first liens on substantially all of the assets of
RERH, and the obligations of RERH under the CSRA were
non-recourse to NRG and its other non-pledgor subsidiaries.
The Company executed an amendment of the existing CSRA with
Merrill Lynch, or CSRA Amendment, which became effective
October 5, 2009. In connection with the CSRA Amendment, the
Company recorded refinancing expense of $20 million in its
results of operations for the year ended December 31, 2009,
primarily related to the write-off of previously deferred
financing costs. The CSRA Amendment removed the first liens
associated with the CSRA, and RERH subsequently became a
guarantor of the Companys obligations under its Senior
Notes. See Note 29, Condensed Consolidating Financial
Information, for further discussion of NRGs guarantees
under its Senior Notes.
158
In connection with the CSRA Amendment, NRG net settled certain
REPS transactions with counterparties and received
$165 million in net cash consideration. Merrill Lynch
returned $250 million of previously posted cash collateral
and released liens on $322 million of unrestricted cash
held at Reliant Energy. See Note 6, Accounting for
Derivative Instruments and Hedging Activities, for the
accounting impact of these settlements.
Pursuant to the CSRA Amendment, the Company was required to post
collateral for any net liability derivatives and other static
margin associated with supply for Reliant Energy. In connection
with this amendment, NRG posted $366 million of cash
collateral to Merrill Lynch and other counterparties, returned
$53 million of counterparty collateral, issued letters of
credit of $206 million, and received $45 million in
counterparty collateral. The funds posted by the Company were
sourced from a portion of the proceeds from the June 5,
2009 issuance of the 2019 Senior Notes. See Note 12,
Debt and Capital Leases, for further discussion of the
2019 Senior Notes.
Under the amended CSRA, the parties had agreed to settle any
outstanding wholesale obligations under the CSRA Amendment by
January 29, 2010. As of that date, there was one remaining
wholesale counterparty, for which NRG provided Merrill Lynch
with a $10 million letter of credit to protect them from
any potential liability. The parties continue to work to settle
all outstanding obligations, including C&I counterparties,
by April 30, 2010.
Acquisition
method of accounting
The acquisition of Reliant Energy is accounted for under the
acquisition method of accounting in accordance with ASC 805.
Accordingly, NRG has conducted an assessment of net assets
acquired and has recognized provisional amounts for identifiable
assets acquired and liabilities assumed at their estimated
acquisition date fair values, 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 evaluations necessary to assess the fair
values of certain net assets acquired and the amount of goodwill
(if any) to be recognized are still in process. The provisional
amounts recognized are subject to revision until the evaluations
are completed and to the extent that additional information is
obtained about the facts and circumstances that existed as of
the acquisition date. Any changes to the fair value assessments
will affect the final balance of goodwill.
NRG paid RRI $287.5 million in cash at closing, funded from
NRGs cash on hand. NRG also made payments to RRI of
$78 million as remittances of acquired net working capital.
In addition, the Company expects to remit approximately
$4 million of acquired net working capital to RRI by the
second quarter 2010, bringing the total cash consideration to
approximately $370 million. 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 consolidated statement of operations.
This non-cash gain is considered a component of consideration in
accordance with ASC 805, and together with cash consideration,
brings total consideration to approximately $401 million.
The following table summarizes the 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
|
|
|
790
|
|
Customer relationships
|
|
|
399
|
|
Trade names
|
|
|
178
|
|
In-market energy supply contracts
|
|
|
54
|
|
Other
|
|
|
6
|
|
Derivative assets
|
|
|
1,942
|
|
Deferred tax asset, net
|
|
|
14
|
|
Goodwill
|
|
|
|
|
|
|
|
|
|
Total assets acquired
|
|
$
|
4,090
|
|
|
|
|
|
|
159
|
|
|
|
|
|
|
(In millions)
|
|
Liabilities
|
|
|
|
|
Current and non-current liabilities
|
|
$
|
550
|
|
Derivative liabilities
|
|
|
2,996
|
|
Out-of-market
energy supply and customer contracts
|
|
|
143
|
|
|
|
|
|
|
Total liabilities assumed
|
|
$
|
3,689
|
|
|
|
|
|
|
Net assets acquired
|
|
$
|
401
|
|
|
|
|
|
|
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 has
collected substantially all of 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.
The Company, through its acquisition of Reliant Energy, is
subject to material contingencies relating to Excess Mitigation
Credits (see Note 22, Commitments and Contingencies)
and Retail Replacement Reserve (see Note 23, 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 ASC-450,
Contingencies, or ASC 450, 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 26,
Guarantees, for further discussion.
Measurement
period adjustments
The following measurement period adjustments to the provisional
amounts, attributable to refinement of the underlying appraisal
assumptions, were recognized during 2009 subsequent to the
acquisition date:
|
|
|
|
|
|
|
Increase/(Decrease)
|
|
|
|
(In millions)
|
|
|
Assets
|
|
|
|
|
Intangible assets subject to amortization:
|
|
|
|
|
In-market customer contracts
|
|
$
|
57
|
|
Customer relationships
|
|
|
(82
|
)
|
In-market energy supply contracts
|
|
|
17
|
|
Deferred tax asset, net
|
|
|
3
|
|
|
|
|
|
|
Total assets acquired
|
|
|
(5
|
)
|
|
|
|
|
|
Liabilities
|
|
|
|
|
Out-of-market
energy supply and customer contracts
|
|
|
(5
|
)
|
|
|
|
|
|
Total liabilities assumed
|
|
|
(5
|
)
|
|
|
|
|
|
Net assets acquired
|
|
$
|
|
|
|
|
|
|
|
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 ASC 820. Significant inputs were as
follows:
|
|
|
|
|
Customer contracts The fair values of the
customer contracts, representing those with Reliant
Energys C&I customers, were 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
|
160
|
|
|
|
|
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 Mass customer
base, 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 expense, 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 remaining useful life of the trade
names were determined by considering various factors, such as
turnover and name changes in the independent power producer and
utility industries, the current age of the Reliant brand,
managements intent to continue using the name at the
current time, and feedback from external consultants regarding
their experience with similar trade names. The trade names are
amortized to depreciation and amortization expense, on a
straight-line basis, over 15 years.
|
|
|
|
Energy supply contracts The fair values of
the in-market and
out-of-market
energy supply contracts were determined in accordance with ASC
820. 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 was 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 values of derivative assets and liabilities as of the
acquisition date were determined in accordance with ASC 820. The
breakdown of Level 1, 2 and 3 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Derivative assets
|
|
$
|
534
|
|
|
$
|
1,375
|
|
|
$
|
33
|
|
|
$
|
1,942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
$
|
534
|
|
|
$
|
2,357
|
|
|
$
|
105
|
|
|
$
|
2,996
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
of acquired intangible assets and
out-of-market
contracts
See Note 11, Goodwill and Other Intangibles, for the
estimated remaining amortization related to acquired intangible
assets and
out-of-market
contracts, including Customer contracts, Customer relationships,
Trade names and Energy supply contracts, for 2010
2014.
Supplemental
Pro-Forma Information
Since the acquisition date, Reliant Energy contributed
$4.2 billion of operating revenues and $1.0 billion in
net income attributable to NRG. See Note 18, Segment
Reporting, for more information on the Companys
segment results.
161
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:
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended
|
|
|
December 31,
|
|
|
2009
|
|
2008
|
|
|
(In millions, except
|
|
|
per share amounts)
|
|
Operating revenues
|
|
$
|
10,799
|
|
|
$
|
15,124
|
|
Net income attributable to NRG Energy, Inc.
|
|
|
945
|
|
|
|
419
|
|
Earnings per share attributable to NRG common stockholders:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
3.71
|
|
|
$
|
1.55
|
|
Diluted
|
|
$
|
3.45
|
|
|
$
|
1.48
|
|
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.
Other
Acquisitions
The Company also completed the following acquisitions during the
fourth quarter of 2009, for combined consideration totaling
$68 million:
Bluewater Wind LLC On November 9, 2009,
NRG, through its wholly-owned subsidiary NRG Bluewater Holdings
LLC, acquired all the subsidiaries of Bluewater Wind LLC (such
subsidiaries, together with NRG Bluewater Holdings LLC, NRG
Bluewater). NRG Bluewater, a developer of off-shore wind energy,
has a number of projects that are in various stages of
development along the eastern seaboard and the Great Lakes
region of the U.S.
FSE Blythe 1, LLC On November 20, 2009,
NRG, through its wholly owned subsidiary NRG Solar LLC, acquired
FSE Blythe 1, LLC, or Blythe Solar, from First Solar, Inc. On
December 18, 2009, construction was completed and
commercial operations began for Blythe Solars 20 MW
utility-scale photovoltaic, or PV, solar facility located in
Riverside County in southeastern California. The Blythe Solar PV
field provides electricity to Southern California Edison under a
20-year PPA.
|
|
Note 4
|
Discontinued
Operations and Dispositions
|
Discontinued
Operations
NRG classifies material business operations and gains/(losses)
recognized on sales as discontinued operations for businesses
that were sold or have met the required criteria for such
classification. ASC 360 requires that discontinued operations be
valued on an
asset-by-asset
basis at the lower of carrying amount or fair value, less costs
to sell. In applying the provisions of ASC 360, the
Companys management considers cash flow analyses, bids,
and offers related to those assets and businesses. In accordance
with the provisions of ASC 360, assets held by discontinued
operations are not depreciated commencing with their
classification as such.
NRGs discontinued operations reflect the disposal of
ITISA, reported in the Companys international segment. On
April 28, 2008, NRG completed the sale of its 100% interest
in Tosli Acquisition B.V, which held all NRGs interest in
ITISA, to Brookfield Renewable Power Inc. (previously Brookfield
Power Inc.), a wholly-owned subsidiary of Brookfield Asset
Management Inc. In addition, the purchase price adjustment
contingency under the sale agreement was resolved on
August 7, 2008. In connection with the sale, NRG received
$300 million of cash proceeds from Brookfield, and removed
$163 million of assets, including $59 million of cash,
$122 million of liabilities, including $63 million of
debt, and $15 million in foreign currency translation
adjustment from its 2008 consolidated balance sheet. The Company
recorded a pre-tax gain on the disposal of ITISA of
$273 million in the
162
year ended December 31, 2008. Summarized results of ITISA,
reflected within discontinued operations for the years ended
December 31, 2008, and 2007, were as follows:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
20
|
|
|
$
|
50
|
|
Operating costs and other expenses
|
|
|
9
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
Pre-tax income from operations of discontinued components
|
|
|
11
|
|
|
|
23
|
|
Income tax expense
|
|
|
3
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Income from operations of discontinued components
|
|
|
8
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
Disposal of discontinued components pre-tax gain
|
|
|
273
|
|
|
|
|
|
Income tax expense
|
|
|
109
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain on disposal of discontinued components, net of income
taxes
|
|
|
164
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from discontinued operations, net of income taxes
|
|
$
|
172
|
|
|
$
|
17
|
|
|
|
|
|
|
|
|
|
|
Other
Dispositions
MIBRAG On June 10, 2009, NRG completed
the sale of its 50% ownership interest in Mibrag B.V. to a
consortium of Severoćeské doly Chomutov, a member of
the CEZ Group, and J&T Group. Mibrag B.V.s principal
holding was MIBRAG, which was 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
($284 million at an exchange rate of 1.40 U.S.$/EUR), net
of transaction costs. During the year ended December 31,
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 year ended
December 31, 2009, NRG recorded an exchange loss of
$24 million on the contract within Other (loss)/income,
net. NRG provided certain indemnities in connection with its
share of the transaction. See Note 26, Guarantees,
for further discussion.
Red Bluff and Chowchilla On January 3,
2007, NRG completed the sale of the Companys Red Bluff and
Chowchilla II power plants to an entity controlled by
Wayzata Investment Partners LLC. These power plants, located in
California, are fueled by natural gas, with generating capacity
of 45 MW and 49 MW, respectively.
|
|
Note 5
|
Fair
Value of Financial Instruments
|
The estimated carrying values and fair values of NRGs
recorded financial instruments related to continuing operations
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Carrying Amount
|
|
Fair Value
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
(In millions)
|
|
Cash and cash equivalents
|
|
$
|
2,304
|
|
|
$
|
1,494
|
|
|
$
|
2,304
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
177
|
|
|
|
754
|
|
|
|
177
|
|
|
|
754
|
|
Restricted cash
|
|
|
2
|
|
|
|
16
|
|
|
|
2
|
|
|
|
16
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
361
|
|
|
|
494
|
|
|
|
361
|
|
|
|
494
|
|
Investment in
available-for-sale
securities (classified within other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
9
|
|
|
|
7
|
|
|
|
9
|
|
|
|
7
|
|
Marketable equity securities
|
|
|
5
|
|
|
|
2
|
|
|
|
5
|
|
|
|
2
|
|
163
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
Carrying Amount
|
|
Fair Value
|
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
|
(In millions)
|
|
Trust fund investments
|
|
|
369
|
|
|
|
305
|
|
|
|
369
|
|
|
|
305
|
|
Notes receivable
|
|
|
231
|
|
|
|
156
|
|
|
|
238
|
|
|
|
166
|
|
Derivative assets
|
|
|
2,319
|
|
|
|
5,485
|
|
|
|
2,319
|
|
|
|
5,485
|
|
Long-term debt, including current portion
|
|
|
8,295
|
|
|
|
8,019
|
|
|
|
8,211
|
|
|
|
7,475
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
177
|
|
|
|
760
|
|
|
|
177
|
|
|
|
760
|
|
Derivative liabilities
|
|
$
|
1,860
|
|
|
$
|
4,489
|
|
|
$
|
1,860
|
|
|
$
|
4,489
|
|
For cash and cash equivalents, funds deposited by
counterparties, restricted cash, and cash collateral paid and
received in support of energy risk management activities, the
carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of
marketable securities is based on quoted market prices for those
instruments. Trust fund investments are comprised of various
U.S. debt and equity securities carried at fair market
value.
The fair value of notes receivable, debt securities and certain
long-term debt are based on expected future cash flows
discounted at market interest rates. The fair value of long-term
debt is based on quoted market prices for these instruments that
are publicly traded, or estimated based on the income approach
valuation technique for non-publicly traded debt using current
interest rates for similar instruments with equivalent credit
quality.
Fair
Value Accounting under ASC 820
ASC 820 establishes a fair value hierarchy that prioritizes the
inputs to valuation techniques used to measure fair value into
three levels as follows:
|
|
|
|
|
Level 1 quoted prices (unadjusted) in active
markets for identical assets or liabilities that the Company has
the ability to access as of the measurement date. NRGs
financial assets and liabilities utilizing Level 1 inputs
include active exchange-traded securities, energy derivatives,
and trust fund investments.
|
|
|
|
Level 2 inputs other than quoted prices
included within Level 1 that are directly observable for
the asset or liability or indirectly observable through
corroboration with observable market data. NRGs financial
assets and liabilities utilizing Level 2 inputs include
fixed income securities, exchange-based derivatives, and over
the counter derivatives such as swaps, options and forwards.
|
|
|
|
Level 3 unobservable inputs for the asset or
liability only used when there is little, if any, market
activity for the asset or liability at the measurement date.
NRGs financial assets and liabilities utilizing
Level 3 inputs include infrequently-traded,
non-exchange-based derivatives and commingled investment funds,
and are measured using present value pricing models.
|
In accordance with ASC 820, the Company determines the level in
the fair value hierarchy within which each fair value
measurement in its entirety falls, based on the lowest level
input that is significant to the fair value measurement in its
entirety.
164
Recurring
Fair Value Measurements
The following table presents assets and liabilities measured and
recorded at fair value on the Companys consolidated
balance sheet on a recurring basis and their level within the
fair value hierarchy as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Cash and cash equivalents
|
|
$
|
2,304
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2,304
|
|
Funds deposited by counterparties
|
|
|
177
|
|
|
|
|
|
|
|
|
|
|
|
177
|
|
Restricted cash
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
361
|
|
|
|
|
|
|
|
|
|
|
|
361
|
|
Investment in
available-for-sale
securities (classified within other non-current assets):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt securities
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
9
|
|
Marketable equity securities
|
|
|
5
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Trust fund investments
|
|
|
214
|
|
|
|
118
|
|
|
|
37
|
|
|
|
369
|
|
Derivative assets
|
|
|
489
|
|
|
|
1,767
|
|
|
|
63
|
|
|
|
2,319
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
3,552
|
|
|
$
|
1,885
|
|
|
$
|
109
|
|
|
$
|
5,546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash collateral received in support of energy risk management
activities
|
|
$
|
177
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
177
|
|
Derivative liabilities
|
|
|
501
|
|
|
|
1,283
|
|
|
|
76
|
|
|
|
1,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
$
|
678
|
|
|
$
|
1,283
|
|
|
$
|
76
|
|
|
$
|
2,037
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table reconciles, for the year ended
December 31, 2009, the beginning and ending balances for
financial instruments that are recognized at fair value in the
consolidated financial statements at least annually using
significant unobservable inputs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurement Using Significant
|
|
|
|
Unobservable Inputs
|
|
|
|
(Level 3)
|
|
|
|
|
|
|
Trust Fund
|
|
|
|
|
|
|
|
|
|
Debt Securities
|
|
|
Investments
|
|
|
Derivatives(a)
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Beginning balance as of January 1, 2009
|
|
$
|
7
|
|
|
$
|
31
|
|
|
$
|
49
|
|
|
$
|
87
|
|
Total gains and losses (realized/unrealized):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Included in OCI
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Included in earnings
|
|
|
|
|
|
|
|
|
|
|
(97
|
)
|
|
|
(97
|
)
|
Included in nuclear decommissioning obligations
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
Purchases/(sales), net
|
|
|
|
|
|
|
(3
|
)
|
|
|
1
|
|
|
|
(2
|
)
|
Transfers, out of Level 3
|
|
|
|
|
|
|
|
|
|
|
34
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ending balance as of December 31, 2009
|
|
$
|
9
|
|
|
$
|
37
|
|
|
$
|
(13
|
)
|
|
$
|
33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 December 31, 2009
|
|
$
|
|
|
|
$
|
|
|
|
$
|
25
|
|
|
$
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Consists of derivatives assets and
liabilities, net.
|
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.
Non-derivative
fair value measurements
NRGs investment in debt securities are classified as
Level 3 and consist of non-traded debt instruments that are
valued based on third-party market value assessments.
165
The trust fund investments are held primarily to satisfy
NRGs nuclear decommissioning obligations. These trust fund
investments hold debt and equity securities directly and equity
securities indirectly through commingled funds. The fair values
of equity securities held directly by the trust funds are based
on quoted prices in active markets and are categorized in
Level 1. In addition, U.S. Treasury securities are
categorized as Level 1 because they trade in a highly
liquid and transparent market. The fair values of fixed income
securities, excluding U.S. Treasury securities, are based
on evaluated prices that reflect observable market information,
such as actual trade information of similar securities, adjusted
for observable differences and are categorized in Level 2.
Commingled funds, which are analogous to mutual funds, are
maintained by investment companies and hold certain investments
in accordance with a stated set of fund objectives. The fair
value of commingled funds are based on net asset values per fund
share (the unit of account), derived from the quoted prices in
active markets of the underlying equity securities. However,
because the shares in the commingled funds are not publicly
quoted, not traded in an active market and are subject to
certain restrictions regarding their purchase and sale, the
commingled funds are categorized in Level 3. See also
Note 7, Nuclear Decommissioning Trust Fund.
Derivative
fair value measurements
A small portion of NRGs contracts are exchange-traded
contracts with readily available quoted market prices. The
majority of NRGs contracts are non-exchange-traded
contracts valued using prices provided by external sources,
primarily price quotations available through brokers or
over-the-counter
and on-line exchanges. For the majority of NRG markets, the
Company receives quotes from multiple sources. To the extent
that NRG receives multiple quotes, the Companys prices
reflect the average of the bid-ask mid-point prices obtained
from all sources that NRG believes provide the most liquid
market for the commodity. If the Company receives one quote,
then the mid-point of the bid-ask spread for that quote is used.
The terms for which such price information is available vary by
commodity, region and product. A significant portion of the fair
value of the Companys derivative portfolio is based on
price quotes from brokers in active markets who regularly
facilitate those transactions and the Company believes such
price quotes are executable. The Company does not use third
party sources that derive price based on proprietary models or
market surveys. The remainder of the assets and liabilities
represents contracts for which external sources or observable
market quotes are not available. These contracts are valued
based on various valuation techniques including but not limited
to internal models based on a fundamental analysis of the market
and extrapolation of observable market data with similar
characteristics. Contracts valued with prices provided by models
and other valuation techniques make up 3% 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 uses the
counterpartys default swap rate. If the exposure under a
specific master agreement is a liability, the Company uses
NRGs default swap rate. The credit reserve is added to the
discounted fair value to reflect the exit price that a market
participant would be willing to receive to assume NRGs
liabilities or that a market participant would be willing to pay
for NRGs assets. As of December 31, 2009, the credit
reserve resulted in a $1 million increase in fair value
which is composed of a $1 million loss in OCI and a
$2 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 December 31, 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.
Under the guidance of ASC 815, entities may choose to offset
cash collateral paid or received against the fair value of
derivative positions executed with the same counterparties under
the same master netting agreements. The Company has chosen not
to offset positions as defined in ASC 815. As of
December 31, 2009, the Company recorded $361 million
of cash collateral paid and $177 million of cash collateral
received on its balance sheet.
166
Concentration
of Credit Risk
In addition to the credit risk discussion as disclosed in
Note 2, Summary of Significant Accounting Policies,
the following item is a discussion of the concentration of
credit risk for the Companys financial instruments. Credit
risk relates to the risk of loss resulting from non-performance
or non-payment by counterparties pursuant to the terms of their
contractual obligations. 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, prepayment arrangements, or volumetric
limits (iv) the use of payment netting agreements; and
(v) the use of master netting agreements that allow for the
netting of positive and negative exposures of various contracts
associated with a single counterparty. Risks surrounding
counterparty performance and credit could ultimately impact the
amount and timing of expected cash flows. The Company seeks to
mitigate counterparty risk with a diversified portfolio of
counterparties, including nine 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.
Since the credit crisis began in late 2008, NRG has taken
several additional steps to mitigate credit risk including the
use of netting arrangements, entering contracts with collateral
thresholds, setting volumetric limits with certain
counterparties and restricting trading relationships with
counterparties where exposure was high or where credit quality
of the counterparty had deteriorated. NRG avoids concentration
of counterparties whenever possible and applies credit policies
that include an evaluation of counterparties financial
condition, collateral requirements and the use of standard
agreements that allow for netting and other security.
As of December 31, 2009, total credit exposure to
substantially all counterparties was $1.3 billion and NRG
held collateral (cash and letters of credit) against those
positions of $186 million resulting in a net exposure of
$1.1 billion. Total credit exposure is discounted at the
risk free rate.
The following table highlights the credit quality and the net
counterparty credit exposure by industry sector. Net
counterparty credit exposure is defined as the aggregate net
asset position for NRG with counterparties where netting is
permitted under the enabling agreement and includes all cash
flow,
mark-to-market
and NPNS, and non-derivative transactions. The exposure is shown
net of collateral held, includes amounts net of receivables or
payables.
|
|
|
|
|
|
|
Net Exposure (a)
|
|
|
|
as of December 31, 2009
|
|
Category
|
|
(% of Total)
|
|
Financial institutions
|
|
|
69
|
%
|
Utilities, energy merchants, marketers and other
|
|
|
25
|
|
Coal suppliers
|
|
|
3
|
|
ISOs
|
|
|
3
|
|
|
|
|
|
|
Total as of December 31, 2009
|
|
|
100
|
%
|
|
|
|
|
|
|
|
Net Exposure (a)
|
|
|
|
as of December 31, 2009
|
|
Category
|
|
(% of Total)
|
|
Investment grade
|
|
|
90
|
%
|
Non-rated
|
|
|
8
|
|
Non-Investment grade
|
|
|
2
|
|
|
|
|
|
|
Total as of December 31, 2009
|
|
|
100
|
%
|
|
|
|
(a)
|
|
Credit exposure excludes California
tolling, uranium, coal transportation, New England RMR, certain
cooperative load contracts, and Texas Westmoreland coal
contracts. The aforementioned exposures were excluded for
various reasons including regulatory support or liens held
against the contracts which serve to reduce the risk of loss, or
credit risks for certain contracts are not readily measurable
due to a lack of market reference prices.
|
NRG has credit risk exposure to certain counterparties
representing more than 10% of total net exposure and the
aggregate of such counterparties was $351 million.
Approximately 82% of NRGs positions relating to credit
risk roll-off by the end of 2012. Changes in hedge positions and
market prices will affect credit exposure and counterparty
concentration. Given the credit quality, diversification and
term of the exposure in the portfolio, NRG
167
does not anticipate a material impact on the Companys
financial position or results of operations from nonperformance
by any of NRGs counterparties.
NRG is exposed to retail credit risk through its competitive
electricity supply business, which serves C&I customers and
the Mass market in Texas. Retail credit risk results when a
customer fails to pay for services rendered. The losses could be
incurred from nonpayment of customer accounts receivable and any
in-the-money
forward value. NRG manages retail credit risk through the use of
established credit policies that include monitoring of the
portfolio, and the use of credit mitigation measures such as
deposits or prepayment arrangements.
As of December 31, 2009, the Companys credit exposure
to C&I customers was diversified across many customers and
various industries. No one customer represented more than 2% of
total exposure and the majority of the customers have investment
grade credit quality, as determined by NRG.
NRG is also exposed to credit risk relating to its
1.5 million Mass customers, which may result in a write-off
of a bad debt. The current economic conditions may affect the
Companys customers ability to pay bills in a timely
manner, which could increase customer delinquencies and may lead
to an increase in bad debt expense.
|
|
Note 6
|
Accounting
for Derivative Instruments and Hedging Activities
|
ASC 815 requires NRG to recognize all derivative instruments on
the balance sheet as either assets or liabilities and to measure
them at fair value each reporting period unless they qualify for
a 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 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 ASC 815, certain derivative
instruments may qualify for the NPNS exception and are therefore
exempt from fair value accounting treatment. ASC 815 applies to
NRGs energy related commodity contracts, interest rate
swaps, and foreign exchange contracts.
As the Company engages principally in the trading and marketing
of its generation assets and retail business, some of NRGs
commercial activities qualify for hedge accounting under the
requirements of ASC 815. In order for the generation assets to
qualify, the physical generation and sale of electricity should
be highly probable at inception of the trade and throughout the
period it is held, as is the case with the Companys
baseload plants. For this reason, many trades in support of
NRGs baseload units normally qualify for NPNS or cash flow
hedge accounting treatment, and trades in support of NRGs
peaking units asset optimization will generally not
qualify for hedge accounting treatment, with any changes in fair
value likely to be reflected on a
mark-to-market
basis in the statement of operations. Most of the retail load
contracts either qualify for the NPNS exception or fail to meet
the criteria for a derivative and the majority of the supply
contracts are recorded under
mark-to-market
accounting. All of NRGs hedging and trading activities are
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.
|
168
|
|
|
|
|
Swap agreements, which require payments to or from
counter-parties based upon the differential between two prices
for a predetermined contractual, or notional, quantity.
|
|
|
|
Option contracts, which convey the right or obligation to
purchase or sell a commodity.
|
|
|
|
Weather and hurricane derivative products used to mitigate a
portion of Reliant Energys lost revenue due to weather.
|
The objectives for entering into derivative contracts designated
as hedges include:
|
|
|
|
|
Fixing the price for a portion of anticipated future electricity
sales through the use of various derivative instruments
including gas collars and swaps at a level that provides an
acceptable return on the Companys electric generation
operations.
|
|
|
|
Fixing the price of a portion of anticipated fuel purchases for
the operation of NRGs power plants.
|
|
|
|
Fixing the price of a portion of anticipated energy purchases to
supply Reliant Energys customers.
|
NRGs trading activities 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.
As of December 31, 2009, NRG had hedge and non-hedge
energy-related derivative financial instruments, and other
energy-related contracts that did not qualify as derivative
financial instruments extending through December 2026. As of
December 31, 2009, NRGs derivative assets and
liabilities consisted primarily of the following:
|
|
|
|
|
Forward and financial contracts for the purchase/sale of
electricity and related products economically hedging NRGs
generation assets forecasted output or NRGs retail
load obligations through 2015.
|
|
|
|
Forward and financial contracts for the purchase of fuel
commodities relating to the forecasted usage of NRGs
generation assets into 2017.
|
Also, as of December 31, 2009, NRG had other energy-related
contracts that qualified for the NPNS exception and were
therefore exempt from fair value accounting treatment under the
guidelines established by ASC 815 as follows:
|
|
|
|
|
Power sales and capacity contracts extending to 2025.
|
Also, as of December 31, 2009, NRG had other energy-related
contracts that did not qualify as derivatives under the
guidelines established by ASC 815 as follows:
|
|
|
|
|
Load-following forward electric sale contracts extending through
2026;
|
|
|
|
Power Tolling contracts through 2029;
|
|
|
|
Lignite purchase contract through 2018;
|
|
|
|
Power transmission contracts through 2015;
|
|
|
|
Natural gas transportation contracts and storage agreements
through 2018; and
|
|
|
|
Coal transportation contracts through 2016.
|
Interest
Rate Swaps
NRG is exposed to changes in interest rates through the
Companys issuance of variable and fixed rate debt. In
order to manage the Companys interest rate risk, NRG
enters into interest-rate swap agreements. As of
December 31, 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.
169
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 December 31, 2009. Option contracts
are reflected using delta volume. Delta volume equals the
notional volume of an option adjusted for the probability that
the option will be
in-the-money
at its expiration date.
|
|
|
|
|
|
|
|
|
|
|
Total Volume as
|
Commodity
|
|
Units
|
|
of December 31, 2009
|
|
|
|
|
(In millions)
|
|
Emissions
|
|
Short Ton
|
|
|
(2
|
)
|
Coal
|
|
Short Ton
|
|
|
55
|
|
Natural Gas
|
|
MMBtu
|
|
|
(484
|
)
|
Oil
|
|
Barrel
|
|
|
1
|
|
Power(a)
|
|
MWH
|
|
|
(41
|
)
|
Interest
|
|
Dollar
|
|
$
|
3,291
|
|
|
|
|
(a)
|
|
Power volumes include capacity
sales. |
Fair
Value of Derivative Instruments
The Company has elected to disclose derivative assets and
liabilities on a
trade-by-trade
basis and does not offset amounts at the counterparty master
agreement level. Also, collateral received or paid on the
Companys derivative assets or liabilities are recorded on
a separate line item on the balance sheet. The Company has
chosen not to offset positions as defined in ASC 815. As of
December 31, 2009, the Company recorded $361 million
of cash collateral paid and $177 million of cash collateral
received on its balance sheet. The following table summarizes
the fair value within the derivative instrument valuation on the
balance sheet as of December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
Fair Value
|
|
|
|
Derivatives Asset
|
|
|
Derivatives Liability
|
|
|
|
(In millions)
|
|
|
Derivatives Designated as Cash Flow or Fair Value Hedges:
|
|
|
|
|
|
|
|
|
Interest rate contracts current
|
|
$
|
|
|
|
$
|
2
|
|
Interest rate contracts long-term
|
|
|
8
|
|
|
|
106
|
|
Commodity contracts current
|
|
|
300
|
|
|
|
12
|
|
Commodity contracts long-term
|
|
|
508
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives Designated as Cash Flow or Fair Value
Hedges
|
|
|
816
|
|
|
|
126
|
|
Derivatives Not Designated as Cash Flow or Fair Value
Hedges:
|
|
|
|
|
|
|
|
|
Commodity contracts current
|
|
|
1,336
|
|
|
|
1,459
|
|
Commodity contracts long-term
|
|
|
167
|
|
|
|
275
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives Not Designated as Cash Flow or Fair Value
Hedges
|
|
|
1,503
|
|
|
|
1,734
|
|
|
|
|
|
|
|
|
|
|
Total Derivatives
|
|
$
|
2,319
|
|
|
$
|
1,860
|
|
|
|
|
|
|
|
|
|
|
Impact of
Derivative Instruments on the Statement of Operations
The following table summarizes the amount of gain/(loss)
resulting from fair value hedges reflected in interest
income/(expense) for interest rate contracts:
|
|
|
|
|
|
|
Years Ended
|
Amount of gain/(loss) recognized
|
|
December 31, 2009
|
|
|
(In millions)
|
|
Derivative
|
|
$
|
(6
|
)
|
Senior Notes (hedged item)
|
|
$
|
6
|
|
170
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
|
|
|
|
gain
|
|
|
gain/(loss)
|
|
gain/(loss)
|
|
|
recognized in
|
|
recognized in
|
|
|
|
recognized in OCI
|
|
|
reclassified from
|
|
reclassified from
|
|
|
income
|
|
income
|
|
|
|
(effective portion)
|
|
|
Accumulated
|
|
Accumulated
|
|
|
(ineffective
|
|
(ineffective
|
|
Year ended December 31, 2009
|
|
after tax
|
|
|
OCI into Income
|
|
OCI into Income
|
|
|
portion)
|
|
portion)
|
|
|
|
(In millions)
|
|
|
Interest rate contracts
|
|
$
|
36
|
|
|
Interest expense
|
|
$
|
1
|
|
|
Interest expense
|
|
$
|
4
|
|
Commodity contracts
|
|
|
55
|
|
|
Operating revenue
|
|
|
(472
|
)
|
|
Operating revenue
|
|
|
45
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
91
|
|
|
|
|
$
|
(471
|
)
|
|
|
|
$
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
Year ended
|
Amount of gain/(loss) recognized in income or cost of
operations for derivatives
|
|
December 31, 2009
|
|
|
(In millions)
|
|
Location of gain/(loss) recognized in income for derivatives:
|
|
|
|
|
Operating revenues
|
|
$
|
(335
|
)
|
Cost of operations
|
|
$
|
842
|
|
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. The collateral required for
out-of-the-money
positions and net accounts payable for contracts that have
adequate assurance clauses that are in a net liability position
as of December 31, 2009, was $80 million. The
collateral required for
out-of-the-money
positions and net accounts payable for contracts with credit
rating contingent features that are in a net liability position
as of December 31, 2009, was $49 million. The Company
is also a party to certain marginable agreements where NRG has a
net liability position but the counterparty has not called for
the collateral due, which is approximately $3 million as of
December 31, 2009.
As of January 29, 2010, Merrill Lynch was no longer
providing credit support for any wholesale energy supply
contracts relating to the retail business. Merrill Lynch
continues to provide guaranties to certain C&I customers as
part of the credit sleeve arrangement. If Merrill Lynch were to
default, NRG would be required to post guaranties to replace
Merrill.
See Note 5, Fair Value of Financial Instruments, for
discussion regarding concentration of credit risk.
Accumulated
Other Comprehensive Income
The following table summarizes the effects of ASC 815 on
NRGs accumulated OCI balance attributable to hedged
derivatives, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Interest
|
|
|
|
|
Year ended December 31, 2009
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Accumulated OCI balance at December 31, 2008
|
|
$
|
406
|
|
|
$
|
(91
|
)
|
|
$
|
315
|
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
- Due to realization of previously deferred amounts
|
|
|
(335
|
)
|
|
|
1
|
|
|
|
(334
|
)
|
- Due to discontinuance of cash flow hedge accounting
|
|
|
(137
|
)
|
|
|
|
|
|
|
(137
|
)
|
Mark-to-market
of cash flow hedge accounting contracts
|
|
|
527
|
|
|
|
35
|
|
|
|
562
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2009
|
|
$
|
461
|
|
|
$
|
(55
|
)
|
|
$
|
406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains/(losses) expected to be realized from OCI during the next
12 months, net of $123 tax
|
|
$
|
213
|
|
|
$
|
(3
|
)
|
|
$
|
210
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Interest
|
|
|
|
|
Year ended December 31, 2008
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Accumulated OCI balance at December 31, 2007
|
|
$
|
(234
|
)
|
|
$
|
(31
|
)
|
|
$
|
(265
|
)
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
- Due to realization of previously deferred amounts
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
Mark-to-market
of cash flow hedge accounting contracts
|
|
|
640
|
|
|
|
(59
|
)
|
|
|
581
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2008
|
|
$
|
406
|
|
|
$
|
(91
|
)
|
|
$
|
315
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Interest
|
|
|
|
|
Year ended December 31, 2007
|
|
Commodities
|
|
|
Rate
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Accumulated OCI balance at December 31, 2006
|
|
$
|
193
|
|
|
$
|
16
|
|
|
$
|
209
|
|
Realized from OCI during the period:
|
|
|
|
|
|
|
|
|
|
|
|
|
- Due to realization of previously deferred amounts
|
|
|
(50
|
)
|
|
|
(2
|
)
|
|
|
(52
|
)
|
Mark-to-market
of cash flow hedge accounting contracts
|
|
|
(377
|
)
|
|
|
(45
|
)
|
|
|
(422
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated OCI balance at December 31, 2007
|
|
$
|
(234
|
)
|
|
$
|
(31
|
)
|
|
$
|
(265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009, the net balance in OCI relating to
ASC 815 was an unrecognized gain of approximately
$406 million, which is net of $247 million in income
taxes. As of December 31, 2008, the net balance in OCI
relating to ASC 815 was an unrecognized gain of approximately
$315 million, which was net of $194 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. On April 1, 2009, the required correlation
threshold for cash flow hedge accounting was achieved for these
transactions, and accordingly, these hedges were re-designated
as cash flow hedges.
As discussed in Note 3, Business Acquisitions, in
conjunction with the CSRA, PML and REPS modified or novated
certain transactions with counterparties. The novated
transactions are financial sales of natural gas to the
counterparties covering the period from 2009 through 2012 to
hedge NRGs Texas baseload generation. A portion of these
transactions were accounted for as cash flow hedges. The
effective portion of the fair value of these transactions
recorded in OCI was approximately $247 million. On the date
of novation, NRG elected to de-designate these cash flow hedges
and to recognize future changes in value in earnings
prospectively. As the underlying baseload power generation is
still probable, the gains through the date of novation related
to the cash flow hedges remain frozen in OCI and will be
amortized into income when the underlying power is generated.
Approximately $240 million of the fair values of these
transactions at the novation date were accounted for as
mark-to-market
transactions through the income statement both before and after
the novations.
As also discussed in Note 3, Business Acquisitions,
on October 5, 2009, the Company amended the CSRA with
Merrill Lynch. In connection with the CSRA amendment, NRG net
settled certain REPS
out-of-money
supply transactions with Merrill Lynch and paid
$104 million in consideration. In addition, NRG net settled
certain
in-the-money
REPS transactions with Morgan and received $269 million in
consideration. As noted above, the
in-the-money
transaction was previously novated by NRGs wholly owned
subsidiary PML to REPS. As these transactions were net settled,
the $245 million in OCI will continue to be frozen and will
be amortized into income when the underlying power from the
baseload plants are generated and the balance of
$24 million of previously recorded unrealized revenue was
recorded as a loss of $24 million in unrealized derivative
revenue and a $24 million gain in realized or financial
revenue. The net settlement on the Merrill Lynch transactions
resulted in a realized loss of $104 million and an
unrealized gain of $104 million due to the reversal of an
unrealized loss.
172
Statement
of Operations
In accordance with ASC 815, unrealized gains and losses
associated with changes in the fair value of derivative
instruments not accounted for as cash flow hedge derivatives and
ineffectiveness of hedge derivatives are reflected in current
period earnings.
The following table summarizes the pre-tax effects of economic
hedges that did not qualify for cash flow hedge accounting,
ineffectiveness on cash flow hedges, and trading activity on
NRGs statement of operations. These amounts are included
within operating revenues and cost of operations.
|
|
|
|
|
|
|
|
|
|
|
Year ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Unrealized
mark-to-market
results
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to economic hedges
|
|
$
|
(68
|
)
|
|
$
|
(38
|
)
|
Reversal of loss positions acquired as part of the Reliant
Energy acquisition as of May 1, 2009
|
|
|
656
|
|
|
|
|
|
Reversal of previously recognized unrealized gains on settled
positions related to trading activity
|
|
|
(157
|
)
|
|
|
(32
|
)
|
Reversal of previously recognized unrealized losses due to the
termination of positions related to the CSRA unwind
|
|
|
80
|
|
|
|
|
|
Net unrealized gains on open positions related to economic hedges
|
|
|
22
|
|
|
|
524
|
|
Gains/(losses) on ineffectiveness associated with open positions
treated as cash flow hedges
|
|
|
45
|
|
|
|
(24
|
)
|
Net unrealized (losses)/gains on open positions related to
trading activity
|
|
|
(26
|
)
|
|
|
95
|
|
|
|
|
|
|
|
|
|
|
Total unrealized gains
|
|
$
|
552
|
|
|
$
|
525
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Revenue/(expense) from operations - energy commodities
|
|
$
|
(290
|
)
|
|
$
|
525
|
|
Cost of operations
|
|
|
842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total impact to statement of operations
|
|
$
|
552
|
|
|
$
|
525
|
|
|
|
|
|
|
|
|
|
|
The $22 million gain from economic hedge positions includes
a gain of $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, offset by a
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 and a
$166 million decrease in value of forward purchases and
sales of natural gas, electricity and fuel due to decrease in
forward power and gas prices.
The Reliant Energys loss positions were acquired as of
May 1, 2009, and valued using forward prices on that date.
The $656 million roll-off amounts were offset by realized
losses at the settled prices and are reflected in revenue and
cost of operations during the same period.
For the year ended December 31, 2008, the unrealized gain
associated with changes in the fair value of derivative
instruments not accounted for as hedge derivatives of
$525 million was comprised of $524 million of fair
value increases in forward sales of electricity and fuel, a
$24 million loss due to the ineffectiveness associated with
financial forward contracted electric and gas sales,
$70 million from the reversal of
mark-to-market
gains which ultimately settled as financial and physical
revenues of which $38 million was related to economic
hedges and $32 million was related to trading activity.
These decreases were partially offset by $95 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 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
173
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 year ended December 31, 2009.
Discontinued Normal Purchase and Sale for Coal Purchases
- Due to lower coal-fired generation during the first
quarter 2009, the Companys coal consumption was lower than
forecasted. The Company net settled some of its coal purchases
under NPNS designation and thus was 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 year ended
December 31, 2009.
|
|
Note 7
|
Nuclear
Decommissioning Trust Fund
|
NRGs nuclear decommissioning trust fund assets, which are
for the decommissioning of STP, are comprised of securities
classified as
available-for-sale
and recorded at fair value based on actively quoted market
prices. Although NRG is responsible for managing the
decommissioning of its 44% interest in STP, the predecessor
utilities that owned STP are authorized by the PUCT to collect
decommissioning funds from their ratepayers to cover
decommissioning costs on behalf of NRG. NRC requirements
determine the decommissioning cost estimate which is the minimum
required level of funding. In the event that funds from the
ratepayers that accumulate in the nuclear decommissioning trust
are ultimately determined to be inadequate to decommission the
STP facilities, the utilities will be required to collect
through rate base all additional amounts, with no obligation
from NRG, provided that NRG has complied with PUCT rules and
regulations regarding decommissioning trusts. Following
completion of the decommissioning, if surplus funds remain in
the decommissioning trusts, any excess will be refunded to the
respective ratepayers of the utilities.
NRG accounts for the nuclear decommissioning trust fund in
accordance with ASC 980 Regulated Operations,
or ASC 980 because the Companys nuclear decommissioning
activities are subject to approval by the PUCT, with regulated
rates that are designed to recover all decommissioning costs and
that can be charged to and collected from the ratepayers per
PUCT mandate. Since the Company is in compliance with PUCT rules
and regulations regarding decommissioning trusts and the cost of
decommissioning is the responsibility of the Texas ratepayers,
not NRG, all realized and unrealized gains or losses (including
other-than-temporary
impairments) related to the Nuclear Decommissioning
Trust Fund are recorded to the Nuclear Decommissioning
Trust Liability to the ratepayers and are not included in
net income or accumulated other comprehensive income, consistent
with regulatory treatment.
The following table summarizes the aggregate fair values and
unrealized gains and losses (including
other-than-temporary
impairments) for the securities held in the trust funds as of
December 31, 2009 and 2008, as well as information about
the contractual maturities of those securities. The cost of
securities sold is determined on the specific identification
method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2009
|
|
|
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
average
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
|
|
|
Unrealized
|
|
|
Unrealized
|
|
|
maturities
|
|
|
|
|
|
Unrealized
|
|
|
Unrealized
|
|
|
|
Value
|
|
|
gains
|
|
|
losses
|
|
|
(years)
|
|
|
Fair Value
|
|
|
gains
|
|
|
losses
|
|
|
|
(In millions, except otherwise noted)
|
|
|
Cash and cash equivalents
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
U.S. government and federal agency obligations
|
|
|
23
|
|
|
|
1
|
|
|
|
|
|
|
|
19
|
|
|
|
21
|
|
|
|
2
|
|
|
|
|
|
Federal agency mortgage-backed securities
|
|
|
60
|
|
|
|
2
|
|
|
|
|
|
|
|
23
|
|
|
|
49
|
|
|
|
2
|
|
|
|
|
|
Commercial mortgage-backed securities
|
|
|
10
|
|
|
|
|
|
|
|
1
|
|
|
|
29
|
|
|
|
16
|
|
|
|
|
|
|
|
4
|
|
Corporate debt securities
|
|
|
48
|
|
|
|
3
|
|
|
|
1
|
|
|
|
10
|
|
|
|
37
|
|
|
|
1
|
|
|
|
2
|
|
Marketable equity securities
|
|
|
220
|
|
|
|
89
|
|
|
|
2
|
|
|
|
|
|
|
|
178
|
|
|
|
41
|
|
|
|
6
|
|
Foreign government fixed income securities
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
367
|
|
|
$
|
95
|
|
|
$
|
4
|
|
|
|
|
|
|
$
|
303
|
|
|
$
|
46
|
|
|
$
|
12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
174
The following tables summarize proceeds from sales of
available-for-sale
securities and the related realized gains and losses from these
sales. The cost of securities sold is determined on the specific
identification method.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Realized gains
|
|
$
|
2
|
|
|
$
|
11
|
|
|
$
|
6
|
|
Realized losses
|
|
|
(1
|
)
|
|
|
(33
|
)
|
|
|
(1
|
)
|
Proceeds from sale of securities
|
|
|
279
|
|
|
|
582
|
|
|
|
233
|
|
Inventory consists of:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Fuel oil
|
|
$
|
104
|
|
|
$
|
128
|
|
Coal/Lignite
|
|
|
288
|
|
|
|
189
|
|
Natural gas
|
|
|
9
|
|
|
|
11
|
|
Spare parts
|
|
|
137
|
|
|
|
127
|
|
Other
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Inventory
|
|
$
|
541
|
|
|
$
|
455
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 9
|
Capital
Leases and Notes Receivable
|
Notes receivable primarily consists of fixed and variable rate
notes secured by equity interests in partnerships and joint
ventures. NRGs notes receivable and capital leases as of
December 31, 2009, and 2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Capital Leases Receivable non-affiliates
|
|
|
|
|
|
|
|
|
VEAG Vereinigte Energiewerke AG, due August 31, 2021,
11.00%(a)
|
|
$
|
301
|
|
|
$
|
338
|
|
Other
|
|
|
5
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
Capital Leases non-affiliates
|
|
|
306
|
|
|
|
347
|
|
|
|
|
|
|
|
|
|
|
Notes Receivable affiliates
|
|
|
|
|
|
|
|
|
GenConn Energy LLC, due April 30, 2009, LIBOR +
3.75%(b)
current
|
|
|
|
|
|
|
36
|
|
Kraftwerke Schkopau GBR, indefinite maturity date,
6.91%-7.00%(c)
non-current
|
|
|
122
|
|
|
|
120
|
|
GCE Holding LLC which wholly-owns GenConn Energy LLC, indefinite
maturity date, LIBOR
+3%(d)
|
|
|
108
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes receivable affiliates
|
|
|
230
|
|
|
|
156
|
|
|
|
|
|
|
|
|
|
|
Subtotal Capital leases and notes receivable
|
|
|
536
|
|
|
|
503
|
|
|
|
|
|
|
|
|
|
|
Less current maturities:
|
|
|
|
|
|
|
|
|
Capital leases
|
|
|
32
|
|
|
|
32
|
|
Notes receivable GenConn
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
Subtotal current maturities
|
|
|
32
|
|
|
|
68
|
|
|
|
|
|
|
|
|
|
|
Total Capital leases and notes receivable
noncurrent
|
|
$
|
504
|
|
|
$
|
435
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Saale Energie GmbH, or SEG, has
sold 100% of its share of capacity from the Schkopau power plant
to VEAG Vereinigte Energiewerke AG under a
25-year
contract, which is more than 83% of the useful life of the
plant. This direct financing lease receivable amount was
calculated based on the present value of the income to be
received over the life of the contract.
|
(b)
|
|
In 2008, NRG entered into a
short-term $45 million note receivable facility with
GenConn Energy LLC to fund project liquidity needs.
|
(c)
|
|
SEG entered into a note receivable
with Kraftwerke Schkopau GBR, a partnership between Saale and
E.On Kraftwerke GmbH. The note was used to fund SEGs
initial capital contribution to the partnership and to cover
project liquidity shortfalls during construction of the Schkopau
power plant. The note is subject to repayment upon the
disposition of the Schkopau plant.
|
(d)
|
|
NRG entered into a long-term
$121.6 million note receivable facility with GCE Holding
LLC to fund project liquidity needs.
|
175
|
|
Note 10
|
Property,
Plant, and Equipment
|
NRGs major classes of property, plant, and equipment as of
December 31, 2009 and 2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
Depreciable
|
|
|
2009
|
|
|
2008
|
|
|
Lives
|
|
|
(In millions)
|
|
|
|
|
Facilities and equipment
|
|
$
|
13,023
|
|
|
$
|
12,193
|
|
|
1-40 Years
|
Land and improvements
|
|
|
621
|
|
|
|
593
|
|
|
|
Nuclear fuel
|
|
|
286
|
|
|
|
225
|
|
|
5 Years
|
Office furnishings and equipment
|
|
|
153
|
|
|
|
73
|
|
|
2-10 Years
|
Construction in progress
|
|
|
533
|
|
|
|
804
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment
|
|
|
14,616
|
|
|
|
13,888
|
|
|
|
Accumulated depreciation
|
|
|
(3,052
|
)
|
|
|
(2,343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment
|
|
$
|
11,564
|
|
|
$
|
11,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Note 11
|
Goodwill
and Other Intangibles
|
Goodwill NRGs goodwill arose in
connection with the acquisitions of Texas Genco and Padoma Wind
Power LLC. As of December 31, 2009 and 2008, goodwill was
approximately $1.7 billion. In accordance with ASC 805,
goodwill associated with the Texas Genco acquisition decreased
by $68 million during 2008 due to an adjustment to deferred
tax liabilities originally established under the 2006 purchase
price allocation. Goodwill is not amortized but instead tested
for impairment in accordance with ASC 350 at the
reporting-unit
level. Goodwill is tested annually, typically during the fourth
quarter, or more often if events or circumstances, such as
adverse changes in the business climate, indicate there may be
impairment. As of December 31, 2009, there was no
impairment to goodwill. As of December 31, 2009 and 2008,
NRG had approximately $721 million and $786 million,
respectively, of goodwill that is deductible for
U.S. income tax purposes in future periods.
Intangible Assets The Companys
intangible assets as of December 31, 2009 reflect
intangible assets acquired from the acquisition of Bluewater
Wind and Blythe Solar in November 2009, the acquisition of
Reliant Energy in May 2009, the acquisition of Texas Genco in
February 2006 and the adoption of Fresh Start accounting.
For the Reliant Energy acquisition, the intangible assets
include energy supply contracts, customer contracts, customer
relationships, trade names, and other. The energy supply
contracts consist of in-market and
out-of-market
contracts that are amortized based on the expected delivery
under the respective contracts. The amortization expense
associated with the energy supply contracts is recorded as part
of cost of operations. The customer contracts are amortized to
revenues, based on expected volumes to be delivered for the
portfolio. The customer relationships are amortized to
depreciation and amortization expense, based on the expected
discounted future cash flow by year. The trade names are
amortized to depreciation and amortization expense on a straight
line basis over the estimated useful life.
The intangible assets established with the Texas Genco
acquisition and upon the adoption of Fresh Start reporting
include
SO2
and
NOx
emission allowances and certain in-market power, fuel (coal,
gas, and nuclear) and water contracts. The emission allowances
are amortized and recorded as a part of the cost of operations,
with
NOx
emission allowances amortized on a straight line basis and
SO2
emission allowances amortized based on units of production. The
power contracts are amortized based on contracted volumes over
the life of each contract and the fuel contracts are amortized
over expected volumes over the life of each contract. The power
contracts are amortized and recorded as part of revenues, while
fuel and water contracts are amortized and recorded as part of
the cost of operations.
In 2009, NRG began purchasing RGGI emission allowance credits,
which are amortized based on units of production and recorded as
a part of the costs of operations.
176
The following tables summarize the components of NRGs
intangible assets subject to amortization for the years ended
December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
Customer
|
|
|
Trade
|
|
|
|
|
|
|
|
December 31, 2009
|
|
Allowances
|
|
|
Power
|
|
|
Supply
|
|
|
Fuel
|
|
|
Customer
|
|
|
Relationships
|
|
|
Names
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2009
|
|
$
|
916
|
|
|
$
|
58
|
|
|
$
|
|
|
|
$
|
171
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
1,150
|
|
Write-off of fully amortized intangible assets
|
|
|
(19
|
)
|
|
|
(58
|
)
|
|
|
|
|
|
|
(88
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(165
|
)
|
Acquisition of businesses
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
790
|
|
|
|
399
|
|
|
|
178
|
|
|
|
11
|
|
|
|
1,432
|
|
Reclassification of NPNS contract to derivative
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
Other
|
|
|
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross amount
|
|
|
919
|
|
|
|
|
|
|
|
54
|
|
|
|
71
|
|
|
|
790
|
|
|
|
399
|
|
|
|
178
|
|
|
|
14
|
|
|
|
2,425
|
|
Less accumulated
amortization(a)
|
|
|
(199
|
)
|
|
|
|
|
|
|
(18
|
)
|
|
|
(48
|
)
|
|
|
(258
|
)
|
|
|
(117
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
(648
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
720
|
|
|
$
|
|
|
|
$
|
36
|
|
|
$
|
23
|
|
|
$
|
532
|
|
|
$
|
282
|
|
|
$
|
170
|
|
|
$
|
14
|
|
|
$
|
1,777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes annual amortization
expense as described in the table below; netting of fully
amortized intangible assets of $19 million and
$58 million for emission allowances and power contracts,
respectively; and decrease of accumulated amortization expense
of $88 million as a result of the reclassification of NPNS
contract to derivatives in fuel contracts.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Contracts
|
|
|
|
|
|
|
|
December 31, 2008
|
|
Allowances
|
|
|
Power
|
|
|
Fuel
|
|
|
Water
|
|
|
Other
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
January 1, 2008
|
|
$
|
916
|
|
|
$
|
92
|
|
|
$
|
171
|
|
|
$
|
64
|
|
|
$
|
2
|
|
|
$
|
1,245
|
|
Additions
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3
|
|
|
|
9
|
|
Transfer to held for sale
|
|
|
(6
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
Fully amortized intangible assets
|
|
|
|
|
|
|
(34
|
)
|
|
|
|
|
|
|
(64
|
)
|
|
|
|
|
|
|
(98
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted gross amount
|
|
|
916
|
|
|
|
58
|
|
|
|
171
|
|
|
|
|
|
|
|
5
|
|
|
|
1,150
|
|
Less accumulated amortization
|
|
|
(155
|
)
|
|
|
(58
|
)
|
|
|
(122
|
)
|
|
|
|
|
|
|
|
|
|
|
(335
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
761
|
|
|
$
|
|
|
|
$
|
49
|
|
|
$
|
|
|
|
$
|
5
|
|
|
$
|
815
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents NRGs amortization of
intangible assets for the years ended December 31, 2009,
2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Emission allowances
|
|
$
|
63
|
|
|
$
|
41
|
|
|
$
|
40
|
|
Energy supply contracts
|
|
|
18
|
|
|
|
|
|
|
|
|
|
Fuel contracts
|
|
|
15
|
|
|
|
20
|
|
|
|
37
|
|
Customer contracts
|
|
|
258
|
|
|
|
|
|
|
|
|
|
Customer relationships
|
|
|
117
|
|
|
|
|
|
|
|
|
|
Trade names
|
|
|
8
|
|
|
|
|
|
|
|
|
|
Water contracts
|
|
|
|
|
|
|
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total amortization
|
|
$
|
479
|
|
|
$
|
61
|
|
|
$
|
113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents estimated amortization related to
NRGs emission allowances, in-market energy supply and fuel
contracts, customer contracts, customer relationships and trade
names:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
Emission
|
|
|
Energy
|
|
|
|
|
|
|
|
|
Customer
|
|
|
Trade
|
|
|
|
|
Year Ended December 31,
|
|
Allowances
|
|
|
Supply
|
|
|
Fuel
|
|
|
Customer
|
|
|
Relationships
|
|
|
Names
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
89
|
|
|
$
|
3
|
|
|
$
|
6
|
|
|
$
|
225
|
|
|
$
|
81
|
|
|
$
|
12
|
|
|
$
|
416
|
|
2011
|
|
|
82
|
|
|
|
4
|
|
|
|
2
|
|
|
|
152
|
|
|
|
57
|
|
|
|
12
|
|
|
|
309
|
|
2012
|
|
|
76
|
|
|
|
5
|
|
|
|
2
|
|
|
|
105
|
|
|
|
44
|
|
|
|
12
|
|
|
|
244
|
|
2013
|
|
|
77
|
|
|
|
6
|
|
|
|
2
|
|
|
|
50
|
|
|
|
31
|
|
|
|
12
|
|
|
|
178
|
|
2014
|
|
|
80
|
|
|
|
6
|
|
|
|
2
|
|
|
|
|
|
|
|
24
|
|
|
|
12
|
|
|
|
124
|
|
177
The following table presents the weighted average remaining
amortization period related to NRGs intangible assets
purchased in 2009 through the Reliant Energy acquisition:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
Customer
|
|
Trade
|
|
|
In years
|
|
Supply
|
|
Customer
|
|
Relationships
|
|
Names
|
|
Total
|
|
Weighted average remaining amortization period
|
|
|
4.4
|
|
|
|
2.0
|
|
|
|
3.1
|
|
|
|
7.7
|
|
|
|
3.3
|
|
Intangible assets held for sale NRG records
the Companys bank of emission allowances
held-for-use
as part of the Companys intangible assets. From time to
time, management may authorize the transfer from the
Companys emission bank to intangible assets
held-for-sale.
Emission allowances
held-for-sale
are included in other non current assets on the Companys
consolidated balance sheet and are not amortized, but rather
expensed as sold. As of December 31, 2009, the value of
emission allowances
held-for-sale
is $7 million and is managed within the Corporate segment.
Once transferred to
held-for-sale,
these emission allowances are prohibited from moving back to
held-for-use.
Out-of-market
contracts Due to Fresh Start accounting, as well
as the acquisition of Blythe Solar, Reliant Energy and Texas
Genco, NRG acquired certain
out-of-market
contracts. These are primarily customer contracts, energy
supply, power, gas swaps, and certain coal contracts and are
classified as non-current liabilities on NRGs consolidated
balance sheet. The gas swap, power and customer contracts are
amortized to revenues, while the energy supply and coal
contracts are amortized to cost of operations.
The following table summarizes the estimated amortization
related to NRGs
out-of-market
contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contracts
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
Customer
|
|
|
Supply
|
|
|
Coal
|
|
|
Gas Swap
|
|
|
Power
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
8
|
|
|
$
|
39
|
|
|
$
|
6
|
|
|
$
|
51
|
|
|
$
|
27
|
|
|
$
|
131
|
|
2011
|
|
|
7
|
|
|
|
11
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
38
|
|
2012
|
|
|
1
|
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
21
|
|
|
|
28
|
|
2013
|
|
|
|
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
22
|
|
2014
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
|
|
16
|
|
178
|
|
Note 12
|
Debt and
Capital Leases
|
Long-term debt and capital leases consist of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
Interest
|
|
|
2009
|
|
|
2008
|
|
|
Rate
|
|
|
(In millions except rates)
|
NRG Recourse Debt:
|
|
|
|
|
|
|
|
|
|
|
Senior notes, due
2019(a)
|
|
$
|
689
|
|
|
$
|
|
|
|
8.50
|
Senior notes, due 2017
|
|
|
1,100
|
|
|
|
1,100
|
|
|
7.375
|
Senior notes, due 2016
|
|
|
2,400
|
|
|
|
2,400
|
|
|
7.375
|
Senior notes, due
2014(b)
|
|
|
1,211
|
|
|
|
1,217
|
|
|
7.25
|
Term Loan Facility, due 2013
|
|
|
2,213
|
|
|
|
2,642
|
|
|
L+1.75/L+1.5(f)
|
NRG Non-Recourse Debt:
|
|
|
|
|
|
|
|
|
|
|
CSF, notes and preferred interests, due
2010(c)
|
|
|
188
|
|
|
|
325
|
|
|
5.45-12.65 for 2009/5.45-13.23 for 2008
|
NRG Peaker Finance Co. LLC, bonds, due
2019(d)
|
|
|
220
|
|
|
|
229
|
|
|
L+1.07(f)
|
NRG Energy Center Minneapolis LLC, senior secured notes, due
2013 and
2017(e)
|
|
|
75
|
|
|
|
86
|
|
|
7.12-7.31
|
Dunkirk Power LLC tax-exempt bonds, due 2042
|
|
|
52
|
|
|
|
|
|
|
Weekly rate based on SIFMA
rate(g)
|
NRG Connecticut Peaking LLC, equity bridge loan facility, due
2010 and 2011
|
|
|
108
|
|
|
|
|
|
|
L + 2(f)
|
Other
|
|
|
39
|
|
|
|
20
|
|
|
L +
0.45(f)
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal long-term debt
|
|
|
8,295
|
|
|
|
8,019
|
|
|
|
Capital leases:
|
|
|
|
|
|
|
|
|
|
|
Saale Energie GmbH, Schkopau capital lease, due 2021
|
|
|
123
|
|
|
|
142
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal
|
|
|
8,418
|
|
|
|
8,161
|
|
|
|
Less current
maturities(h)
|
|
|
571
|
|
|
|
464
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,847
|
|
|
$
|
7,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes discount of
$(11) million as of December 31, 2009. On June 5,
2009, NRG issued these $700 million aggregate principal
amount bonds resulting in a yield of 8.75%.
|
(b)
|
|
Includes fair value adjustment as
of December 31, 2009 and 2008 of $11 million and
$17 million, respectively, reflecting an adjustment for an
interest rate swap.
|
(c)
|
|
Includes discount of
$(2) million and $(8) million as of December 31,
2009 and 2008, respectively.
|
(d)
|
|
Includes discount of
$(31) million and $(37) million as of
December 31, 2009 and 2008, respectively.
|
(e)
|
|
Includes premium of $2 million
as of December 31, 2009 and 2008.
|
(f)
|
|
L+ equals LIBOR plus x%.
|
(g)
|
|
Securities Industry and Financial
Markets Association, or SIFMA.
|
(h)
|
|
Includes discount of
$(6) million on the NRG Peaker Finance debt as of
December 31, 2009 and 2008; discount of $(1) million
on the CSF notes and preferred interests as of December 31,
2009 and a premium of $1 million on NRG Energy Center
Minneapolis debt as of December 31, 2009 and 2008.
|
179
Senior
Notes
NRG has four outstanding issuances of senior notes, or Senior
Notes, under an Indenture, dated February 2, 2006, or the
Indenture, between NRG and Law Debenture Trust Company of
New York, as trustee:
(i) 7.25% senior notes, issued February 2, 2006
and due February 1, 2014, or the 2014 Senior Notes;
(ii) 7.375% senior notes, issued February 2, 2006
and due February 1, 2016, or the 2016 Senior Notes;
(iii) 7.375% senior notes, issued November 21,
2006 and due January 15, 2017, or the 2017 Senior
Notes; and
(iv) 8.5% senior notes, issued June 5, 2009 and
due June 15, 2019, or the 2019 Senior Notes.
Supplemental indentures to the series of notes have been issued
to add newly formed or acquired subsidiaries as guarantors.
The Indentures and the form of notes provide, among other
things, that the Senior Notes will be senior unsecured
obligations of NRG. The Indentures also provide for customary
events of default, which include, among others: nonpayment of
principal or interest; breach of other agreements in the
Indentures; defaults in failure to pay certain other
indebtedness; the rendering of judgments to pay certain amounts
of money against NRG and its subsidiaries; the failure of
certain guarantees to be enforceable; and certain events of
bankruptcy or insolvency. Generally, if an event of default
occurs, the Trustee or the Holders of at least 25% in principal
amount of the then outstanding series of Senior Notes may
declare all of the Senior Notes of such series to be due and
payable immediately.
The terms of the Indentures, among other things, limit
NRGs ability and certain of its subsidiaries ability
to:
|
|
|
|
|
return capital to shareholders;
|
|
|
|
grant liens on assets to lenders; and
|
|
|
|
incur additional debt.
|
Interest is payable semi-annually on the Senior Notes until
their maturity dates. In addition, the Company entered into a
fixed to floating interest rate swap in 2004 with a notional
amount as of December 31, 2009 of $400 million and a
maturity date of December 15, 2013.
Prior to February 1, 2010, NRG may redeem all or a portion
of the 2014 Senior Notes at a price equal to 100% of the
principal amount plus a premium and accrued interest. The
premium is the greater of: (i) 1% of the principal amount
of the note, or (ii) the excess of the principal amount of
the note over the following: the present value of 103.625% of
the note, plus interest payments due on the note from the date
of redemption through February 1, 2010, discounted at a
Treasury rate plus 0.50%. On or after February 1, 2010, NRG
may redeem some or all of the notes at redemption prices
expressed as percentages of principal amount as set forth below,
plus accrued and unpaid interest on the notes redeemed to the
applicable redemption date:
|
|
|
|
|
|
|
Redemption
|
|
Redemption Period
|
|
Percentage
|
|
February 1, 2010 to February 1, 2011
|
|
|
103.625
|
%
|
February 1, 2011 to February 1, 2012
|
|
|
101.813
|
%
|
February 1, 2012 and thereafter
|
|
|
100.000
|
%
|
Prior to February 1, 2011, NRG may redeem all or a portion
of the 2016 Senior Notes at a price equal to 100% of the
principal amount plus a premium and accrued interest. The
premium is the greater of: (i) 1% of the principal amount
of the note, or (ii) the excess of the principal amount of
the note over the following: the present value of 103.688% of
the note, plus interest payments due on the note from the date
of redemption through February 1, 2011, discounted at a
Treasury rate plus 0.50%. On or after February 1, 2011, NRG
may redeem some or all of the notes at
180
redemption prices expressed as percentages of principal amount
as set forth below, plus accrued and unpaid interest on the
notes redeemed to the applicable redemption date:
|
|
|
|
|
|
|
Redemption
|
Redemption Period
|
|
Percentage
|
February 1, 2011 to February 1, 2012
|
|
|
103.688
|
%
|
February 1, 2012 to February 1, 2013
|
|
|
102.458
|
%
|
February 1, 2013 to February 1, 2014
|
|
|
101.229
|
%
|
February 1, 2014 and thereafter
|
|
|
100.000
|
%
|
Prior to January 15, 2012, NRG may redeem up to 35% of the
2017 Senior Notes with net cash proceeds of certain equity
offerings at a price of 107.375%, provided at least 65% of the
aggregate principal amount of the notes issued remain
outstanding after the redemption. Prior to January 15,
2012, NRG may redeem all or a portion of the Senior Notes at a
price equal to 100% of the principal amount of the notes
redeemed, plus a premium and any accrued and unpaid interest.
The premium is the greater of: (i) 1% of the principal
amount of the note, or (ii) the excess of the principal
amount of the note over the following: the present value of
103.688% of the note, plus interest payments due on the note
from the date of redemption through January 15, 2012,
discounted at a Treasury rate plus 0.50%. In addition, on or
after January 15, 2012, NRG may redeem some or all of the
notes at redemption prices expressed as percentages of principal
amount as set forth below, plus accrued and unpaid interest on
the notes redeemed to the first applicable redemption date:
|
|
|
|
|
|
|
Redemption
|
Redemption Period
|
|
Percentage
|
February 1, 2012 to February 1, 2013
|
|
|
103.688
|
%
|
February 1, 2013 to February 1, 2014
|
|
|
102.458
|
%
|
February 1, 2014 to February 1, 2015
|
|
|
101.229
|
%
|
February 1, 2015 and thereafter
|
|
|
100.000
|
%
|
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 notes; 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:
|
|
|
|
|
|
|
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
|
%
|
Senior
Credit Facility
As of December 31, 2009, NRG has a Senior Credit Facility
which is comprised of a senior first priority secured term loan,
or the Term Loan Facility, a $1.0 billion senior first
priority secured revolving credit facility, or the Revolving
Credit Facility, and a $1.3 billion senior first priority
secured synthetic letter of credit facility, or the Synthetic
Letter of Credit Facility. The Senior Credit Facility was last
amended on June 8, 2007 which resulted in a charge of
$35 million which was recorded to the Companys
results of operations for the year ended December 31, 2007,
primarily related to the write-off of previously deferred
financing costs. The pricing on the Companys Term Loan
Facility and Synthetic Letter of Credit Facility is also subject
to further reductions upon the achievement of certain financial
ratios.
As of December 31, 2009, NRG had issued $717 million
of letters of credit under the Synthetic Letter of Credit
Facility, leaving $583 million available for future
issuances. Under the Companys Revolving Credit Facility as
of
181
December 31, 2009, NRG had issued letters of credit
totaling $95 million, leaving $905 million available
for borrowings, of which approximately $805 million could
be used to issue additional letters of credit.
The Term Loan Facility matures on February 1, 2013, and
amortizes in twenty-seven consecutive equal quarterly
installments of 0.25% term loan commitments, beginning
June 30, 2006, with the balance payable on the seventh
anniversary thereof. The full amount of the Revolving Credit
Facility will mature on February 2, 2011. The Synthetic
Letter of Credit Facility will mature on February 1, 2013,
and no amortization will be required in respect thereof. NRG has
the option to prepay the Senior Credit Facility in whole or in
part at any time.
NRG must annually offer a portion of its excess cash flow (as
defined in the Senior Credit Facility) to its first lien lenders
under the Term Loan Facility. The percentage of the excess cash
flow offered to these lenders is dependent upon the
Companys consolidated leverage ratio (as defined in the
Senior Credit Facility) at the end of the preceding year. Of the
amount offered, the first lien lenders must accept 50%, while
the remaining 50% may either be accepted or rejected at the
lenders option. The 2010 mandatory offer related to 2009
is expected to be $430 million, against which the Company
made a prepayment of $200 million in December 2009. Based
on current credit market conditions, the Company expects that
its lenders will accept in full the 2010 mandatory offer related
to 2009, and, as such, the Company has reclassified
approximately $230 million of Term Loan Facility maturity
from a non-current to a current liability as of
December 31, 2009. The 2009 mandatory offer and prepayment
related to 2008 paid in March 2009 was $197 million.
The Senior Credit Facility is guaranteed by substantially all of
NRGs existing and future direct and indirect subsidiaries,
with certain customary or
agreed-upon
exceptions for unrestricted foreign subsidiaries, project
subsidiaries, and certain other subsidiaries. The capital stock
of substantially all of NRGs subsidiaries, with certain
exceptions for unrestricted subsidiaries, foreign subsidiaries,
and project subsidiaries, has been pledged for the benefit of
the Senior Credit Facilitys lenders.
The Senior Credit Facility is also secured by first-priority
perfected security interests in substantially all of the
property and assets owned or acquired by NRG and its
subsidiaries, other than certain limited exceptions. These
exceptions include assets of certain unrestricted subsidiaries,
equity interests in certain of NRGs project affiliates
that have non-recourse debt financing, and voting equity
interests in excess of 66% of the total outstanding voting
equity interest of certain of NRGs foreign subsidiaries.
The Senior Credit Facility contains customary covenants, which,
among other things, require NRG to meet certain financial tests,
including minimum interest coverage ratio and a maximum leverage
ratio on a consolidated basis, and limit NRGs ability to:
|
|
|
|
|
incur indebtedness and liens and enter into sale and lease-back
transactions;
|
|
|
make investments, loans and advances; and
|
|
|
return capital to shareholders.
|
Interest Rate Swaps In 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, which mature on
February 1, 2013, is $900 million.
In 2006 in connection with the Senior Credit Facility, NRG
entered into another series of forward-setting interest rate
swaps which are intended to hedge the risks associated with
floating interest rates. For each of the interest rate swaps,
the Company pays its counterparty the equivalent of a fixed
interest payment on a predetermined notional value, and NRG
receives quarterly the equivalent of a floating interest payment
based on a
3-month
LIBOR calculated on the same notional value. All interest rate
swap payments by NRG and its counterparties are made quarterly,
and the LIBOR is determined in advance of each interest period.
While the
182
notional value of each of the swaps does not vary over time, the
swaps are designed to mature sequentially. The notional amounts
and maturities of each tranche of these swaps as of
December 31, 2009, are as follows:
|
|
|
|
|
Maturity
|
|
Notional Value
|
March 31, 2010
|
|
$
|
190 million
|
|
March 31, 2011
|
|
$
|
1.55 billion
|
|
Dunkirk
Power LLC Tax-Exempt Bonds
On April 15, 2009, NRG executed a $59 million
tax-exempt bond financing, or the Dunkirk bonds, 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 December 31, 2009 were $52 million,
with the remaining balance being released over time as
construction costs are paid. On February 1, 2010, the
Company fixed the rate on the Dunkirk bonds at 5.875%. Interest
will be payable semiannually. In addition, the $59 million
letter of credit issued by NRG in support of the bonds was
cancelled and replaced with a parent guarantee.
NRG
Non-Recourse Debt
Debt
Related to Capital Allocation Program
In 2006, the Company formed CSF I and II, two wholly-owned
unrestricted subsidiaries that are both consolidated by NRG.
Their purpose was to repurchase an aggregate of
$500 million in shares of NRGs common stock in the
public markets or in privately negotiated transactions in
connection with the Companys Capital Allocation Program.
These subsidiaries were funded with a combination of cash from
NRG, and a mix of notes and preferred interests issued to CS, or
the CSF Debt. Both the notes and the preferred interests are
non-recourse debt to NRG or any of its restricted subsidiaries,
with the debt collateralized by the NRG common stock held by CSF
I and II. In addition, the assets of CSF I and II are not
available to the creditors of NRG or the Companys other
subsidiaries.
From inception through July 2008, the notes and preferred
interests of CSF I contained a feature considered an embedded
derivative, which required NRG to pay to CS at maturity, either
in cash or stock at NRGs option, the excess of NRGs
then current stock price over a Threshold Price. From inception
through November 24, 2009, the notes and preferred
interests of CSF II also contained a feature considered an
embedded derivative with terms similar to the CSF I embedded
derivative. The Threshold Price is the price of NRGs stock
in excess of a compound annual growth rate, or CAGR, of 20%
beyond the volume-weighted average share price of the stock at
the time of repurchase. Although this feature was considered a
derivative, it was exempt from derivative accounting under the
guidance of ASC 815, and was only recognized upon settlement. As
a result of the early settlement in August 2008 by the CSF I
extension and the unwinding of the CSF II debt in November 2009,
both described below, there were no notes or preferred interests
containing an embedded derivative feature as of
December 31, 2009.
CSF I Extension In March 2008, the Company
executed an arrangement with CS to extend the notes and
preferred interest maturities of the CSF I Debt from October
2008 to June 2010. In addition, the settlement date of the
embedded derivative, or CSF I CAGR, was extended 30 days to
early December 2008. As part of this extension arrangement, the
Company contributed 795,503 treasury shares to CSF I as
additional collateral to maintain a blended interest rate in the
CSF I facility of approximately 7.5%. The amount due at maturity
in June 2010, including accrued interest, for the CSF I Debt
will be $249 million. In August 2008, the Company amended
the CSF I Debt to early settle the CSF I CAGR. Accordingly, NRG
made a cash payment of $45 million to CS for the benefit of
CSF I, which was recorded to additional paid in capital on
the Companys consolidated balance sheet as of
December 31, 2008. See further discussion below regarding
the adoption of FSP APB
14-1.
Share Lending Agreements On February 20,
2009, CSF I and II entered into Share Lending Agreements,
or SLAs, with affiliates of CS relating to the shares of NRG
common stock currently held by CSF I and II in connection
with the CSF Debt. The Company entered into the SLAs due to a
lack of liquidity in the stock borrow
183
market for NRG shares that existed at that time and in order to
maintain the intended economic benefits of the CSF Debt
agreements. The SLAs permitted affiliates of CS to borrow up to
the total number of shares of NRG common stock held by CSF I and
II. CSF I and II loaned affiliates of CS 6,600,000 and
5,400,000 shares, respectively, of NRG common stock under
the SLAs.
Shares borrowed by affiliates of CS under the SLAs were 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.
CSF II Debt Maturity On November 24,
2009, the Company completed the unwinding of the CSF II Debt,
remitting a cash payment to CS of the $181 million
outstanding principal and interest, while CS returned
5,400,000 shares of NRG common stock borrowed under the
SLAs, and then released all 9,528,930 common shares held as
collateral for the CSF II Debt. The CSF II Debt contained an
embedded derivative feature, or CFS II CAGR, which could have
required NRG to pay CS at maturity, either in cash or stock at
NRGs option, the excess of NRGs then current stock
price over a Threshold Price of $40.80 per share. On
November 24, 2009, it was determined that no payment was
required on the CSF II CAGR at which point the CSF II CAGR
expired.
At December 31, 2009, CSF I held 12,441,973 shares of
NRG common stock of which 6,600,000 shares lent to
affiliates of CS under the SLAs, with a fair value of
$156 million, are considered outstanding and
5,841,973 shares are reflected within treasury stock on the
Companys consolidated balance sheet.
Notes As of December 31, 2009, CSF I had
a total of $137 million in notes in connection with Phase I
of the Capital Allocation Program which mature in June 2010,
plus accrued interest at an annual rate of 5.45%. As of
December 31, 2008, CSF I and II had a total of
$249 million in notes outstanding in connection with Phase
I.
Preferred Interests As of December 31,
2009, CSF I had a total of $53 million in preferred
interests issued and outstanding which mature in June 2010, plus
accrued interest at an annual rate of 12.65%. As of
December 31, 2008, CSF I and II had a total of
$84 million in preferred interests issued and outstanding.
The preferred interests are classified as a liability per ASC
480, Distinguishing Liabilities from Equity, or ASC 480,
because they embody a fixed unconditional obligation that the
unrestricted subsidiaries must settle.
Adoption of FSP APB
14-1 As
discussed in Note 2, Summary of Significant Accounting
Policies, the Company adopted FSP APB
14-1 on
January 1, 2009, which has been incorporated in ASC 470 and
ASC 825. The following table summarizes certain information
related to the CSF Debt in accordance with ASC 470:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Equity Component
|
|
|
|
|
|
|
|
|
Additional Paid-in Capital
|
|
$
|
|
|
|
$
|
14
|
|
|
|
|
|
|
|
|
|
|
Liability Component
|
|
|
|
|
|
|
|
|
Principal amount
|
|
$
|
190
|
|
|
$
|
333
|
|
Unamortized discount
|
|
|
(2
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
Net carrying amount
|
|
$
|
188
|
|
|
$
|
325
|
|
|
|
|
|
|
|
|
|
|
The unamortized discount will be amortized through the maturity
of the CSF Debt. The CSF II debt matured in November 2009 and
the CSF I debt has a maturity date of June 2010. Interest
expense for the CSF Debt, including the debt discount
amortization for the years ended December 31, 2009, 2008,
and 2007 was $33 million, $37 million, and
$40 million, respectively. The effective interest rate as
of December 31, 2009, was 11.4% for the CSF I debt. The
effective interest rate as of December 31, 2008, was 11.4%
for the CSF I debt and 12.1% for the CSF II debt.
184
Project
Financings
The following are descriptions of certain indebtedness of
NRGs project subsidiaries that remain outstanding as of
December 31, 2009. The indebtedness described below is
non-recourse to NRG, unless otherwise noted.
TANE
Facility
On February 24, 2009, Nuclear Innovation North America LLC,
or NINA, executed an 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 December 31, 2009, no
amounts have been borrowed under the TANE Facility.
GenConn
Energy LLC related financings
On April 27, 2009, NRG Connecticut Peaking LLC, 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 Middletowns commercial operations date 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 $54 million, on the earlier of
Devons commercial operations date, currently anticipated
to be June 2010, or January 27, 2011. The proceeds of the
EBL received through December 31, 2009, were
$108 million and the remaining amounts will be drawn as
necessary.
Borrowings of an equity method investment In
April 2009, GenConn, a variable interest entity, 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. In August 2009, GenConn began to draw under the
GenConn Facility to cover costs related to the Devon project and
as of December 31, 2009, has drawn $48 million.
Other
In 2008, NINA and NRG Repowering Holdings LLC, or NRG
Repowering, each obtained a $20 million revolving credit
facility to provide working capital which permits NINA and NRG
Repowering to make cash draws or issue letters of credit. The
facilities mature on April 30, 2010, for NINA and
August 12, 2011, for NRG Repowering. The facilities provide
for customary events of default, which include, among others:
nonpayment of principal or interest; breach of other agreements
in the facility; the rendering of judgments to pay certain
amounts of money against NINA or NRG Repowering and their
subsidiaries; and certain events of bankruptcy or insolvency.
Borrowings under the facilities accrue interest at LIBOR or a
base rate, plus a spread and are supported by a letter of credit
issued by NRG. As of December 31, 2009, and 2008, NINA had
borrowed approximately $20 million and $10 million,
respectively. As of December 31, 2009, and 2008, NRG
Repowering had borrowed approximately $19 million and
$10 million, respectively. As of December 31, 2009,
NRG Repowering also had outstanding approximately
$1 million in letters of credit.
185
Peakers
In June 2002, NRG Peaker Finance Company LLC, or Peakers, an
indirect wholly-owned subsidiary, issued $325 million in
floating rate bonds due June 2019. Peakers subsequently swapped
such floating rate debt for fixed rate debt at an all-in cost of
6.67% per annum. Principal, interest, and swap payments were
originally guaranteed by Syncora Guarantee Inc., successor in
interest to XL Capital Assurance, through a financial guaranty
insurance policy. In 2009, Assured Guaranty Mutual Corp assumed
the responsibility as the bond insurer and controlling party.
Syncora Guarantee Inc. continues to be the swap insurer. These
notes are also secured by, among other things, substantially all
of the assets of and membership interests in Bayou Cove Peaking
Power LLC, Big Cajun I Peaking Power LLC, NRG Sterlington Power
LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG
Rockford Equipment LLC. As of December 31, 2009,
approximately $251 million in principal remained
outstanding on these bonds. Upon emergence from bankruptcy, NRG
issued a $36 million letter of credit to the Peakers
collateral agent. The letter of credit may be drawn if the
project is unable to meet principal or interest payments. There
are no provisions requiring NRG to replenish the letter of
credit if it is drawn. On December 10, 2009, the collateral
agent drew approximately $0.6 million on the letter of
credit to meet the debt service requirements.
NRG
Thermal
NRG owns and operates its thermal business through a
wholly-owned subsidiary holding company, NRG Thermal LLC, or NRG
Thermal. In 1993, the predecessor entity to NRG Thermals
largest subsidiary, NRG Energy Center Minneapolis LLC, or NRG
Thermal Minneapolis, issued $84 million of
7.31% senior secured notes due June 2013, of which
approximately $25 million remained outstanding as of
December 31, 2009. In 2002, NRG Thermal Minneapolis issued
an additional $55 million of 7.25% Series A notes due
August 2017, of which approximately $37 million remained
outstanding as of December 31, 2009, and $20 million
of 7.12% Series B notes due August 2017, of which
approximately $13 million remained outstanding as of
December 31, 2009. This indebtedness is secured by
substantially all of the assets of NRG Thermal Minneapolis. NRG
Thermal has guaranteed the indebtedness, and its guarantee is
secured by a pledge of the equity interests in all of NRG
Thermals subsidiaries.
Capital
Leases
Saale
Energie GmbH
Saale Energie GmbH, or SEG, an NRG wholly-owned subsidiary, has
a 41.9% participation in Schkopau through NRGs interest in
the Kraftwerke Schkopau GbR, or KSGbR, partnership. Under the
terms of a Use and Benefit Fee Agreement, SEG and the other
partner to the project, E.ON Kraftwerke GmbH, are required to
fund debt service and certain other costs resulting from the
construction and financing of Schkopau. The Use and Benefit Fee
Agreement is treated as a capital lease under U.S. GAAP.
Calls for funds are made to the partners based on their
participation interest as cash is needed. As of
December 31, 2009, the capital lease obligation at SEG was
approximately $123 million.
The KSGbR issued debt to fund Schkopau pursuant to multiple
facilities totaling approximately 785 million. As of
December 31, 2009, approximately 141 million
(approximately $202 million) remained outstanding at
Schkopau. Interests on the individual loans accrue at fixed
rates averaging 4.26% per annum, with maturities occurring
between 2010 and 2015. SEG remains liable to the lenders as a
partner in KSGbR, but there is no recourse to NRG.
186
Consolidated
Annual Maturities and Future Minimum Lease
Payments
Annual payments based on the maturities of NRGs long-term
debt and capital leases for the years ending after
December 31, 2009 are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
571
|
|
2011
|
|
|
143
|
|
2012
|
|
|
70
|
|
2013
|
|
|
1,926
|
|
2014
|
|
|
1,250
|
|
Thereafter
|
|
|
4,458
|
|
|
|
|
|
|
Total
|
|
$
|
8,418
|
|
|
|
|
|
|
NRGs future minimum lease payments for capital leases
included above as of December 31, 2009, are as follows:
|
|
|
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
28
|
|
2011
|
|
|
16
|
|
2012
|
|
|
14
|
|
2013
|
|
|
13
|
|
2014
|
|
|
14
|
|
Thereafter
|
|
|
107
|
|
|
|
|
|
|
Total minimum obligations
|
|
|
192
|
|
Interest
|
|
|
69
|
|
|
|
|
|
|
Present value of minimum obligations
|
|
|
123
|
|
Current portion
|
|
|
22
|
|
|
|
|
|
|
Long-term obligations
|
|
$
|
101
|
|
|
|
|
|
|
|
|
Note 13
|
Asset
Retirement Obligations
|
NRGs AROs are primarily related to the future
dismantlement of equipment on leased property and environmental
obligations related to nuclear decommissioning, ash disposal,
site closures, and fuel storage facilities. In addition, NRG has
also identified conditional AROs for asbestos removal and
disposal, which are specific to certain power generation
operations.
See Note 7, Nuclear Decommissioning Trust Fund,
for a further discussion of NRGs nuclear
decommissioning obligations. Consequently, accretion for the
nuclear decommissioning ARO and amortization of the related ARO
asset are recorded to the Nuclear Decommissioning
Trust Liability to the ratepayers and are not included in
net income, consistent with regulatory treatment.
The following table represents the balance of ARO obligations as
of December 31, 2009, and 2008, along with the additions,
reductions and accretion related to the Companys ARO
obligations for the year ended December 31, 2009:
|
|
|
|
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Balance as of December 31, 2008
|
|
$
|
393
|
|
Additions
|
|
|
3
|
|
Revisions in estimated cashflows
|
|
|
(5
|
)
|
Accretion Expense
|
|
|
8
|
|
Accretion Nuclear decommissioning
|
|
|
16
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
$
|
415
|
|
|
|
|
|
|
187
|
|
Note 14
|
Benefit
Plans and Other Postretirement Benefits
|
NRG sponsors and operates three defined benefit pension and
other postretirement plans. The NRG Plan for Bargained Employees
and the NRG Plan for Non-bargained Employees are maintained
solely for eligible legacy NRG participants. A third plan, the
Texas Genco Retirement Plan, is maintained for participation by
eligible Texas based employees. NRG expects to contribute
approximately $18 million to the Companys three
pension plans in 2010.
NRG Plans for Bargained and Non-bargained
Employees Substantially all employees hired
prior to December 5, 2003, were eligible to participate in
NRGs legacy defined benefit pension plans. The Company
initiated a noncontributory, defined benefit pension plan
effective January 1, 2004, with credit for service from
December 5, 2003. In addition, the Company provides
postretirement health and welfare benefits for certain groups of
employees. Generally, these are groups that were acquired prior
to 2004 and for whom prior benefits are being continued (at
least for a certain period of time or as required by union
contracts). Cost sharing provisions vary by acquisition group
and terms of any applicable collective bargaining agreements.
Texas Genco Retirement Plan The Texas
regions pension plan is a noncontributory defined benefit
pension plan that provides a final average pay benefit or cash
balance benefit, where the participant receives the more
favorable of the two formulas, based on all years of service. In
addition, employees who were hired prior to 1999 are also
eligible for grandfathered benefits under a final average pay
formula. In most cases, the benefits under the grandfathered
formula were frozen on December 31, 2008. NRGs Texas
region employees are also covered under an unfunded
postretirement health and welfare plan. Each year, employees
receive a fixed credit of $750 to their account plus interest.
Certain grandfathered employees will receive additional credits
through 2008. At retirement, the employees may use their
accounts to purchase retiree medical and dental benefits from
NRG. NRGs costs are limited to the amounts earned in the
employees account; all other costs are paid by the
participant.
NRG
Defined Benefit Plans
The net annual periodic pension cost related to NRG domestic
pension and other postretirement benefit plans include the
following components:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
Pension Benefits
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Service cost benefits earned
|
|
$
|
12
|
|
|
$
|
14
|
|
|
$
|
15
|
|
Interest cost on benefit obligation
|
|
|
20
|
|
|
|
18
|
|
|
|
17
|
|
Expected return on plan assets
|
|
|
(16
|
)
|
|
|
(14
|
)
|
|
|
(11
|
)
|
Amortization of unrecognized net gain
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
17
|
|
|
$
|
17
|
|
|
$
|
21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
Other Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Service cost benefits earned
|
|
$
|
2
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Interest cost on benefit obligation
|
|
|
6
|
|
|
|
6
|
|
|
|
5
|
|
Amortization of unrecognized prior service cost
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net periodic benefit cost
|
|
$
|
9
|
|
|
$
|
9
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
188
A comparison of the pension benefit obligation, other post
retirement benefit obligations, and related plan assets as of
December 31, 2009 and 2008 for NRGs plans on a
combined basis is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Benefit obligation at January 1
|
|
$
|
291
|
|
|
$
|
290
|
|
|
$
|
91
|
|
|
$
|
83
|
|
Service cost
|
|
|
12
|
|
|
|
14
|
|
|
|
2
|
|
|
|
2
|
|
Interest cost
|
|
|
20
|
|
|
|
18
|
|
|
|
6
|
|
|
|
6
|
|
Plan amendments
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Actuarial gain
|
|
|
45
|
|
|
|
(19
|
)
|
|
|
6
|
|
|
|
(4
|
)
|
Employee and retiree contributions
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
Benefit payments
|
|
|
(12
|
)
|
|
|
(12
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31
|
|
|
357
|
|
|
|
291
|
|
|
|
104
|
|
|
|
91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1
|
|
|
195
|
|
|
|
168
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets
|
|
|
53
|
|
|
|
(60
|
)
|
|
|
|
|
|
|
|
|
Employee contributions
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
Employer contributions
|
|
|
27
|
|
|
|
99
|
|
|
|
1
|
|
|
|
1
|
|
Benefit payments
|
|
|
(12
|
)
|
|
|
(12
|
)
|
|
|
(2
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31
|
|
|
263
|
|
|
|
195
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded status at December 31 excess of obligation
over assets
|
|
$
|
(94
|
)
|
|
$
|
(96
|
)
|
|
$
|
(104
|
)
|
|
$
|
(91
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts recognized in NRGs balance sheets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Current liabilities
|
|
$
|
|
|
|
$
|
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Non-current liabilities
|
|
|
94
|
|
|
|
96
|
|
|
|
102
|
|
|
|
89
|
|
Amounts recognized in NRGs accumulated other comprehensive
income that have not yet been recognized as components of net
periodic benefit cost were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Unrecognized loss/(gain)
|
|
$
|
29
|
|
|
$
|
21
|
|
|
$
|
1
|
|
|
$
|
(6
|
)
|
Prior service (credit)/cost
|
|
|
(3
|
)
|
|
|
(3
|
)
|
|
|
4
|
|
|
|
5
|
|
189
Other changes in plan assets and benefit obligations recognized
in other comprehensive income were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
|
Other Postretirement
|
|
|
|
Pension Benefits
|
|
|
Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
Net loss/(gain)
|
|
$
|
7
|
|
|
$
|
55
|
|
|
$
|
7
|
|
|
$
|
(4
|
)
|
Amortization of net actuarial loss
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
Prior service cost
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
Amortization for prior service cost
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in other comprehensive loss
|
|
$
|
8
|
|
|
$
|
56
|
|
|
$
|
6
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total recognized in net periodic pension cost and other
comprehensive income
|
|
$
|
25
|
|
|
$
|
73
|
|
|
$
|
15
|
|
|
$
|
9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Companys estimated net gain for NRGs domestic
pension plan that will be amortized from the accumulated other
comprehensive income to net periodic cost over the next fiscal
year is minimal.
The following table presents the balances of significant
components of NRGs domestic pension plan:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Projected benefit obligation
|
|
$
|
357
|
|
|
$
|
291
|
|
Accumulated benefit obligation
|
|
|
309
|
|
|
|
251
|
|
Fair value of plan assets
|
|
|
263
|
|
|
|
195
|
|
NRGs market-related value of its plan assets is the fair
value of the assets. The fair values of the Companys
pension plan assets at December 31, 2009 by asset category
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at December 31, 2009
|
|
|
|
Quoted Prices in
|
|
|
|
|
|
Significant
|
|
|
|
|
|
|
Active Markets for
|
|
|
Significant
|
|
|
Unobservable
|
|
|
|
|
|
|
Identical Assets
|
|
|
Observable
|
|
|
Inputs
|
|
|
|
|
|
|
(Level 1)
|
|
|
Inputs (Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
U.S. equity investment
|
|
$
|
44
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
44
|
|
International equity investment
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Corporate bond investment-fixed income
|
|
|
23
|
|
|
|
|
|
|
|
|
|
|
|
23
|
|
Common/collective trust investment U.S. equity
|
|
|
|
|
|
|
107
|
|
|
|
|
|
|
|
107
|
|
Common/collective trust investment international
equity
|
|
|
|
|
|
|
29
|
|
|
|
|
|
|
|
29
|
|
Common/collective trust investment fixed income
|
|
|
|
|
|
|
48
|
|
|
|
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
79
|
|
|
$
|
184
|
|
|
$
|
|
|
|
$
|
263
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The fair value of the U.S. and international equity
investments and the corporate bond investment are based on
quoted prices in active markets and are categorized in
Level 1. All equity investments are valued at the net asset
value of shares held at year end. The fair value of the
corporate bond investment is based on the closing price reported
on the active market on which the individual securities are
traded. The fair value of the common /collective trusts are
valued at fair value which is equal to the sum of the market
value of all of the funds underlying investments and is
categorized as Level 2.
190
The following table presents the significant assumptions used to
calculate NRGs benefit obligations:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
Weighted-Average
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
Assumptions
|
|
2009
|
|
2008
|
|
2009
|
|
2008
|
|
Discount rate
|
|
5.93%
|
|
6.88%
|
|
6.14%
|
|
6.88%
|
Rate of compensation increase
|
|
4.00-4.50%
|
|
4.00-4.50%
|
|
N/A
|
|
N/A
|
Health care trend rate
|
|
|
|
|
|
9.5% grading to 5.5% in 2016
|
|
9.5% grading to 5.5% in 2016
|
The following table presents the significant assumptions used to
calculate NRGs benefit expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
Weighted-Average
|
|
Pension Benefits
|
|
Other Postretirement Benefits
|
Assumptions
|
|
2009
|
|
2008
|
|
2007
|
|
2009
|
|
2008
|
|
2007
|
|
Discount rate
|
|
6.88%
|
|
6.56%
|
|
5.92%
|
|
6.88%
|
|
6.56%
|
|
5.92%
|
Expected return on plan assets
|
|
7.50%
|
|
7.50%
|
|
8.00%
|
|
|
|
|
|
|
Rate of compensation increase
|
|
4.00-4.50%
|
|
4.00-4.50%
|
|
4.00-4.50%
|
|
|
|
|
|
|
Health care trend rate
|
|
|
|
|
|
|
|
9.5% grading to
5.5% in 2016
|
|
9.5% grading to
5.5% in 2016
|
|
10.5% grading to
5.5% in 2012
|
NRG uses December 31 of each respective year as the measurement
date for the Companys pension and other postretirement
benefit plans. The Company sets the discount rate assumptions on
an annual basis for each of NRGs retirement related
benefit plans at their respective measurement date. This rate is
determined by NRGs Investment Committee based on
information provided by the Companys actuary. The discount
rate assumptions reflect the current rate at which the
associated liabilities could be effectively settled at the end
of the year. The discount rate assumptions used to determine
future pension obligations as of December 31, 2009, and
2008 were based on the Hewitt Yield Curve, or HYC, which was
designed by Hewitt Associates to provide a means for plan
sponsors to value the liabilities of their postretirement
benefit plans. The HYC is a hypothetical yield curve represented
by a series of annualized individual discount rates. Each bond
issue underlying the HYC is required to have a rating of Aa or
better by Moodys Investor Service, Inc. or a rating of AA
or better by Standard & Poors.
NRG employs a total return investment approach, whereby a mix of
equities and fixed income investments are used to maximize the
long-term return of plan assets for a prudent level of risk.
Risk tolerance is established through careful consideration of
plan liabilities, plan funded status, and corporate financial
condition. The target allocation of plan assets is 63% to 77%
invested in equity securities of which 50% to 60% invested in
U.S. equity securities, with the remainder invested in
fixed income securities. The Investment Committee reviews the
asset mix periodically and as the plan assets increase in future
years, the Investment Committee may examine other asset classes
such as real estate or private equity. NRG employs a building
block approach to determining the long-term rate of return for
plan assets, with proper consideration given to diversification
and rebalancing. Historical markets are studied and long-term
historical relationships between equities and fixed income are
preserved, consistent with the widely accepted capital market
principle that assets with higher volatility generate a greater
return over the long run. Current factors such as inflation and
interest rates are evaluated before long-term capital market
assumptions are determined. Peer data and historical returns are
reviewed to check for reasonability and appropriateness.
Plan assets are currently invested in a diversified blend of
equity and fixed-income investments. Furthermore, equity
investments are diversified across U.S. and
non-U.S. equities,
as well as among growth, value, small and large capitalization
stocks.
NRGs pension plan assets weighted average allocation as of
December 31, 2009, and 2008 were as follows:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
U.S. Equity
|
|
|
50-60
|
%
|
|
|
50-55
|
%
|
International Equity
|
|
|
13-17
|
%
|
|
|
15
|
%
|
U.S. Fixed Income
|
|
|
25-35
|
%
|
|
|
30-35
|
%
|
191
NRGs expected future benefit payments for each of the next
five years, and in the aggregate for the five years thereafter,
are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefit
|
|
|
|
Pension
|
|
|
|
|
|
Medicare Prescription
|
|
|
|
Benefit Payments
|
|
|
Benefit Payments
|
|
|
Drug Reimbursements
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
2010
|
|
$
|
16
|
|
|
$
|
2
|
|
|
$
|
|
|
2011
|
|
|
17
|
|
|
|
3
|
|
|
|
|
|
2012
|
|
|
19
|
|
|
|
3
|
|
|
|
|
|
2013
|
|
|
21
|
|
|
|
4
|
|
|
|
|
|
2014
|
|
|
23
|
|
|
|
4
|
|
|
|
|
|
2015-2019
|
|
|
149
|
|
|
|
30
|
|
|
|
1
|
|
Assumed health care cost trend rates have a significant effect
on the amounts reported for the health care plans. A
one-percentage-point change in assumed health care cost trend
rates would have the following effect:
|
|
|
|
|
|
|
|
|
|
|
1-Percentage-
|
|
|
1-Percentage-
|
|
|
|
Point Increase
|
|
|
Point Decrease
|
|
|
|
(In millions)
|
|
|
Effect on total service and interest cost components
|
|
$
|
1
|
|
|
$
|
(1
|
)
|
Effect on postretirement benefit obligation
|
|
|
9
|
|
|
|
(7
|
)
|
STP
Defined Benefit Plans
NRG has a 44% undivided ownership interest in STP, as discussed
further in Note 27, Jointly Owned Plants. STPNOC,
who operates and maintains STP, provides its employees a defined
benefit pension plan as well as postretirement health and
welfare benefits. Although NRG does not sponsor the STP plan, it
reimburses STPNOC for 44% of the contributions made towards its
retirement plan obligations. For the years ending
December 31, 2009, and 2008, NRG reimbursed STPNOC
approximately $5 million and $6 million, respectively,
towards its defined benefit plans. In 2010, NRG expects to
reimburse STPNOC approximately $4 million for its
contributions towards the plans.
The Company has recognized the following in its statement of
financial position and accumulated other comprehensive income
related to its 44% interest in STP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
Pension Benefits
|
|
|
Other Postretirement Benefits
|
|
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Funded status STPNOC benefit plans
|
|
$
|
(43
|
)
|
|
$
|
(48
|
)
|
|
$
|
(30
|
)
|
|
$
|
(27
|
)
|
Net periodic benefit costs
|
|
|
10
|
|
|
|
5
|
|
|
|
4
|
|
|
|
3
|
|
Other changes in plan assets and benefit obligations recognized
in other comprehensive income
|
|
|
(10
|
)
|
|
|
27
|
|
|
|
5
|
|
|
|
6
|
|
Defined
Contribution Plans
NRGs employees have also been eligible to participate in
defined contribution 401(K) plans. The Companys
contributions to these plans were approximately
$22 million, $17 million, and $16 million for the
years ended December 31, 2009, 2008, and 2007, respectively.
192
|
|
Note 15
|
Capital
Structure
|
The following table reflects the changes in NRGs common
stock issued and outstanding for the year ended
December 31, 2009, 2008, and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized
|
|
|
Issued
|
|
|
Treasury
|
|
|
Outstanding
|
|
|
Balance as of December 31, 2006
|
|
|
500,000,000
|
|
|
|
274,248,264
|
|
|
|
(29,601,162
|
)
|
|
|
244,647,102
|
|
Retirement of shares
|
|
|
|
|
|
|
(14,094,962
|
)
|
|
|
14,094,962
|
|
|
|
|
|
Additional Share Repurchase
|
|
|
|
|
|
|
|
|
|
|
(2,037,700
|
)
|
|
|
(2,037,700
|
)
|
Capital Allocation Plans
|
|
|
|
|
|
|
|
|
|
|
(7,006,700
|
)
|
|
|
(7,006,700
|
)
|
Shares issued from LTIP
|
|
|
|
|
|
|
1,132,227
|
|
|
|
|
|
|
|
1,132,227
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2007
|
|
|
500,000,000
|
|
|
|
261,285,529
|
|
|
|
(24,550,600
|
)
|
|
|
236,734,929
|
|
Capital Allocation Plans
|
|
|
|
|
|
|
|
|
|
|
(4,691,883
|
)
|
|
|
(4,691,883
|
)
|
Shares issued from LTIP
|
|
|
|
|
|
|
1,004,176
|
|
|
|
|
|
|
|
1,004,176
|
|
5.75% Preferred Stock conversion
|
|
|
|
|
|
|
1,309,495
|
|
|
|
|
|
|
|
1,309,495
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2008
|
|
|
500,000,000
|
|
|
|
263,599,200
|
|
|
|
(29,242,483
|
)
|
|
|
234,356,717
|
|
Shares issued under NRG Employee Stock Purchase Plan, or ESPP
|
|
|
|
|
|
|
|
|
|
|
81,532
|
|
|
|
81,532
|
|
Shares loaned to affiliates of CS
|
|
|
|
|
|
|
|
|
|
|
12,000,000
|
|
|
|
12,000,000
|
|
Shares returned by affiliate of CS
|
|
|
|
|
|
|
|
|
|
|
(5,400,000
|
)
|
|
|
(5,400,000
|
)
|
Capital Allocation Plans
|
|
|
|
|
|
|
|
|
|
|
(19,305,500
|
)
|
|
|
(19,305,500
|
)
|
Shares issued from LTIP
|
|
|
|
|
|
|
367,858
|
|
|
|
|
|
|
|
367,858
|
|
4.00% Preferred Stock conversion
|
|
|
|
|
|
|
13,293,500
|
|
|
|
|
|
|
|
13,293,500
|
|
5.75% Preferred Stock conversion
|
|
|
|
|
|
|
18,601,201
|
|
|
|
|
|
|
|
18,601,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2009
|
|
|
500,000,000
|
|
|
|
295,861,759
|
|
|
|
(41,866,451
|
)
|
|
|
253,995,308
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes NRGs common stock reserved
for the maximum number of shares potentially issuable based on
the conversion and redemption features of outstanding equity
instruments and the long-term incentive plan as of
December 31, 2009:
|
|
|
|
|
|
|
Common Stock
|
|
Equity Instrument
|
|
Reserve Balance
|
|
|
4% Convertible perpetual preferred
|
|
|
12,858,472
|
|
3.625% Convertible perpetual preferred
|
|
|
16,000,000
|
|
Long term incentive plan
|
|
|
13,193,707
|
|
|
|
|
|
|
Total
|
|
|
42,052,179
|
|
|
|
|
|
|
Capital Allocation Plan In December 2007, the
Company initiated its 2008 Capital Allocation Plan, with the
repurchase of 2,037,700 shares of NRG common stock during
that month for approximately $85 million. In February 2008,
the Companys Board of Directors authorized an additional
$200 million in common share repurchases that raised the
total 2008 Capital Allocation Plan to approximately
$300 million. During 2008, the Company repurchased a total
of 4,691,883 shares for approximately $185 million. As
of December 31, 2008, NRG had repurchased a total of
6,729,583 shares of NRG common stock at a cost of
approximately $270 million as part of its 2008 Capital
Allocation Plan.
In the third quarter 2009, to complete its remaining
$30 million planned share re-purchase under the 2008
Capital Allocation plan and to initiate its 2009 Capital
Allocation Plan, the Company repurchased 8,919,100 shares
of NRG common stock for approximately $250 million. In the
fourth quarter 2009, the Company repurchased an additional
10,386,400 shares of NRG common stock for approximately
$250 million. For 2009, NRG repurchased a total of
19,305,500 shares of NRG common stock at a cost of
approximately $500 million under its share repurchase
program.
Retirement of Treasury Stock On May 22,
2007, NRG retired 14,094,962 shares of treasury stock.
These retired shares are now included in the Companys pool
of authorized but unissued shares. The retired stock had a
carrying value of approximately $447 million. The
Companys accounting policy upon the formal retirement of
193
treasury stock is to deduct its par value from Common Stock and
to reflect any excess of cost over par value as a deduction from
Additional Paid-in Capital.
Employee Stock Purchase Plan In May 2008, NRG
shareholders approved the adoption of the NRG Energy, Inc.
Employee Stock Purchase Plan, or ESPP, pursuant to which
eligible employees may elect to withhold up to 10% of their
eligible compensation to purchase shares of NRG common stock at
85% of its fair market value on the exercise date. An exercise
date occurs each June 30 and December 31. The initial six
month employee withholding period began July 1, 2008 and
the first issuance of common stock under the ESPP occurred in
2009. As of December 31, 2009, there remained
418,468 shares of treasury stock reserved for issuance
under the ESPP, and in January 2010, 54,845 shares of
common stock were issued to employee accounts from treasury
stock.
Share Lending Agreements As discussed in
Note 12, Debt and Capital Leases, under Debt
Related to Capital Allocation Program, CSF I and CSF II
loaned 12,000,000 shares of NRG common stock to affiliates
of CS in the first quarter 2009, and in the fourth quarter 2009,
CS returned 5,400,000 of these shares in connection with the
maturity of the CSF II Debt.
Preferred
Stock
As of December 31, 2009, and 2008, the Company had
10,000,000 shares of preferred stock authorized. As of
December 31, 2009, the Companys preferred stock
consisted of two series: the 4% Convertible Perpetual
Preferred Stock, or 4% Preferred Stock; and the
3.625% Convertible Perpetual Preferred Stock, which is
treated as Redeemable Preferred Stock, or 3.625% Preferred Stock.
5.75%
Preferred Stock
On February 2, 2006, NRG completed the issuance of
2,000,000 shares of 5.75% Preferred Stock, for net proceeds
of $486 million, reflecting an offering price of $250 per
share and the deduction of offering expenses and discounts of
approximately $14 million. Dividends on the 5.75% Preferred
Stock were $14.375 per share per year, and were due and payable
on a quarterly basis beginning on March 15, 2006.
Certain holders of the Companys 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 December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
18,601,201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4%
Preferred Stock
As of December 31, 2009, and 2008, 154,057 and
420,000 shares of the Companys 4% Preferred Stock
were issued and outstanding at a liquidation value, net of
issuance costs, of $149 million and $406 million,
respectively. The 4% Preferred Stock has a liquidation
preference of $1,000 per share. Holders of the 4% Preferred
Stock are entitled to receive, when declared by NRGs Board
of Directors, cash dividends at the rate of 4% per annum, or
$40.00 per share per year, payable quarterly in arrears
commencing on March 15, 2005. The 4% Preferred Stock is
convertible, at the option of the holder, at any time into
shares of NRGs common stock at an initial conversion price
of $20.00 per share. In addition, NRG had the ability to redeem,
on or after December 20, 2009, and subject to
194
certain limitations, some or all of the 4% Preferred Stock with
cash at a redemption price equal to 100% of the liquidation
preference, plus accumulated but unpaid dividends, including
liquidated damages, if any, to the redemption date.
During the first half of 2009, 413 shares of 4% Preferred
Stock were converted, at the option of the holder, into
20,650 shares of common stock. In addition, in November
2009, NRG notified the holders of the Companys intention
to redeem approximately 50% of the outstanding 4% Preferred
Stock and 265,457 shares of the 4% Preferred Stock were
converted, at the option of the holder, into
13,272,850 shares of common stock in December 2009 in
response to this notification. These conversions resulted in a
decrease in preferred stock of $257 million, and a
corresponding increase in Additional Paid-in Capital. The
following table summarizes all 4% Preferred Stock conversions
and redemptions for the year ended December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock
|
|
|
Conversion Rate
|
|
|
Common Stock
|
|
|
|
Shares
|
|
|
(per share)
|
|
|
Shares
|
|
|
Balance as of December 31, 2008
|
|
|
420,000
|
|
|
|
|
|
|
|
|
|
Preferred shares converted by the holders prior to
November 20, 2009
|
|
|
413
|
|
|
|
50
|
|
|
|
20,650
|
|
First redemption:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred shares converted by the holders prior to
December 22, 2009
|
|
|
256,486
|
|
|
|
50
|
|
|
|
12,824,300
|
|
Preferred shares redeemed for cash by the Company prior to
December 22, 2009
|
|
|
73
|
|
|
|
|
|
|
|
|
|
Second redemption:
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred shares converted by the holders prior to December 31 ,
2009
|
|
|
8,971
|
|
|
|
50
|
|
|
|
448,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
154,057
|
|
|
|
|
|
|
|
13,293,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On December 22, 2009, NRG notified the holders of the 4%
Preferred Stock of the Companys intention to call for
redemption the remaining outstanding shares of 4% Preferred
Stock on January 21, 2010. As of January 21, 2010, the
Company completed the redemption of the remaining shares of 4%
Preferred Stock, with holders converting 154,029 shares to
7,701,450 shares of common stock and the Company redeeming
28 shares for $28,000 cash.
Redeemable
Preferred Stock
3.625%
Preferred Stock
On August 11, 2005, NRG issued 250,000 shares of
3.625% Preferred Stock, which is treated as Redeemable Preferred
Stock, to CS in a private placement. As of December 31,
2009 and 2008, 250,000 shares of the 3.625% Preferred Stock
were issued and outstanding at a liquidation value, net of
issuance costs, of $247 million. The 3.625% Preferred Stock
amount is located after the liabilities but before the
stockholders equity section on the balance sheet, due to
the fact that the preferred shares can be redeemed in cash by
the shareholder. The 3.625% Preferred Stock has a liquidation
preference of $1,000 per share. Holders of the 3.625% Preferred
Stock are entitled to receive, out of legally available funds,
cash dividends at the rate of 3.625% per annum, or $36.25 per
share per year, payable in cash quarterly in arrears commencing
on December 15, 2005.
Each share of the 3.625% Preferred Stock is convertible during
the 90-day
period beginning August 11, 2015 at the option of NRG or
the holder. Holders tendering the 3.625% Preferred Stock for
conversion shall be entitled to receive, for each share of
3.625% Preferred Stock converted, $1,000 in cash and a number of
shares of NRG common stock equal to the product of (a) the
greater of (i) the difference between the average closing
share price of NRG common stock on each of the 20 consecutive
scheduled trading days starting on the date 30 exchange business
days immediately prior to the conversion date, or the Market
Price, and $29.54 and (ii) zero, times (b) 50.77. The
number of NRG common stock to be delivered under the conversion
feature is limited to 16,000,000 shares. If upon
conversion, the Market Price is less than $19.69, then the
Holder will deliver to NRG cash or a number of shares of NRG
common stock equal in value to the product of (i) $19.69
minus the Market Price, times (ii) 50.77. NRG may elect to
make a cash payment in lieu of delivering shares of NRG common
stock in connection with such
195
conversion, and NRG may elect to receive cash in lieu of shares
of common stock, if any, from the Holder in connection with such
conversion. The conversion feature is considered an embedded
derivative per ASC 815 that is exempt from derivative accounting
as it is excluded from the scope pursuant to ASC 815.
If a fundamental change occurs, the holders will have the right
to require NRG to repurchase all or a portion of the 3.625%
Preferred Stock for a period of time after the fundamental
change at a purchase price equal to 100% of the liquidation
preference, plus accumulated and unpaid dividends. The 3.625%
Preferred Stock is senior to all classes of common stock, on
parity with the Companys 4% Preferred Stock, and junior to
all of the Companys existing and future debt obligations
and all of NRG subsidiaries existing and future
liabilities and capital stock held by persons other than NRG or
its subsidiaries.
|
|
Note 16
|
Investments
Accounted for by the Equity Method
|
NRG accounts for the Companys significant investments
using the equity method of accounting. NRGs carrying value
of equity investments can be impacted by impairments, unrealized
gains and losses on derivatives and movements in foreign
currency exchange rates, as well as other adjustments.
The following table summarizes NRGs equity method
investments, as of December 31, 2009:
|
|
|
|
|
|
|
|
|
Economic
|
Name
|
|
Geographic Area
|
|
Interest
|
|
Sherbino I Wind Farm LLC
|
|
USA
|
|
50.0%
|
Saguaro Power Company
|
|
USA
|
|
50.0%
|
GenConn Energy LLC
|
|
USA
|
|
50.0%
|
Gladstone Power Station
|
|
Australia
|
|
37.5%
|
MIBRAG On June 10, 2009, NRG
completed the sale of its 50% ownership in Mibrag B.V. See
further discussion in Note 4, Discontinued Operations
and Dispositions.
Sherbino I Wind Farm LLC NRG owns a
50% interest in Sherbino, a joint venture with BP Wind Energy
North America Inc. Sherbino is a 150MW wind farm consisting of
50 Vestas 3MW wind turbine generators, which commenced
commercial operations in October 2008. NRG contributed
approximately $84 million to its equity investment in
Sherbino in 2008. NRGs equity loss from Sherbino was
insignificant for the year ended December 31, 2009, and for
the year ended December 31, 2008, NRG posted equity
earnings from Sherbino of $8 million.
Saguaro Power Company NRG owns a 50%
interest in the Saguaro plant, a cogeneration plant with
dual-fuel capability, natural gas and oil. For the year ended
December 31, 2009, NRGs equity income from Saguaro
was $10 million. NRG posted equity losses in 2008 and 2007
of $2 million and $3 million, respectively.
GenConn Energy LLC NRG owns a 50%
interest in GenConn, a limited liability company formed in
February 2008 by NRG and The United Illuminating Company, or UI,
for the construction and operation of two 200 MW peaking
facilities in Connecticut through GenConns wholly-owned
subsidiaries, GenConn Devon, LLC, or Devon, and GenConn
Middletown LLC, or Middletown. Devon and Middletown have each
entered into
30-year cost
of service type contracts with CL&P as mandated by the
DPUC, commencing when the facilities reach commercial
operations, currently expected to be 2010 and 2011, respectively.
The project is expected to be funded through equity
contributions from the owners and non-recourse, project level
debt. As of December 31, 2009, NRG has made a nominal
equity investment in GenConn. In addition, as discussed in
Note 9, Capital Leases and Notes Receivable, in 2008
NRG entered into a short-term $45 million note receivable
facility with GenConn to fund NRGs proportionate
share of project liquidity needs which was repaid in 2009.
NRGs maximum exposure to loss is limited to its equity
investments and note receivable.
On April 27, 2009, a wholly-owned subsidiary of NRG, NRG
Connecticut Peaking LLC, closed on an equity bridge loan
facility, or EBL, in the amount of $121.5 million from a
syndicate of banks. For a detailed discussion on the facility,
see Note 12 Debt and Capital Leases.
GenConn had borrowed $108 million under this facility as of
December 31, 2009.
196
As discussed in Note 21, Related Party Transactions,
NRG has entered into construction management agreements with
Devon and Middletown, and recognized approximately
$7 million and $1 million of revenue for the years
ended December 31, 2009 and 2008, respectively. In
addition, NRG earned interest income of $2 million in 2009
from GenConn on an outstanding note receivable as discussed in
Note 9, Capital Leases and Notes Receivable.
GenConn is considered a VIE under ASC 810, but NRG is not the
primary beneficiary of GenConn and accounts for its 50% interest
under the equity method. GenConn is a development stage entity,
and is not expected to begin generating revenues until 2010;
therefore NRG recognized no equity earnings from the joint
venture for the years ended December 31, 2008 or 2009.
Gladstone Through a joint venture, NRG
owns a 37.5% interest in Gladstone, a 1,613 megawatt coal-fueled
power generation facility in Queensland, Australia. The power
generation facility is managed by the joint venture participants
and the facility is operated by NRG. Operating expenses incurred
in connection with the operation of the facility are funded by
each of the participants in proportion to their ownership
interests. Coal is sourced from local mines in Queensland. NRG
and the joint venture participants receive their respective
share of revenues directly from the off takers in proportion to
the ownership interests in the joint venture. Power generated by
the facility is primarily sold to an adjacent aluminum smelter,
with excess power sold to the Queensland Government owned
utility under long term supply contracts. For the years ended
December 31, 2009, 2008 and 2007, NRGs equity
earnings from Gladstone were approximately $17 million,
$21 million and $21 million, respectively.
The undistributed earnings from equity investments as of
December 31, 2009 and 2008, were $132 million and
$116 million, respectively.
|
|
Note 17
|
Earnings
Per Share
|
Basic earnings per common share is computed by dividing net
income less accumulated preferred stock dividends by the
weighted average number of common shares outstanding. Shares
issued and treasury shares repurchased during the year are
weighted for the portion of the year that they were outstanding.
Diluted earnings per share is computed in a manner consistent
with that of basic earnings per share while giving effect to all
potentially dilutive common shares that were outstanding during
the period.
Dilutive effect for equity compensation The
outstanding non-qualified stock options, non-vested restricted
stock units, deferred stock units and performance units are not
considered outstanding for purposes of computing basic earnings
per share. However, these instruments are included in the
denominator for purposes of computing diluted earnings per share
under the treasury stock method.
Dilutive effect for other equity instruments
NRGs outstanding 4% Preferred Stock and 5.75% Preferred
Stock are not considered outstanding for purposes of computing
basic earnings per share. However, these instruments are
considered for inclusion in the denominator for purposes of
computing diluted earnings per share under the if-converted
method. The if-converted method is also used to determine the
dilutive effect of embedded derivatives in the Companys
3.625% Preferred Stock, and CSF preferred interests and notes.
197
The reconciliation of NRGs basic earnings per common share
to diluted earnings per share for the years ended
December 31, 2009, 2008 and 2007 is shown in the following
table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Basic earnings per share attributable to NRG common
stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations, net of income taxes
|
|
$
|
942
|
|
|
$
|
1,053
|
|
|
$
|
556
|
|
Preferred stock dividends
|
|
|
(33
|
)
|
|
|
(55
|
)
|
|
|
(55
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
|
909
|
|
|
|
998
|
|
|
|
501
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
172
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc. available to common
stockholders
|
|
$
|
909
|
|
|
$
|
1,170
|
|
|
$
|
518
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
245.5
|
|
|
|
235.0
|
|
|
|
240.2
|
|
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations
|
|
$
|
3.70
|
|
|
$
|
4.25
|
|
|
$
|
2.09
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
0.73
|
|
|
|
0.07
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
3.70
|
|
|
$
|
4.98
|
|
|
$
|
2.16
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share attributable to NRG common
stockholders
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing
operations
|
|
$
|
909
|
|
|
$
|
998
|
|
|
$
|
501
|
|
Add preferred stock dividends for dilutive preferred stock
|
|
|
23
|
|
|
|
46
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted income from continuing operations available to common
stockholders
|
|
|
932
|
|
|
|
1,044
|
|
|
|
547
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
172
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc. available to common
stockholders
|
|
$
|
932
|
|
|
$
|
1,216
|
|
|
$
|
564
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
245.5
|
|
|
|
235.0
|
|
|
|
240.2
|
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method)
|
|
|
1.2
|
|
|
|
2.3
|
|
|
|
3.8
|
|
Incremental shares attributable to embedded derivatives of
certain financial instruments (if-converted method)
|
|
|
|
|
|
|
|
|
|
|
6.0
|
|
Incremental shares attributable to the assumed conversion
features of outstanding preferred stock (if-converted method)
|
|
|
24.5
|
|
|
|
37.5
|
|
|
|
37.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total dilutive shares
|
|
|
271.2
|
|
|
|
274.8
|
|
|
|
287.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from continuing operations available to common
stockholders
|
|
$
|
3.44
|
|
|
$
|
3.80
|
|
|
$
|
1.90
|
|
Income from discontinued operations, net of tax
|
|
|
|
|
|
|
0.63
|
|
|
|
0.06
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
3.44
|
|
|
$
|
4.43
|
|
|
$
|
1.96
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes NRGs outstanding equity
instruments that are anti-dilutive and were not included in the
computation of the Companys diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions of shares)
|
|
|
Equity compensation NQSOs and PUs
|
|
|
5.7
|
|
|
|
1.9
|
|
|
|
0.1
|
|
Embedded derivative of 3.625% redeemable perpetual preferred
stock
|
|
|
16.0
|
|
|
|
16.0
|
|
|
|
12.2
|
|
Embedded derivatives of CSF preferred interests and notes
|
|
|
|
|
|
|
7.6
|
|
|
|
16.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
21.7
|
|
|
|
25.5
|
|
|
|
28.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
198
|
|
Note 18
|
Segment
Reporting
|
NRGs segment structure reflects core areas of operation
which are primarily segregated based on the Companys
wholesale power generation, retail, thermal and chilled water
business, and corporate activities. In May 2009, NRGs
segment structure changed to reflect the Companys
acquisition of Reliant Energy and has been incorporated as a
separate reporting segment as per ASC 280, Segment
Reporting. Within NRGs wholesale power generation
operations, there are distinct components with separate
operating results and management structures for the following
geographical regions: Texas, Northeast, South Central, West and
International. The Companys corporate activities include
wind, solar and nuclear development.
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 have been allocated based on forecasted
earnings/(losses) before interest expense, income taxes,
depreciation and amortization expense.
As of December 31, 2009, there were no customers from whom
the Company derived more than 10% of the Companys
consolidated revenues. The following table summarizes customers
from whom NRG derived more than 10% of the Companys
consolidated revenues for the years ended December 31, 2008
and 2007:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
Customer A Texas region
|
|
|
11
|
%
|
|
|
|
%
|
Customer B Texas region
|
|
|
11
|
|
|
|
27
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
22
|
%
|
|
|
27
|
%
|
|
|
|
|
|
|
|
|
|
199
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
|
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reliant
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy
|
|
|
Texas(a)
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
4,182
|
|
|
$
|
2,946
|
|
|
$
|
1,201
|
|
|
$
|
581
|
|
|
$
|
150
|
|
|
$
|
144
|
|
|
$
|
135
|
|
|
$
|
28
|
|
|
$
|
(415
|
)
|
|
$
|
8,952
|
|
Operating expenses
|
|
|
3,044
|
|
|
|
1,634
|
|
|
|
740
|
|
|
|
508
|
|
|
|
110
|
|
|
|
116
|
|
|
|
112
|
|
|
|
129
|
|
|
|
(418
|
)
|
|
|
5,975
|
|
Depreciation and amortization
|
|
|
137
|
|
|
|
472
|
|
|
|
118
|
|
|
|
67
|
|
|
|
8
|
|
|
|
|
|
|
|
10
|
|
|
|
6
|
|
|
|
|
|
|
|
818
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
1,001
|
|
|
|
840
|
|
|
|
343
|
|
|
|
6
|
|
|
|
32
|
|
|
|
28
|
|
|
|
13
|
|
|
|
(107
|
)
|
|
|
3
|
|
|
|
2,159
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
Other income/(loss), net
|
|
|
|
|
|
|
7
|
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
(20
|
)
|
|
|
|
|
|
|
27
|
|
|
|
(22
|
)
|
|
|
(5
|
)
|
Refinancing expenses
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
(20
|
)
|
Interest expense
|
|
|
(34
|
)
|
|
|
(4
|
)
|
|
|
(54
|
)
|
|
|
(48
|
)
|
|
|
(2
|
)
|
|
|
(8
|
)
|
|
|
(5
|
)
|
|
|
(497
|
)
|
|
|
18
|
|
|
|
(634
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
966
|
|
|
|
843
|
|
|
|
291
|
|
|
|
(41
|
)
|
|
|
40
|
|
|
|
159
|
|
|
|
8
|
|
|
|
(596
|
)
|
|
|
(1
|
)
|
|
|
1,669
|
|
Income tax expense
|
|
|
|
|
|
|
171
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
548
|
|
|
|
|
|
|
|
728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
966
|
|
|
|
672
|
|
|
|
291
|
|
|
|
(41
|
)
|
|
|
40
|
|
|
|
150
|
|
|
|
8
|
|
|
|
(1,144
|
)
|
|
|
(1
|
)
|
|
|
941
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
|
966
|
|
|
|
672
|
|
|
|
291
|
|
|
|
(41
|
)
|
|
|
40
|
|
|
|
150
|
|
|
|
8
|
|
|
|
(1,144
|
)
|
|
|
(1
|
)
|
|
|
941
|
|
Less: Net loss attributable to noncontrolling interest
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) attributable to NRG Energy, Inc.
|
|
$
|
966
|
|
|
$
|
673
|
|
|
$
|
291
|
|
|
$
|
(41
|
)
|
|
$
|
40
|
|
|
$
|
150
|
|
|
$
|
8
|
|
|
$
|
(1,144
|
)
|
|
$
|
(1
|
)
|
|
$
|
942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
$
|
2
|
|
|
$
|
92
|
|
|
$
|
6
|
|
|
$
|
|
|
|
$
|
35
|
|
|
$
|
273
|
|
|
$
|
|
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
409
|
|
Capital expenditures
|
|
|
7
|
|
|
|
189
|
|
|
|
207
|
|
|
|
9
|
|
|
|
8
|
|
|
|
|
|
|
|
10
|
|
|
|
353
|
|
|
|
|
|
|
|
783
|
|
Goodwill
|
|
|
|
|
|
|
1,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
1,718
|
|
Total assets
|
|
$
|
2,007
|
|
|
$
|
13,092
|
|
|
$
|
1,866
|
|
|
$
|
909
|
|
|
$
|
329
|
|
|
$
|
785
|
|
|
$
|
206
|
|
|
$
|
22,442
|
|
|
$
|
(18,258
|
)
|
|
$
|
23,378
|
|
(a) Includes inter-segment sales of $411 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 year ended
December 31, 2009, would have been as follows:
|
Net income/(loss) attributable to NRG Energy, Inc. as reported
|
|
$
|
966
|
|
|
$
|
673
|
|
|
$
|
291
|
|
|
$
|
(41
|
)
|
|
$
|
40
|
|
|
$
|
150
|
|
|
$
|
8
|
|
|
$
|
(1,144
|
)
|
|
$
|
(1
|
)
|
|
$
|
942
|
|
Increase/(decrease) in net income/(loss) attributable to NRG
Energy, Inc.
|
|
|
(46
|
)
|
|
|
33
|
|
|
|
13
|
|
|
|
(3
|
)
|
|
|
2
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted net income/(loss) attributable to NRG Energy,
Inc.
|
|
$
|
920
|
|
|
$
|
706
|
|
|
$
|
304
|
|
|
$
|
(44
|
)
|
|
$
|
42
|
|
|
$
|
151
|
|
|
$
|
8
|
|
|
$
|
(1,144
|
)
|
|
$
|
(1
|
)
|
|
$
|
942
|
|
|
|
200
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
4,026
|
|
|
$
|
1,630
|
|
|
$
|
746
|
|
|
$
|
171
|
|
|
$
|
158
|
|
|
$
|
154
|
|
|
$
|
3
|
|
|
$
|
(3
|
)
|
|
$
|
6,885
|
|
Operating expenses
|
|
|
1,890
|
|
|
|
1,087
|
|
|
|
579
|
|
|
|
105
|
|
|
|
133
|
|
|
|
122
|
|
|
|
52
|
|
|
|
(5
|
)
|
|
|
3,963
|
|
Depreciation and amortization
|
|
|
451
|
|
|
|
109
|
|
|
|
67
|
|
|
|
8
|
|
|
|
|
|
|
|
10
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
1,685
|
|
|
|
434
|
|
|
|
100
|
|
|
|
58
|
|
|
|
25
|
|
|
|
22
|
|
|
|
(53
|
)
|
|
|
2
|
|
|
|
2,273
|
|
Equity in earnings/(loss) of unconsolidated affiliates
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
(2
|
)
|
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
Other income, net
|
|
|
9
|
|
|
|
12
|
|
|
|
1
|
|
|
|
1
|
|
|
|
5
|
|
|
|
|
|
|
|
20
|
|
|
|
(31
|
)
|
|
|
17
|
|
Interest expense
|
|
|
(100
|
)
|
|
|
(56
|
)
|
|
|
(51
|
)
|
|
|
(6
|
)
|
|
|
|
|
|
|
(6
|
)
|
|
|
(383
|
)
|
|
|
19
|
|
|
|
(583
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
1,603
|
|
|
|
390
|
|
|
|
50
|
|
|
|
51
|
|
|
|
82
|
|
|
|
16
|
|
|
|
(416
|
)
|
|
|
(10
|
)
|
|
|
1,766
|
|
Income tax expense
|
|
|
692
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
911
|
|
|
|
390
|
|
|
|
50
|
|
|
|
51
|
|
|
|
63
|
|
|
|
16
|
|
|
|
(418
|
)
|
|
|
(10
|
)
|
|
|
1,053
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
|
911
|
|
|
|
390
|
|
|
|
50
|
|
|
|
51
|
|
|
|
235
|
|
|
|
16
|
|
|
|
(418
|
)
|
|
|
(10
|
)
|
|
|
1,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) attributable to NRG Energy, Inc.
|
|
$
|
911
|
|
|
$
|
390
|
|
|
$
|
50
|
|
|
$
|
51
|
|
|
$
|
235
|
|
|
$
|
16
|
|
|
$
|
(418
|
)
|
|
$
|
(10
|
)
|
|
$
|
1,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity investments in affiliates
|
|
$
|
92
|
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
25
|
|
|
$
|
372
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
490
|
|
Capital expenditures
|
|
|
238
|
|
|
|
208
|
|
|
|
14
|
|
|
|
35
|
|
|
|
|
|
|
|
11
|
|
|
|
509
|
|
|
|
|
|
|
|
1,015
|
|
Goodwill
|
|
|
1,713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
1,718
|
|
Total assets
|
|
$
|
12,899
|
|
|
$
|
1,667
|
|
|
$
|
933
|
|
|
$
|
264
|
|
|
$
|
973
|
|
|
$
|
208
|
|
|
$
|
20,215
|
|
|
$
|
(12,351
|
)
|
|
$
|
24,808
|
|
201
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2007
|
|
|
|
Wholesale Power Generation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Texas
|
|
|
Northeast
|
|
|
Central
|
|
|
West
|
|
|
International
|
|
|
Thermal
|
|
|
Corporate
|
|
|
Elimination
|
|
|
Total
|
|
|
|
(In millions)
|
|
|
Operating revenues
|
|
$
|
3,287
|
|
|
$
|
1,605
|
|
|
$
|
658
|
|
|
$
|
127
|
|
|
$
|
140
|
|
|
$
|
159
|
|
|
$
|
30
|
|
|
$
|
(17
|
)
|
|
$
|
5,989
|
|
Operating expenses
|
|
|
1,849
|
|
|
|
1,045
|
|
|
|
533
|
|
|
|
85
|
|
|
|
112
|
|
|
|
125
|
|
|
|
47
|
|
|
|
(8
|
)
|
|
|
3,788
|
|
Depreciation and amortization
|
|
|
469
|
|
|
|
102
|
|
|
|
68
|
|
|
|
3
|
|
|
|
|
|
|
|
11
|
|
|
|
5
|
|
|
|
|
|
|
|
658
|
|
Gain/(loss) on disposal/sale of assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income/(loss)
|
|
|
969
|
|
|
|
458
|
|
|
|
57
|
|
|
|
39
|
|
|
|
28
|
|
|
|
41
|
|
|
|
(23
|
)
|
|
|
(9
|
)
|
|
|
1,560
|
|
Equity in earnings/(loss) of unconsolidated affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3
|
)
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
1
|
|
Other income, net
|
|
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8
|
|
|
|
1
|
|
|
|
58
|
|
|
|
(19
|
)
|
|
|
55
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
(35
|
)
|
Interest expense
|
|
|
(164
|
)
|
|
|
(57
|
)
|
|
|
(53
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
(6
|
)
|
|
|
(436
|
)
|
|
|
19
|
|
|
|
(702
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations before income taxes
|
|
|
812
|
|
|
|
401
|
|
|
|
4
|
|
|
|
36
|
|
|
|
88
|
|
|
|
36
|
|
|
|
(435
|
)
|
|
|
(9
|
)
|
|
|
933
|
|
Income tax expense/(benefit)
|
|
|
327
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12
|
)
|
|
|
|
|
|
|
62
|
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from continuing operations
|
|
|
485
|
|
|
|
401
|
|
|
|
4
|
|
|
|
36
|
|
|
|
100
|
|
|
|
36
|
|
|
|
(497
|
)
|
|
|
(9
|
)
|
|
|
556
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss)
|
|
|
485
|
|
|
|
401
|
|
|
|
4
|
|
|
|
36
|
|
|
|
117
|
|
|
|
36
|
|
|
|
(497
|
)
|
|
|
(9
|
)
|
|
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(loss) attributable to NRG Energy, Inc.
|
|
$
|
485
|
|
|
$
|
401
|
|
|
$
|
4
|
|
|
$
|
36
|
|
|
$
|
117
|
|
|
$
|
36
|
|
|
$
|
(497
|
)
|
|
$
|
(9
|
)
|
|
$
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
202
The income tax provision from continuing operations for the
years ended December 31, 2009, 2008 and 2007 consisted of
the following amounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Federal
|
|
$
|
99
|
|
|
$
|
89
|
|
|
$
|
(6
|
)
|
State
|
|
|
20
|
|
|
|
31
|
|
|
|
(1
|
)
|
Foreign
|
|
|
18
|
|
|
|
17
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
137
|
|
|
|
137
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Federal
|
|
|
599
|
|
|
|
539
|
|
|
|
347
|
|
State
|
|
|
1
|
|
|
|
35
|
|
|
|
47
|
|
Foreign
|
|
|
(9
|
)
|
|
|
2
|
|
|
|
(30
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
591
|
|
|
|
576
|
|
|
|
364
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax
|
|
$
|
728
|
|
|
$
|
713
|
|
|
$
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
43.6
|
%
|
|
|
40.4
|
%
|
|
|
40.4
|
%
|
The following represents the domestic and foreign components of
income from continuing operations before income tax expense for
the years ended December 31, 2009, 2008 and 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
U.S.
|
|
$
|
1,508
|
|
|
$
|
1,681
|
|
|
$
|
847
|
|
Foreign
|
|
|
161
|
|
|
|
85
|
|
|
|
86
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
1,669
|
|
|
$
|
1,766
|
|
|
$
|
933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
A reconciliation of the U.S. federal statutory rate of 35%
to NRGs effective rate from continuing operations for the
years ended December 31, 2009, 2008 and 2007 were as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions, except percentages)
|
|
|
Income from continuing operations before income taxes
|
|
$
|
1,669
|
|
|
$
|
1,766
|
|
|
$
|
933
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax at 35%
|
|
|
584
|
|
|
|
618
|
|
|
|
327
|
|
State taxes, net of federal benefit
|
|
|
23
|
|
|
|
74
|
|
|
|
46
|
|
Foreign operations
|
|
|
(53
|
)
|
|
|
(10
|
)
|
|
|
(13
|
)
|
Subpart F taxable income
|
|
|
|
|
|
|
2
|
|
|
|
|
|
Valuation allowance
|
|
|
119
|
|
|
|
(12
|
)
|
|
|
6
|
|
Expiration of capital losses
|
|
|
249
|
|
|
|
|
|
|
|
|
|
Reversal of valuation allowance on expired capital losses
|
|
|
(249
|
)
|
|
|
|
|
|
|
|
|
Change in state effective tax rate
|
|
|
(5
|
)
|
|
|
(11
|
)
|
|
|
|
|
Change in local German effective tax rates
|
|
|
|
|
|
|
|
|
|
|
(29
|
)
|
Foreign dividends and foreign earnings
|
|
|
33
|
|
|
|
32
|
|
|
|
26
|
|
Non-deductible interest
|
|
|
10
|
|
|
|
12
|
|
|
|
10
|
|
FIN 48 interest
|
|
|
9
|
|
|
|
8
|
|
|
|
|
|
Production tax credit
|
|
|
(10
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
18
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense
|
|
$
|
728
|
|
|
$
|
713
|
|
|
$
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate
|
|
|
43.6
|
%
|
|
|
40.4
|
%
|
|
|
40.4
|
%
|
The effective income tax rate for the year ended
December 31, 2009, 2008 and 2007 differs from the
U.S. statutory rate of 35% due to changes in the valuation
allowance as a result of capital gain or losses generated
203
during the period. In addition, the current earnings in foreign
jurisdictions are taxed at rates lower than the
U.S. statutory rate, including the sale of the MIBRAG in
2009 which resulted in minimal tax due to the local jurisdiction.
For the year ended December 31, 2009, NRGs state
effective income tax rate has been reduced to 3%, which is lower
than its 2008 rate of 6%, due to increased operational
activities within the state of Texas in the current year. This
decrease was primarily due to the acquisition of Reliant Energy
which operates in the state of Texas.
The temporary differences, which gave rise to the Companys
deferred tax assets and liabilities as of December 31, 2009
and 2008, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Discount/premium on notes
|
|
$
|
12
|
|
|
$
|
13
|
|
Emissions allowances
|
|
|
119
|
|
|
|
112
|
|
Difference between book and tax basis of property
|
|
|
1,604
|
|
|
|
1,477
|
|
Derivatives, net
|
|
|
434
|
|
|
|
440
|
|
Goodwill
|
|
|
93
|
|
|
|
73
|
|
Anticipated repatriation of foreign earnings
|
|
|
6
|
|
|
|
26
|
|
Cumulative translation adjustments
|
|
|
29
|
|
|
|
22
|
|
Development costs
|
|
|
16
|
|
|
|
|
|
Intangibles amortization (excluding goodwill)
|
|
|
242
|
|
|
|
|
|
Investment in projects
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
2,587
|
|
|
|
2,163
|
|
|
|
|
|
|
|
|
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Deferred compensation, pension, accrued vacation and other
reserves
|
|
|
195
|
|
|
|
126
|
|
Differences between book and tax basis of contracts
|
|
|
270
|
|
|
|
377
|
|
Non-depreciable property
|
|
|
19
|
|
|
|
19
|
|
Intangibles amortization (excluding goodwill)
|
|
|
|
|
|
|
164
|
|
Equity compensation
|
|
|
26
|
|
|
|
22
|
|
Claimants reserve
|
|
|
|
|
|
|
10
|
|
U.S. capital loss carryforwards
|
|
|
135
|
|
|
|
274
|
|
Foreign net operating loss carryforwards
|
|
|
78
|
|
|
|
66
|
|
State net operating loss carryforwards
|
|
|
28
|
|
|
|
28
|
|
Foreign capital loss carryforwards
|
|
|
1
|
|
|
|
1
|
|
Investments in projects
|
|
|
|
|
|
|
10
|
|
Deferred financing costs
|
|
|
7
|
|
|
|
10
|
|
Alternative minimum tax
|
|
|
40
|
|
|
|
20
|
|
Federal benefit on state FIN 48 liabilities
|
|
|
30
|
|
|
|
|
|
Other
|
|
|
11
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
Total deferred tax assets
|
|
|
840
|
|
|
|
1,131
|
|
Valuation allowance
|
|
|
(233
|
)
|
|
|
(359
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets
|
|
|
607
|
|
|
|
772
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
1,980
|
|
|
$
|
1,391
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes NRGs net deferred tax
position as of December 31, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
As of December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Current deferred tax liability
|
|
$
|
197
|
|
|
$
|
201
|
|
Non-current deferred tax liability
|
|
|
1,783
|
|
|
|
1,190
|
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
1,980
|
|
|
$
|
1,391
|
|
|
|
|
|
|
|
|
|
|
204
Tax
Receivable and Payable
As of December 31, 2009, NRG recorded a current tax payable
of approximately $32 million that represents a tax
liability due for domestic state taxes of approximately
$20 million, as well as foreign taxes payable of
approximately $12 million. In addition, NRG has a domestic
tax receivable of $153 million, of which $102 million
is federal cash grant receivable on Blythe Solar and Langford
plants.
Deferred
tax assets and valuation allowance
Net deferred tax balance As of
December 31, 2009, and 2008, NRG recorded a net deferred
tax liability of $1,747 million and $1,032 million,
respectively. However, due to an assessment of positive and
negative evidence, including projected capital gains and
available tax planning strategies, NRG believes that it is more
likely than not that a benefit will not be realized on
$233 million and $359 million of tax assets, thus a
valuation allowance has remained, resulting in a net deferred
tax liability of $1,980 million and $1,391 million as
of December 31, 2009 and 2008, respectively. NRG believes
it is more likely than not that future earnings will be
sufficient to utilize the Companys deferred tax assets,
net of the existing valuation allowances at December 31,
2009.
NOL carryforwards At December 31, 2009,
and 2008, the Company had cumulative state net operating losses,
or NOLs, of $28 million. These NOLs will expire starting
2010. In addition, as of December 31, 2009, NRG has
cumulative foreign NOL carryforwards of $280 million of
which $82 million will expire starting 2011 through 2017
and of which $198 million do not have an expiration date.
Valuation allowance As of December 31,
2009, the Companys valuation allowance was reduced by
$249 million as result of the expiration of unused capital
loss carryforwards. The valuation allowance was increased by
$123 million primarily for certain derivative contracts
that are eligible for capital loss treatment for tax purposes
resulting in a net reduction of $126 million.
Uncertain
tax benefits
NRG has identified unrecognized tax benefits whose after-tax
value was $643 million that if recognized, would impact the
Companys income tax expense.
As of December 31, 2009, and 2008, NRG has recorded a
non-current tax liability of $347 and $208 million,
respectively, for unrecognized tax benefits resulting from
taxable earnings for the period for which there are no NOLs
available to offset for financial statement purposes. The
Company recognizes interest and penalties related to
unrecognized tax benefits in income tax expense. During the
years ended December 31, 2009, and 2008, the Company
recognized approximately $9 million, and $8 million,
respectively, in interest and penalties. For the year ended
December 31, 2007, the Company incurred an immaterial
amount of interest and penalties related to its unrecognized tax
benefit. As of December 31, 2009, and 2008, NRG had accrued
interest and penalties related to these unrecognized tax
benefits of approximately $17 and $8 million, respectively.
Tax jurisdictions NRG is subject to
examination by taxing authorities for income tax returns filed
in the U.S. federal jurisdiction and various state and
foreign jurisdictions including major operations located in
Germany and Australia. The Company is no longer subject to
U.S. federal income tax examinations for years prior to
2002. With few exceptions, state and local income tax
examinations are no longer open for years before 2003. The
Companys significant foreign operations are also no longer
subject to examination by local jurisdictions for years prior to
2000.
The Company continues to be under examination by the Internal
Revenue Service, or IRS, for years 2004 through 2006. It is
possible that the IRS examination may conclude during 2010 but
because of a possible extension, an estimate of the range of
reasonably possible changes in unrecognized tax benefits cannot
be made.
Sale of ITISA On April 28, 2008, NRG
completed the sale of its 100% interest in Tosli Acquisition
B.V., or Tosli, which held all NRGs interest in ITISA, to
Brookfield Renewable Power Inc. (previously Brookfield Power
Inc.), a wholly-owned subsidiary of Brookfield Asset Management
Inc. In addition, the purchase price adjustment contingency
under the sale agreement was resolved on August 7, 2008. In
connection with the sale, NRG recorded a capital gain of
$218 million which further reduced the Companys
uncertain tax benefits.
205
The following table reconciles the total amounts of unrecognized
tax benefits at the beginning and end of the respective periods:
|
|
|
|
|
|
|
|
|
|
|
As of
|
|
|
As of
|
|
|
|
December 31,
|
|
|
December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
|
(In millions)
|
|
|
Balance as of January 1
|
|
$
|
527
|
|
|
$
|
683
|
|
Increase due to current year positions
|
|
|
80
|
|
|
|
18
|
|
Decrease due to current year positions
|
|
|
|
|
|
|
(183
|
)
|
Increase due to prior year positions
|
|
|
40
|
|
|
|
9
|
|
Decrease due to prior year positions
|
|
|
(4
|
)
|
|
|
|
|
Decrease due to settlements and payments
|
|
|
|
|
|
|
|
|
Decrease due to statute expirations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized tax benefits as of December 31
|
|
$
|
643
|
|
|
$
|
527
|
|
|
|
|
|
|
|
|
|
|
Included in the balance at December 31, 2009, are
$43 million of tax positions for which the ultimate
deductibility is highly certain but for which there is
uncertainty about the timing of such deductibility. Because of
the impact of deferred tax accounting, other than interest and
penalties, the disallowance of the shorter deductibility period
would not affect the annual effective tax rate but would
accelerate the payment of cash or use of net operating loss
carryforwards to an earlier period.
German
Tax Reform Act 2008
On July 6, 2007, the German government passed the Tax
Reform Act of 2008, which reduces the German statutory and
resulting effective tax rates on earnings from approximately 36%
to approximately 27% effective January 1, 2008. Due to this
reduction in the statutory and resulting effective tax rate in
2007, NRG recognized a $29 million tax benefit and as of
December 31, 2007, NRG had a German net deferred tax
liability of approximately $84 million which includes the
impact of this tax rate change.
|
|
Note 20
|
Stock-Based
Compensation
|
Long-Term
Incentive Plan, or LTIP
As of December 31, 2009, and 2008, a total of
16,000,000 shares of NRG common stock were authorized for
issuance under the LTIP, subject to adjustments in the event of
reorganization, recapitalization, stock split, reverse stock
split, stock dividend, and a combination of shares, merger or
similar change in NRGs structure or outstanding shares of
common stock. There were 5,129,593 and 6,798,074 shares of
common stock remaining available for grants under NRGs
LTIP as of December 31, 2009, and 2008, respectively.
Non-Qualified
Stock Options, or NQSOs
NQSOs granted under the LTIP typically have a three-year
graded vesting schedule beginning on the grant date and become
exercisable at the end of the requisite service period. NRG
recognizes compensation costs for NQSOs on a straight-line
basis over the requisite service period for the entire award.
The maximum contractual term is ten years for approximately
1.1 million of NRGs outstanding NQSOs, and six
years for the remaining 3.7 million NQSOs.
206
The following table summarizes the Companys NQSO activity
as of December 31, 2009, and changes during the year then
ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Remaining
|
|
|
Aggregate
|
|
|
|
|
|
|
Average
|
|
|
Contractual Term
|
|
|
Intrinsic Value
|
|
|
|
Shares
|
|
|
Exercise Price
|
|
|
(In years)
|
|
|
(In millions)
|
|
|
|
(In whole)
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2008
|
|
|
4,008,188
|
|
|
$
|
25.84
|
|
|
|
4
|
|
|
$
|
14
|
|
Granted
|
|
|
1,406,500
|
|
|
|
23.62
|
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(506,103
|
)
|
|
|
29.86
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(115,000
|
)
|
|
|
13.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
4,793,585
|
|
|
|
25.07
|
|
|
|
4
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at December 31, 2009
|
|
|
2,766,165
|
|
|
|
22.21
|
|
|
|
3
|
|
|
|
13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of options granted
during the years ended December 31, 2009, 2008 and 2007 was
$8.64, $10.33, and $8.28, respectively. The total intrinsic
value of options exercised during the years ended
December 31, 2009, 2008 and 2007 was $1.4 million,
$14 million and $11 million, respectively and cash
received from the exercise of these options was $2 million,
$9 million and $7 million, respectively.
The fair value of the Companys NQSOs is estimated on
the date of grant using the Black-Scholes option-pricing model.
Significant assumptions used in the fair value model for the
years ended December 31, 2009, 2008, and 2007 with respect
to the Companys NQSOs are summarized below:
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
Expected volatility
|
|
44.36%-48.29%
|
|
26.75%-44.00%
|
|
25.88%-27.28%
|
Expected term (in years)
|
|
4
|
|
4
|
|
4
|
Risk free rate
|
|
1.43%-1.93%
|
|
1.33%-3.09%
|
|
4.58%-4.68%
|
For 2009, 2008, and 2007, expected volatility is calculated
based on NRGs historical stock price volatility data over
the period commensurate with the expected term of the stock
option. Typically, the expected term for the Companys
NQSOs is based on the simple average of the contractual
term and vesting term. The Company uses this simplified method
as it does not have sufficient historical exercise data to
provide a reasonable basis upon which to estimate the expected
term.
Restricted
Stock Units, or RSUs
Typically, RSUs granted under the Companys LTIP
fully vest three years from the date of issuance. Fair value of
the RSUs is based on the closing price of NRG common stock
on the date of grant. The following table summarizes the
Companys non-vested RSU awards as of December 31,
2009, and changes during the year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
Grant-Date Fair
|
|
|
|
Units
|
|
|
Value per Unit
|
|
|
|
(In whole)
|
|
|
Non-vested at December 31, 2008
|
|
|
1,061,996
|
|
|
$
|
32.97
|
|
Granted
|
|
|
1,021,800
|
|
|
|
26.13
|
|
Forfeited
|
|
|
(119,955
|
)
|
|
|
31.79
|
|
Vested
|
|
|
(349,072
|
)
|
|
|
23.50
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2009
|
|
|
1,614,769
|
|
|
|
30.78
|
|
|
|
|
|
|
|
|
|
|
The total fair value of RSUs vested during the years ended
December 31, 2009, 2008, and 2007, was $8 million,
$22 million and $40 million, respectively. The
weighted average grant date fair value of RSUs granted
during the years ended December 31, 2009, 2008 and 2007 was
$26.13, $39.84 and $38.61, respectively.
207
Deferred
Stock Units, or DSUs
DSUs represent the right of a participant to be paid one
share of NRG common stock at the end of a deferral period
established under the terms of the award. DSUs granted
under the Companys LTIP are fully vested at the date of
issuance. Fair value of the DSUs, which is based on the
closing price of NRG common stock on the date of grant, is
recorded as compensation expense in the period of grant.
The following table summarizes the Companys outstanding
DSU awards as of December 31, 2009, and changes during the
year then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
Grant-Date Fair
|
|
|
Units
|
|
Value per Unit
|
|
|
(In whole)
|
|
Outstanding at December 31, 2008
|
|
|
260,768
|
|
|
$
|
18.50
|
|
Granted
|
|
|
65,437
|
|
|
|
22.77
|
|
Conversions
|
|
|
(22,156
|
)
|
|
|
23.69
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2009
|
|
|
304,049
|
|
|
|
19.34
|
|
|
|
|
|
|
|
|
|
|
The aggregate intrinsic values for DSUs outstanding as of
December 31, 2009, 2008, and 2007 were approximately
$7 million, $6 million, and $12 million
respectively. The aggregate intrinsic values for DSUs
converted to common stock for the years ended December 31,
2009, 2008 and 2007 were $0.5 million, $1.5 million
and $1.2 million, respectively. The weighted average grant
date fair value of DSUs granted during the years ended
December 31, 2009, 2008 and 2007 was $22.77, $35.12 and
$44.43, respectively.
Performance
Units, or PUs
PUs granted under the Companys LTIP fully vest three
years from the date of issuance. PUs granted prior to
January 1, 2009, are paid out upon vesting if the closing
price of NRGs common stock on the vesting date, or the
Measurement Price, is equal to or greater than the Target Price.
PUs granted after January 1, 2009, are paid out upon
vesting if the Measurement Price is equal to or greater than
Threshold Price. The Threshold Price, Target Price and Maximum
Price are determined on the date of issuance. The payout for
each PU will be equal to: (i) a pro-rata amount between 0.5
and 1 share of common stock, if the Measurement Price is
equal to or greater than the target Threshold Price but less
than the Target Price, for grants made after January 1,
2009; (ii) one share of common stock, if the Measurement
Price equals the Target Price; (iii) a pro-rata amount
between one and two shares of common stock, if the Measurement
Price is greater than the Target Price but less than the Maximum
Price; and (iv) two shares of common stock, if the
Measurement Price is equal to, or greater than, the Maximum
Price.
The following table summarizes the Companys non-vested PU
awards as of December 31, 2009, and changes during the year
then ended:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Outstanding
|
|
Grant-Date Fair
|
|
|
Units
|
|
Value per Unit
|
|
|
(In whole except weighted average data)
|
|
Non-vested at December 31, 2008
|
|
|
659,564
|
|
|
$
|
22.81
|
|
Granted
|
|
|
339,300
|
|
|
|
22.91
|
|
Forfeited
|
|
|
(381,564
|
)
|
|
|
20.86
|
|
|
|
|
|
|
|
|
|
|
Non-vested at December 31, 2009
|
|
|
617,300
|
|
|
|
24.27
|
|
|
|
|
|
|
|
|
|
|
The weighted average grant date fair value of PUs granted
during the years ended December 31, 2009, 2008 and 2007 was
$22.91, $26.99 and $22.43, respectively.
208
The fair value of PUs is estimated on the date of grant
using a Monte Carlo simulation model and expensed over the
service period, which equals the vesting period. Significant
assumptions used in the fair value model for the years ended
December 31, 2009, 2008 and 2007 with respect to the
Companys PUs are summarized below:
|
|
|
|
|
|
|
|
|
2009
|
|
2008
|
|
2007
|
|
Expected volatility
|
|
48.48%-53.00%
|
|
27.81%-48.06%
|
|
25.91%-27.28%
|
Expected term (in years)
|
|
3
|
|
3
|
|
3
|
Risk free rate
|
|
1.14%-1.48%
|
|
1.13%-2.89%
|
|
4.54%-4.69%
|
For 2009, 2008, and 2007, expected volatility is calculated
based on NRGs historical stock price volatility data over
the period commensurate with the expected term of the PU, which
equals the vesting period.
Supplemental
Information
The following table summarizes NRGs total compensation
expense recognized in accordance with ASC 718 for the years
ended December 31, 2009, 2008, and 2007 for each of the
four types of awards issued under the Companys LTIP, as
well as total non-vested compensation costs not yet recognized
and the period over which this expense is expected to be
recognized as of December 31, 2009. Minimum tax
withholdings of $3 million, $10 million, and
$17 million paid by the Company during 2009, 2008, and
2007, respectively, are reflected as a reduction to Additional
Paid-in Capital on the Companys statement of financial
position, and are reflected as operating activities on the
Companys statement of cash flows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested Compensation Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognition Period
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrecognized
|
|
|
Remaining
|
|
|
|
Compensation Expense
|
|
|
Total Cost
|
|
|
(In years)
|
|
|
|
Year Ended December 31
|
|
|
As of December 31
|
|
Award
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2009
|
|
|
2009
|
|
|
|
(In millions, except weighted average data)
|
|
|
NQSOs
|
|
$
|
9
|
|
|
$
|
8
|
|
|
$
|
5
|
|
|
$
|
10
|
|
|
|
2.2
|
|
RSUs
|
|
|
11
|
|
|
|
12
|
|
|
|
10
|
|
|
|
31
|
|
|
|
1.8
|
|
DSUs
|
|
|
1
|
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
PUs
|
|
|
5
|
|
|
|
5
|
|
|
|
3
|
|
|
|
6
|
|
|
|
1.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
26
|
|
|
$
|
26
|
|
|
$
|
19
|
|
|
$
|
47
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tax benefit recognized
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Compensation Arrangements
Beginning in 2008, NRG also sponsored certain cash-settled
equity award programs, under which employees are eligible to
receive future cash compensation upon fulfillment of the vesting
criteria for the particular program. The aggregate compensation
expense for these arrangements was approximately $2 million
and $1 million for the years ended December 31, 2009,
and 2008, respectively.
209
|
|
Note 21
|
Related
Party Transactions
|
The following table summarizes NRGs material related party
transactions with affiliates that are included in the
Companys operating revenues, operating costs and other
income and expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Revenues from Related Parties Included in Operating
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG(a)
|
|
$
|
2
|
|
|
$
|
4
|
|
|
$
|
4
|
|
Gladstone
|
|
|
2
|
|
|
|
2
|
|
|
|
1
|
|
GenConn
|
|
|
7
|
|
|
|
1
|
|
|
|
|
|
Sherbino
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
11
|
|
|
$
|
8
|
|
|
$
|
5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses from Related Parties Included in Cost of
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
MIBRAG(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of purchased coal
|
|
$
|
43
|
|
|
$
|
57
|
|
|
$
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income from Related Parties Included in Other Income
and Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
GenConn(b)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
Kraftwerke Schkopau GBR
|
|
|
4
|
|
|
|
4
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
6
|
|
|
$
|
4
|
|
|
$
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
The period in 2009 is from
January 1, 2009 to June 10, 2009.
|
|
(b)
|
|
For the period Apri1 1, 2009 to
June 10, 2009.
|
Gladstone - NRG provides services to Gladstone, an equity
method investment, under an operation and maintenance, or
O&M, agreement Fees for services under this contract
primarily include recovery of NRGs costs of operating the
plant as approved in the annual budget, as well as a base
monthly fee.
GenConn and Sherbino - Under construction
management, or CMA, agreements with GenConn and Sherbino, NRG
has received fees for management, design and construction
services. The construction at Sherbino was completed during
2008. In addition, NRG entered into a loan agreement with
GenConn during 2009, pursuant to which it receives interest
income. See further discussion in Note 16, Investments
Accounted for by the Equity Method.
MIBRAG - Prior to NRGs sale of its 50%
ownership in MIBRAG on June 10, 2009, NRG rendered
technical consulting services to MIBRAG under a consulting
agreement and had entered into long-term coal purchase
agreements with MIBRAG to supply coal to Schkopau. See further
discussion in Note 4, Discontinued Operations and
Dispositions.
Kraftwerke Schkopau GBR - A subsidiary of NRG, Saale
Energie GmbH has entered into a loan agreement with Kraftwerke
Schkopau GBR, a partnership between Saale and E.ON Kraftwerke
GmbH, pursuant to which NRG receives interest income. See
further discussion in Note 9, Capital Leases and Notes
Receivable.
|
|
Note 22
|
Commitments
and Contingencies
|
Operating
Lease Commitments
NRG leases certain Company facilities and equipment under
operating leases, some of which include escalation clauses,
expiring on various dates through 2040. NRG also has certain
tolling arrangements to purchase power which qualifies as
operating leases. Certain operating lease agreements over their
lease term include provisions such as scheduled rent increases,
leasehold incentives, and rent concessions. The Company
recognizes the effects of these scheduled rent increases,
leasehold incentives, and rent concessions on a straight-line
basis over the lease term unless another systematic and rational
allocation basis is more representative of the time pattern in
which the leased property is physically employed. Lease expense
under operating leases was approximately $102 million,
$54 million, and $40 million for the years ended
December 31, 2009, 2008, and 2007, respectively.
210
Future minimum lease commitments under operating leases for the
years ending after December 31, 2009 are as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2010
|
|
$
|
100
|
|
2011
|
|
|
66
|
|
2012
|
|
|
54
|
|
2013
|
|
|
50
|
|
2014
|
|
|
48
|
|
Thereafter
|
|
|
264
|
|
|
|
|
|
|
Total
|
|
$
|
582
|
|
|
|
|
|
|
Coal,
Gas and Transportation Commitments
NRG has entered into long-term contractual arrangements to
procure fuel and transportation services for the Companys
generation assets and for the years ended December 31,
2009, 2008, and 2007, the Company purchased approximately
$1.4 billion, $2.0 billion, and $1.7 billion,
respectively, under such arrangements.
As of December 31, 2009, the Companys commitments
under such outstanding agreements are estimated as follows:
|
|
|
|
|
Period
|
|
(In millions)
|
|
|
2010
|
|
$
|
1,011
|
|
2011
|
|
|
225
|
|
2012
|
|
|
180
|
|
2013
|
|
|
65
|
|
2014
|
|
|
75
|
|
Thereafter
|
|
|
600
|
|
|
|
|
|
|
Total(a)
|
|
$
|
2,156
|
|
|
|
|
|
|
|
|
|
(a)
|
|
Includes those coal transportation
and lignite commitments for 2010 as no other nominations were
made as of December 31, 2009. Natural gas nomination is
through February 2011.
|
Purchased
Power Commitment
NRG has purchased power contracts of various quantities and
durations that are not classified as derivative assets and
liabilities and do not qualify as operating leases. These
contracts are not included in the consolidated balance sheet as
of December 31, 2009. Minimum purchase commitment
obligations under these agreements are as follows as of
December 31, 2009:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Variable
|
|
Period
|
|
Fixed Pricing
(a)
|
|
|
Pricing
(b)
|
|
|
|
(In millions)
|
|
|
2010
|
|
$
|
53
|
|
|
$
|
2
|
|
2011
|
|
|
30
|
|
|
|
4
|
|
2012
|
|
|
21
|
|
|
|
1
|
|
2013
|
|
|
10
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total(a)
|
|
$
|
114
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
As of December 31, 2010, 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 December 31, 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.
211
Lignite
Contract with Texas Westmoreland Coal Co.
The lignite used to fuel the Texas regions Limestone
facility is obtained from a surface mine, or the Jewett mine,
adjacent to the Limestone facility under a long-term contract
with Texas Westmoreland Coal Co., or TWCC. The contract is based
on a cost-plus arrangement with incentives and penalties to
ensure proper management of the mine. NRG has the flexibility to
increase or decrease lignite purchases from the mine within
certain ranges, including the ability to suspend or terminate
lignite purchases with adequate notice. The mining period was
extended through 2018 with an option to extend the mining period
by two five-year intervals.
TWCC is responsible for performing ongoing reclamation
activities at the mine until all lignite reserves have been
produced. When production is completed at the mine, NRG will be
responsible for final mine reclamation obligations. The Railroad
Commission of Texas has imposed a bond obligation of
approximately $83 million on TWCC for the reclamation of
this lignite mine. Pursuant to the contract with TWCC, an
affiliate of CenterPoint Energy, Inc. has guaranteed
$107 million of this obligation and approximately
$32 million of such amount is supported by letters of
credit posted by NRG. Under the terms of the cost plus agreement
with TWCC, NRG is required to maintain a corporate guarantee of
TWCCs bond obligation in the amount of $50 million
when CenterPoint Energy, Inc.s obligation lapses in April
2010, or pay the costs of obtaining replacement performance
assurance. Additionally, NRG is required to provide additional
performance assurance over TWCCs current bond obligations
if required by the Commission. On January 14, 2010, NRG
made a filing with the Railroad Commission of Texas to provide a
corporate guaranty and indemnity in the amount of
$50 million in support of TWCCs bond obligation.
NRGs corporate guaranty and indemnity will become
effective on April 14, 2010, upon acceptance by the Texas
Railroad Commission.
First
and Second Lien Structure
NRG has granted first and second liens to certain counterparties
on substantially all of the Companys assets. NRG uses the
first or second lien structure to reduce the amount of cash
collateral and letters of credit that it would otherwise be
required to post from time to time to support its obligations
under
out-of-the-money
hedge agreements for forward sales of power or MWh equivalents.
To the extent that the underlying hedge positions for a
counterparty are
in-the-money
to NRG, the counterparty would have no claim under the lien
program. The lien program limits the volumes that can be hedged,
not the value of underlying
out-of-the
money positions. The first lien program does not require NRG to
post collateral above any threshold amount of exposure. Within
the first and second lien structure, the Company can hedge up to
80% of its baseload capacity and 10% of its non-baseload assets
with these counterparties for the first 60 months and then
declining thereafter. Net exposure to a counterparty on all
trades must be positively correlated to the price of the
relevant commodity for the first lien to be available to that
counterparty. The first and second lien structure is not subject
to unwind or termination upon a ratings downgrade of a
counterparty and has no stated maturity date.
NRGs lien counterparties may have a claim on the
Companys assets to the extent market prices exceed the
hedged price. As of December 31, 2009, and February 9,
2010, all hedges under the first and second liens were
in-the-money
on a counterparty aggregate basis.
RepoweringNRG
Initiatives
NRG has capitalized $33 million through December 31,
2009, for the repowering of its El Segundo generating facility
in California. Air permitting litigation unrelated to the El
Segundo project has delayed receipt of certain required permits
and prevented, the El Segundo project from meeting its original
completion date of June 1, 2011. The Company is working
with the counterparty to consider certain PPA modifications
including the commercial operations date currently expected to
be the summer of 2013.
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 ASC 450 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
212
addition legal costs are expensed as incurred. Management has
assessed each of the following matters based on current
information and made a judgment concerning its potential
outcome, considering the nature of the claim, the amount and
nature of damages sought, and the probability of success. Unless
specified below, the Company is unable to predict the outcome of
these legal proceedings or reasonably estimate the scope or
amount of any associated costs and potential liabilities. As
additional information becomes available, management adjusts its
assessment and estimates of such contingencies accordingly.
Because litigation is subject to inherent uncertainties and
unfavorable rulings or developments, it is possible that the
ultimate resolution of the Companys liabilities and
contingencies could be at amounts that are different from its
currently recorded reserves and that such difference could be
material.
In addition to the legal proceedings noted below, NRG and its
subsidiaries are party to other litigation or legal proceedings
arising in the ordinary course of business. In managements
opinion, the disposition of these ordinary course matters will
not materially adversely affect NRGs consolidated
financial position, results of operations, or cash flows.
California
Department of Water Resources
This matter concerns, among other contracts and other
defendants, the 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 or FERC abrogate
the CDWR contract and sought refunds associated with revenues
collected under the contract. In 2003, the FERC rejected this
complaint, denied rehearing, and the case was appealed to the
U.S. Court of Appeals for the Ninth Circuit where oral
argument was held on December 8, 2004. On December 19,
2006, the Ninth Circuit decided that in the FERCs review
of the contracts at issue, the FERC could not rely on the
Mobile-Sierra standard presumption of just and reasonable
rates, where such contracts were not reviewed by the FERC with
full knowledge of the then existing market conditions. WCP and
others sought review by the U.S. Supreme Court. WCPs
appeal was not selected, but instead held by the Supreme Court.
In the appeal that was selected by the Supreme Court, on
June 26, 2008 the Supreme Court ruled: (i) that the
Mobile-Sierra public interest standard of review applied
to contracts made under a sellers market-based rate
authority; (ii) that the public interest bar
required to set aside a contract remains a very high one to
overcome; and (iii) that the Mobile-Sierra
presumption of contract reasonableness applies when a
contract is formed during a period of market dysfunction unless
(a) such market conditions were caused by the illegal
actions of one of the parties or (b) the contract
negotiations were tainted by fraud or duress. In this related
case, the U.S. Supreme Court affirmed the Ninth
Circuits decision agreeing that the case should be
remanded to the FERC to clarify the FERCs 2003 reasoning
regarding its rejection of the original complaint relating to
the financial burdens under the contracts at issue and to
alleged market manipulation at the time these contracts were
formed. As a result, the U.S. Supreme Court then reversed
and remanded the WCP CDWR case to the Ninth Circuit for
treatment consistent with its June 26, 2008 decision in the
related case. On October 20, 2008, the Ninth Circuit asked
the parties in the remanded CDWR case, including WCP and the
FERC, whether that Court should answer a question the
U.S. Supreme Court did not address in its June 26,
2008, decision; whether the Mobile-Sierra doctrine
applies to a third-party that was not a signatory to any of the
wholesale power contracts, including the CDWR contract, at issue
in that case. Without answering that reserved question, on
December 4, 2008, the Ninth Circuit vacated its prior
opinion and remanded the WCP CDWR case back to the FERC for
proceedings consistent with the U.S. Supreme Courts
June 26, 2008 decision. On December 15, 2008, WCP and
the other seller-defendants filed with the FERC a Motion for
Order Governing Proceedings on Remand. On January 14, 2009,
the Public Utilities Commission of the State of California filed
an Answer and Cross Motion for an Order Governing Procedures on
Remand, and on January 28, 2009, WCP and the other
seller-defendants filed their reply.
At this time, while NRG cannot predict with certainty whether
WCP will be required to make refunds for rates collected under
the CDWR contract or estimate the range of any such possible
refunds, a reconsideration of the CDWR contract by the FERC with
a resulting order mandating significant refunds could have a
material adverse impact on NRGs financial position,
statement of operations, and statement of cash flows. As part of
the 2006 acquisition of Dynegys 50% ownership interest in
WCP, WCP and NRG assumed responsibility for any risk of loss
213
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.
On January 14, 2010, the U.S. Supreme Court issued its
decision in an unrelated proceeding involving the
Mobile-Sierra doctrine that will affect the standard of
review applied to the CDWR contract on remand before the FERC.
In NRG Power Marketing v. Maine Public Utilities
Commission, the Supreme Court held that the Mobile-Sierra
presumption regarding the reasonableness of contract rates
does not depend on the identity of the complainant who seeks a
FERC investigation/refund. The Supreme Court proceeding arose
following an appeal by the Attorneys General of the State of
Connecticut and of the Commonwealth of Massachusetts regarding
the settlement establishing the New England Forward Capacity
Market. The settlement, filed with the FERC on March 7,
2006, provides for interim capacity transition payments for all
generators in New England for the period from December 1,
2006 through May 31, 2010 and for the Forward Capacity
Market auction rates thereafter. The Court of Appeals for the DC
Circuit, or DC Circuit, had rejected all substantive challenges
to the settlement, but had sustained one procedural argument
relating to the applicability of the Mobile-Sierra
doctrine to third parties. The Supreme Court reversed the DC
Circuit on this point, and remanded the case for further
consideration of whether the transition payments and auction
rates qualify as contract rates.
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. It filed an objection in the Cajun Electric Cooperative
Power, Inc.s bankruptcy proceeding in the
U.S. Bankruptcy Court for the Middle District of Louisiana
to seek to prevent the bankruptcy from closing. It also filed a
complaint in the same bankruptcy proceeding in the same court
seeking a judgment that: (i) it did not assume liability
from Cajun Electric for any claims or other liabilities under
environmental laws with respect to Big Cajun II that arose,
or are based on activities that were undertaken, prior to the
closing date of the acquisition; (ii) it is not otherwise
the successor to Cajun Electric; and (iii) Cajun Electric
and/or the
Bankruptcy Trustee are exclusively liable for the violations
alleged in the February 11, 2009, lawsuit to the extent
that such claims are determined to have merit. On 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. On August 24,
2009, Louisiana Generating, LLC filed a motion to dismiss this
lawsuit, and on September 25, 2009, the Department of
Justice filed its opposition to the motion to dismiss. A new
federal bankruptcy judge was appointed on October 9, 2009.
214
On February 18, 2010, the LDEQ filed a motion to intervene
in the above lawsuit and a complaint against Louisiana
Generating LLC for alleged violations of Louisianas PSD
regulations and Louisianas Title V operating permit
program. LDEQ seeks similar relief to that requested by the
Department of Justice. Specifically, LDEQ seeks injunctive
relief to: (1) preclude the operation of Units 1 and 2 except in
accordance with the CAA; (2) order the installation of BACT on
Units 1 and 2 for each pollutant subject to regulation under the
CAA; (3) obtain all necessary permits for Units 1 and 2 pursuant
to the requirements of PSD and the Louisiana Title V operating
permits program; (4) conduct audits to determine if any
additional modifications have occurred which would require it to
meet the requirements of PSD and report the results of the audit
to the LDEQ and EPA; (5) order the surrender of emission
allowances or credits; (6) take other appropriate actions to
remedy, mitigate and offset the harm to public health and the
environment caused by violations of the CAA; (7) assess civil
penalties; and (8) award to the LDEQ its costs in prosecuting
the litigation. On February 19, 2010, the district court
granted LDEQs motion to intervene.
Nuclear
Innovation North America, LLC
On December 6, 2009, CPS commenced a lawsuit against two
NINA entities asking the court to declare the rights,
obligations, and remedies of the parties pursuant to the 1997
and 2007 agreements between the parties should CPS unilaterally
withdraw from the proposed STP Units 3 and 4 Project. On
December 23, 2009, CPS amended its original December 6
complaint adding NRG, Toshiba Corporation, and NINA LLC as
defendants and not only continued to request that the Court
declare the rights, obligations, and remedies of the parties
under the two operative governing agreements, but also sought
$32 billion in damages. CPS amended its complaint again on
December 28, 2009.
On January 6, 2010, CPS amended its complaint for the third
time. In addition to requesting immediate injunctive relief, the
amended complaint alleges that NRG, Toshiba, and NINA have been
involved in a conspiracy to defraud CPS, that they purposefully
misled CPS in inducing it to be a partner in the STP Units 3 and
4 Project, that they maliciously interfered with CPS contracts
and business relationships, and that they willfully disparaged
CPS. It sought declarations that: (i) owner consensus is
required for all development decisions; (ii) there is a
right to voluntary withdrawal, after which no further
obligations accrue but undiluted ownership continues;
(iii) both the partition waiver and forfeiture provisions
are unenforceable against CPS under Texas law if they did apply;
and (iv) CPS is not currently in breach. In addition, CPS
sought relief among the following alternatives: partition by
sale; an order forcing NRG and NINA to buy CPS undiluted
share at an independent valuation; an order requiring NRG to
compensate CPS $350 million investment and fair value for
the site; an order granting CPS twelve months following
withdrawal to sell its stake in the project; or an order that no
further development take place without consensus of all project
owners. This case was removed and remanded to and from federal
court on three separate occasions. On January 19, 2010, CPS
dismissed Toshiba from the lawsuit.
The parties agreed to a January 25, 2010, phased trial
wherein all other claims would be reserved for an undetermined
future phase II date and a trial would go forward in phase
I only on CPS request for declaratory relief to determine
the respective rights, obligations, and remedies of the parties
under the two operative governing agreements should CPS withdraw
from the STP Units 3 and 4 Project. On January 25, 2010,
the parties argued the NINA entities and NRGs Motion for
Summary Judgment which was denied on January 26, 2010.
After a
two-day
trial, the court issued its ruling on January 29, 2010,
making a number of findings. It ruled that as of
January 29, 2010, CPS and NINA were each 50% equity owners
as tenants in common under Texas law in the STP Units 3 and 4
Project. The court found that while a withdrawing party does not
forfeit its 50% interest upon a withdrawal, the governing
agreements are silent as to whether that withdrawing party can
recoup its sunk costs upon withdrawal. Finally, the court noted
that for CPS to remain a 50% equity owner, it must pay all
appropriate costs. Failure to do so, the court determined, would
result in a complete loss of CPS equity share. On
February 17, 2010, an agreement in principle was reached
with CPS for NINA to acquire a controlling interest in the STP
Units 3 and 4 Project through a settlement of all pending
litigation between the parties. As part of that agreement, all
litigation would be dismissed with prejudice, including all
phase II claims, thereby ending this matter. The parties
continue to negotiate terms regarding final documentation of the
agreement in principle.
215
Dunkirk
Construction Litigation
In 2005, NRG entered into a Consent Decree with the New York
State Department of Environmental Conservation whereby it agreed
to reduce certain emissions generated by its Huntley and Dunkirk
power plants. Pursuant to the Consent Decree, on
November 21, 2007, Clyde Bergemann EEC, or CBEEC, and NRG
entered into a firm fixed price contract for the supply of
equipment, material and services for six fabric filters for
NRGs Dunkirk Electric Power Generating Station. Subsequent
to contracting with NRG, CBEEC subcontracted with Hohl
Industrial Services, Inc., or Hohl, to perform steel erection
and equipment installation at Dunkirk.
On August 28, 2009, Hohl filed its original complaint
against NRG, its subsidiary Dunkirk Power LLC, or Dunkirk Power,
and CBEEC among others for claims of breach of contract, quantum
meruit, unjust enrichment and foreclosure of mechanics
liens. As part of CBEECs contractual obligation to NRG,
CBEEC agreed to defend, under a reservation of rights,
NRGs interest in this lawsuit. CBEEC filed an answer to
the above complaint on behalf of itself, NRG and Dunkirk Power
on October 5, 2009. On December 16, 2009, CBEEC filed
a Motion for Summary Judgment on behalf of itself, NRG, and
Dunkirk Power, which has yet to be decided.
On February 1, 2010, NRG and Dunkirk Power filed a Motion
for Leave to file an Amended Answer with Cross-Claims against
CBEEC. NRG asserted breach of contract claims seeking liquidated
damages for the delays caused by CBEEC. NRG also retained its
own counsel to represent its interest in the cross-claims and
reserved its rights to seek reimbursement from CBEEC. On
February 17, 2010, CBEEC filed an Amended Answer with
Affirmative Defenses, Counterclaims and Cross-Claims against
NRG. CBEEC is seeking approximately $30 million alleging
breach of contract, quantum meruit, unjust enrichment, and
foreclosure of two mechanics liens, as a result of alleged
delays caused by NRG and Dunkirk Power. A court ordered hearing
and settlement conference is scheduled for February 23,
2010.
Excess
Mitigation Credits
From January 2002 to April 2005, CenterPoint Energy applied
excess mitigation credits, or EMCs, to its monthly charges to
retail electric providers as ordered by the PUCT. The PUCT
imposed these credits to facilitate the transition to
competition in Texas, which had the effect of lowering the
retail electric providers monthly charges payable to
CenterPoint Energy. As indicated in its Petition for Review
filed with the Supreme Court of Texas on June 2, 2008,
CenterPoint Energy has claimed that the portion of those EMCs
credited to Reliant Energy Retail Services, LLC, or RERS, a
retail electric provider and NRG subsidiary acquired from RRI,
totaled $385 million for RERSs Price to
Beat Customers. It is unclear what the actual number may
be. Price to Beat was the rate RERS was required by
state law to charge residential and small commercial customers
that were transitioned to RERS from the incumbent integrated
utility company commencing in 2002. In its original stranded
cost case brought before the PUCT on March 31, 2004,
CenterPoint Energy sought recovery of all EMCs that were
credited to all retail electric providers, including RERS, and
the PUCT ordered that relief in its Order on Rehearing in Docket
No. 29526, on December 17, 2004. After an appeal to
state district court, the court entered a final judgment on
August 26, 2005, affirming the PUCTs order with
regard to EMCs credited to RERS. Various parties filed appeals
of that judgment with the Court of Appeals for the Third
District of Texas with the first such appeal filed on the same
date as the state district court judgment and the last such
appeal filed on October 10, 2005. On April 17, 2008,
the Court of Appeals for the Third District reversed the lower
courts decision ruling that CenterPoint Energys
stranded cost recovery should exclude only EMCs credited to RERS
for its Price to Beat customers. On June 2,
2008, CenterPoint Energy filed a Petition for Review with the
Supreme Court of Texas and on June 19, 2009, the Court
agreed to consider the CenterPoint Energy appeal as well as two
related petitions for review filed by other entities. Oral
argument occurred on October 6, 2009.
In November 2008, CenterPoint Energy and 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.
216
|
|
Note 23
|
Regulatory
Matters
|
NRG operates in a highly regulated industry and is subject to
regulation by various federal and state agencies. As such, NRG
is affected by regulatory developments at both the federal and
state levels and in the regions in which NRG operates. In
addition, NRG is subject to the market rules, procedures and
protocols of the various ISO markets in which NRG participates.
These power markets are subject to ongoing legislative and
regulatory changes that may impact NRGs wholesale and
retail businesses.
In addition to the regulatory proceedings noted below, NRG and
its subsidiaries are a party to other regulatory proceedings
arising in the ordinary course of business or have other
regulatory exposure. In managements opinion, the
disposition of these ordinary course matters will not materially
adversely affect NRGs consolidated financial position,
results of operations, or cash flows.
PJM On June 18, 2009, FERC denied
rehearing of its order dated September 19, 2008, dismissing
a complaint filed by the Maryland Public Service Commission, or
MDPSC, together with other load interests, against PJM
challenging the results of the RPM transition Base Residual
Auctions for installed capacity, held between April 2007 and
January 2008. The complaint had sought to replace the
auction-determined results for installed capacity for the
2008/2009, 2009/2010, and 2010/2011 delivery years with
administratively-determined prices. On August 14, 2009, the
MDPSC and the New Jersey Board of Public Utilities filed an
appeal of FERCs orders to the U.S. Court of Appeals
for the Fourth Circuit, and a successful appeal could disrupt
the auction-determined results and create a refund obligation
for market participants. The case has been transferred to the
U.S. Court of Appeals for the DC Circuit.
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.
|
|
Note 24
|
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 GHG
including
CO2
from power plants, are under consideration at the federal and
state levels. In general, the effect of such future laws or
regulations is expected to require the addition of pollution
control equipment or the imposition of restrictions or
additional costs on the Companys operations.
217
Environmental
Capital Expenditures
Based on current rules, technology and plans, NRG has estimated
that environmental capital expenditures from 2010 through 2014
to meet NRGs environmental commitments will be
approximately $0.9 billion and are primarily associated
with controls on the Companys Big Cajun and Indian River
facilities. These capital expenditures, in general, are related
to installation of particulate,
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 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.
Northeast
Region
In January 2006, NRGs Indian River Operations, Inc.
received a letter of informal notification from the DNREC
stating that it may be a potentially responsible party with
respect to Burton Island Old Ash Landfill, a historic captive
landfill located at the Indian River facility. On
October 1, 2007, NRG signed an agreement with the DNREC to
investigate the site through the Voluntary
Clean-up
Program. On February 4, 2008, the DNREC issued findings
that no further action is required in relation to surface water
and that a previously planned shoreline stabilization project
would adequately address shore line erosion. The landfill itself
will require a further Remedial Investigation and Feasibility
Study to determine the type and scope of any additional work
required. Until the Remedial Investigation and Feasibility Study
are completed, the Company is unable to predict the impact of
any required remediation.
On May 29, 2008, the DNREC 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 Item 3
Legal Proceedings, United States of
America v. Louisiana Generating, LLC.
|
|
Note 25
|
Cash
Flow Information
|
Detail of supplemental disclosures of cash flow and non-cash
investing and financing information was:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
(In millions)
|
|
|
Interest paid, net of amount
capitalized(a)
|
|
$
|
587
|
|
|
$
|
563
|
|
|
$
|
598
|
|
Income taxes
paid(b)
|
|
|
47
|
|
|
|
46
|
|
|
|
22
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
(Reduction)/addition to fixed assets due to asset retirement
obligations
|
|
|
(1
|
)
|
|
|
(39
|
)
|
|
|
7
|
|
Additions to fixed assets for accrued capital expenditures
|
|
|
44
|
|
|
|
116
|
|
|
|
|
|
Decrease to fixed assets for accrued grants and related tax
impact
|
|
|
(132
|
)
|
|
|
|
|
|
|
|
|
Decrease to 4.0% preferred stock from conversion to common stock
|
|
|
257
|
|
|
|
|
|
|
|
|
|
Decrease to 5.75% preferred stock from conversion to common stock
|
|
|
447
|
|
|
|
39
|
|
|
|
|
|
Decrease to treasury stock from the net impact of shares loaned
to and returned by affiliates of CS
|
|
|
160
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
2008 interest paid includes
$45 million payment to settle the CSF I CAGR.
|
(b)
|
|
2009, 2008 and 2007 income taxes
paid is net of $3, $2 and $6 million, respectively, of
income tax refunds received.
|
218
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. The Company is also obligated with respect to
customer deposits associated with Reliant Energy. In some cases,
NRGs maximum potential liability cannot be estimated,
since the underlying agreements contain no limits on potential
liability. In accordance with ASC 460, NRG has estimated that
the current fair value for issuing these guarantees was
approximately $8.0 million as of December 31, 2009,
and the liability in this amount is included in the
Companys non-current liabilities.
The following table summarizes NRGs estimated guarantees,
indemnity, and other contingent liability obligations by
maturity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
By Remaining Maturity at December 31,
|
|
|
|
2009
|
|
|
|
|
|
|
Under
|
|
|
|
|
|
|
|
|
Over
|
|
|
|
|
|
2008
|
|
Guarantees
|
|
1 Year
|
|
|
1-3 Years
|
|
|
3-5 Years
|
|
|
5 Years
|
|
|
Total
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Synthetic letters of credit
|
|
$
|
531
|
|
|
$
|
186
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
717
|
|
|
$
|
440
|
|
Unfunded letters of credit and surety bonds
|
|
|
61
|
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
97
|
|
|
|
5
|
|
Asset sales guarantee obligations
|
|
|
|
|
|
|
118
|
|
|
|
|
|
|
|
8
|
|
|
|
126
|
|
|
|
129
|
|
Commercial sales arrangements
|
|
|
104
|
|
|
|
44
|
|
|
|
103
|
|
|
|
965
|
|
|
|
1,216
|
|
|
|
1,005
|
|
Other guarantees
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
117
|
|
|
|
117
|
|
|
|
80
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total guarantees
|
|
$
|
696
|
|
|
$
|
384
|
|
|
$
|
103
|
|
|
$
|
1,090
|
|
|
$
|
2,273
|
|
|
$
|
1,659
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Letters of credit and surety bonds As of
December 31, 2009, NRG and its consolidated subsidiaries
were contingently obligated for a total of approximately
$814 million under letters of credit and surety bonds. Most
of these letters of credit and surety bonds are issued in
support of the Companys obligations to perform under
commodity agreements, financing or other arrangements. A
majority of these letters of credit and surety bonds expire
within one year of issuance, and it is typical for the Company
to renew them on similar terms.
Asset sale guarantees NRG is typically
requested to provide certain assurances to the counter-parties
of the Companys asset sale agreements. Such assurances may
take the form of a guarantee issued by the Company on behalf of
a directly or indirectly held majority-owned subsidiary which
include certain indemnifications to a third party, usually the
buyer, as described below. Due to the inter-company nature of
such arrangements, NRG is essentially guaranteeing its own
performance, and the nature of the guarantee being provided. It
is not the Companys policy to recognize the value of such
an obligation in its consolidated financial statements. Most of
these guarantees provide an explicit cap on the Companys
maximum liability, as well as an expiration period, exclusive of
breach of representations and warranties.
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.
Commercial sales arrangements In connection
with the purchase and sale of fuel, emission allowances and
power generation products to and from third parties with respect
to the operation of some of NRGs generation facilities in
the U.S., the Company may be required to guarantee a portion of
the obligations of certain of its subsidiaries. These
obligations may include liquidated damages payments or other
unscheduled payments.
Other guarantees NRG has issued guarantees of
obligations that its subsidiaries may incur as a provision for
environmental site remediation, payment of debt obligations,
rail car leases, performance under purchase, EPC and
219
operating and maintenance agreements. NRG has executed
guarantees with related parties for one of its subsidiarys
obligations as construction manager under EPC contracts for the
construction of the two peaking power plants at GenConns
Devon and Middletown sites. See Note 16, Investments
Accounted for by the Equity Method, for more information on
this equity investment. The Company does not believe that it
will be required to perform under these guarantees.
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.
In connection with the October 5, 2009, amendment of the
CSRA, NRG signed guarantee agreements on behalf of its
subsidiary NRG Retail, LLC guaranteeing performance under power
purchase and sales contracts. See Note 3, Business
Acquisitions, for more information on the amendment of the CSRA.
The material indemnities, within the scope of ASC 460, are as
follows:
Asset purchases and divestitures The purchase
and sale agreements which govern NRGs asset or share
investments and divestitures customarily contain
indemnifications of the transaction to third parties. The
contracts indemnify the parties for liabilities incurred as a
result of a breach of a representation or warranty by the
indemnifying party, or as a result of a change in tax laws.
These obligations generally have a discrete term and are
intended to protect the parties against risks that are difficult
to predict or estimate at the time of the transaction. In
several cases, the contract limits the liability of the
indemnifier. For those indemnities in which liability is capped,
the maximum exposures range from $1 million to
$300 million. NRG has no reason to believe that the Company
currently has any material liability relating to such routine
indemnification obligations.
Other indemnities Other indemnifications NRG
has provided cover operational, tax, litigation and breaches of
representations, warranties and covenants. NRG has also
indemnified, on a routine basis in the ordinary course of
business, consultants or other vendors who have provided
services to the Company. NRGs maximum potential exposure
under these indemnifications can range from a specified dollar
amount to an indeterminate amount, depending on the nature of
the transaction. Total maximum potential exposure under these
indemnifications is not estimable due to uncertainty as to
whether claims will be made or how they will be resolved. NRG
does not have any reason to believe that the Company will be
required to make any material payments under these indemnity
provisions.
Because many of the guarantees and indemnities NRG issues to
third parties and affiliates do not limit the amount or duration
of its obligations to perform under them, there exists a risk
that the Company may have obligations in excess of the amounts
described above. For those guarantees and indemnities that do
not limit the Companys liability exposure, it may not be
able to estimate what the Companys liability would be,
until a claim is made for payment or performance, due to the
contingent nature of these contracts.
|
|
Note 27
|
Jointly
Owned Plants
|
Certain NRG subsidiaries own undivided interests in
jointly-owned plants, described below. These plants are
maintained and operated pursuant to their joint ownership
participation and operating agreements. NRG is responsible for
its subsidiaries share of operating costs and direct
expense and includes its proportionate share of the facilities
and related revenues and direct expenses in these jointly-owned
plants in the corresponding balance sheet and income statement
captions of the Companys consolidated financial statements.
220
The following table summarizes NRGs proportionate
ownership interest in the Companys jointly-owned
facilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
Property, Plant &
|
|
Accumulated
|
|
Construction in
|
As of December 31, 2009
|
|
Interest
|
|
Equipment
|
|
Depreciation
|
|
Progress
|
|
|
(In millions unless otherwise stated)
|
|
South Texas Project Units 1 and 2, Bay City, TX
|
|
|
44.00
|
%
|
|
$
|
3,003
|
|
|
$
|
(663
|
)
|
|
$
|
32
|
|
Big Cajun II Unit 3, New Roads, LA
|
|
|
58.00
|
|
|
|
175
|
|
|
|
(58
|
)
|
|
|
13
|
|
Cedar Bayou Unit 4, Baytown, TX
|
|
|
50.00
|
|
|
|
215
|
|
|
|
(5
|
)
|
|
|
|
|
Keystone, Shelocta, PA
|
|
|
3.70
|
|
|
|
88
|
|
|
|
(19
|
)
|
|
|
4
|
|
Conemaugh, New Florence, PA
|
|
|
3.72
|
|
|
|
74
|
|
|
|
(22
|
)
|
|
|
2
|
|
|
|
Note 28
|
Unaudited
Quarterly Financial Data
|
Summarized unaudited quarterly financial data is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
2009
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
|
|
(In millions, except per share data)
|
|
Operating revenues
|
|
$
|
2,141
|
|
|
$
|
2,916
|
|
|
$
|
2,237
|
|
|
$
|
1,658
|
|
Operating income
|
|
|
314
|
|
|
|
611
|
|
|
|
619
|
|
|
|
615
|
|
Income from continuing operations, net of income taxes
|
|
|
33
|
|
|
|
278
|
|
|
|
433
|
|
|
|
198
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
33
|
|
|
$
|
278
|
|
|
$
|
433
|
|
|
$
|
198
|
|
Weighted average number of common shares outstanding
basic
|
|
|
242
|
|
|
|
249
|
|
|
|
253
|
|
|
|
237
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
0.11
|
|
|
$
|
1.09
|
|
|
$
|
1.68
|
|
|
$
|
0.78
|
|
Net income per weighted average common share basic
|
|
$
|
0.11
|
|
|
$
|
1.09
|
|
|
$
|
1.68
|
|
|
$
|
0.78
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
244
|
|
|
|
272
|
|
|
|
275
|
|
|
|
275
|
|
Income from continuing operations per weighted average common
share diluted
|
|
$
|
0.11
|
|
|
$
|
1.02
|
|
|
$
|
1.56
|
|
|
$
|
0.70
|
|
Net income per weighted average common share diluted
|
|
$
|
0.11
|
|
|
$
|
1.02
|
|
|
$
|
1.56
|
|
|
$
|
0.70
|
|
221
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quarter Ended
|
|
|
2008
|
|
|
December 31
|
|
September 30
|
|
June 30
|
|
March 31
|
|
|
(In millions, except per share data)
|
|
Operating revenues
|
|
$
|
1,655
|
|
|
$
|
2,612
|
|
|
$
|
1,316
|
|
|
$
|
1,302
|
|
Operating income
|
|
|
595
|
|
|
|
1,371
|
|
|
|
57
|
|
|
|
250
|
|
Income/(loss) from continuing operations, net of income taxes
|
|
|
271
|
|
|
|
778
|
|
|
|
(41
|
)
|
|
|
45
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
|
|
|
|
168
|
|
|
|
4
|
|
Net income attributable to NRG Energy, Inc.
|
|
$
|
271
|
|
|
$
|
778
|
|
|
$
|
127
|
|
|
$
|
49
|
|
Weighted average number of common shares outstanding
basic
|
|
|
233
|
|
|
|
235
|
|
|
|
236
|
|
|
|
236
|
|
Income from continuing operations per weighted average common
share basic
|
|
$
|
1.10
|
|
|
$
|
3.26
|
|
|
$
|
(0.23
|
)
|
|
$
|
0.13
|
|
Income/(loss) from discontinued operations per weighted average
common share basic
|
|
|
|
|
|
|
|
|
|
|
0.71
|
|
|
|
0.02
|
|
Net income per weighted average common share basic
|
|
$
|
1.10
|
|
|
$
|
3.26
|
|
|
$
|
0.48
|
|
|
$
|
0.15
|
|
Weighted average number of common shares outstanding
diluted
|
|
|
276
|
|
|
|
277
|
|
|
|
236
|
|
|
|
245
|
|
Income/(loss) from continuing operations per weighted average
common share diluted
|
|
$
|
0.97
|
|
|
$
|
2.81
|
|
|
$
|
(0.23
|
)
|
|
$
|
0.12
|
|
Income from discontinued operations per weighted average common
share diluted
|
|
|
|
|
|
|
|
|
|
|
0.71
|
|
|
|
0.02
|
|
Net income per weighted average common share diluted
|
|
$
|
0.97
|
|
|
$
|
2.81
|
|
|
$
|
0.48
|
|
|
$
|
0.14
|
|
222
|
|
Note 29
|
Condensed
Consolidating Financial Information
|
As of December 31, 2009, the Company had $1.2 billion
of 7.25% Senior Notes due 2014, $2.4 billion of
7.375% Senior Notes due 2016 and $1.1 billion of
7.375%. Senior Notes due 2017 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.
On October 5, 2009, RERH became a guarantor subsidiary as a
result of the CSRA Amendment. The consolidating financial
statements hereinafter have been recast to reflect RERH as a
guarantor subsidiary for the period ended December 31,
2009. RERHs cash balance on the date it became a guarantor
subsidiary was $734 million.
Unless otherwise noted below, each of the following guarantor
subsidiaries fully and unconditionally guaranteed the Senior
Notes as of December 31, 2009:
|
|
|
Arthur Kill Power LLC
|
|
NRG Generation Holdings, Inc.
|
Astoria Gas Turbine Power LLC
|
|
NRG Huntley Operations Inc.
|
Berrians I Gas Turbine Power LLC
|
|
NRG International LLC
|
Big Cajun II Unit 4 LLC
|
|
NRG Kaufman LLC
|
Cabrillo Power I LLC
|
|
NRG Mesquite LLC
|
Cabrillo Power II LLC
|
|
NRG MidAtlantic Affiliate Services Inc.
|
Chickahominy River Energy Corp.
|
|
NRG Middletown Operations Inc.
|
Commonwealth Atlantic Power LLC
|
|
NRG Montville Operations Inc.
|
Conemaugh Power LLC
|
|
NRG New Jersey Energy Sales LLC
|
Connecticut Jet Power LLC
|
|
NRG New Roads Holdings LLC
|
Devon Power LLC
|
|
NRG North Central Operations, Inc.
|
Dunkirk Power LLC
|
|
NRG Northeast Affiliate Services Inc.
|
Eastern Sierra Energy Company
|
|
NRG Norwalk Harbor Operations Inc.
|
El Segundo Power, LLC
|
|
NRG Operating Services Inc.
|
El Segundo Power II LLC
|
|
NRG Oswego Harbor Power Operations Inc.
|
GCP Funding Company LLC
|
|
NRG Power Marketing LLC
|
Hanover Energy Company
|
|
NRG Retail LLC
|
Hoffman Summit Wind Project LLC
|
|
NRG Rocky Road LLC
|
Huntley IGCC LLC
|
|
NRG Saguaro Operations Inc.
|
Huntley Power LLC
|
|
NRG South Central Affiliate Services Inc.
|
Indian River IGCC LLC
|
|
NRG South Central Generating LLC
|
Indian River Operations Inc.
|
|
NRG South Central Operations Inc.
|
Indian River Power LLC
|
|
NRG South Texas LP
|
James River Power LLC
|
|
NRG Texas LLC
|
Kaufman Cogen LP
|
|
NRG Texas C & I Supply LLC
|
Keystone Power LLC
|
|
NRG Texas Holding Inc.
|
Lake Erie Properties Inc.
|
|
NRG Texas Power LLC
|
Langford Wind Power, LLC
|
|
NRG West Coast LLC
|
Louisiana Generating LLC
|
|
NRG Western Affiliate Services Inc.
|
Middletown Power LLC
|
|
Oswego Harbor Power LLC
|
Montville IGCC LLC
|
|
Padoma Wind Power, LLC
|
Montville Power LLC
|
|
Reliant Energy Power Supply, LLC
|
NEO Chester-Gen LLC
|
|
Reliant Energy Retail Holding, LLC
|
NEO Corporation
|
|
Reliant Energy Retail Services, LLC
|
NEO Freehold-Gen LLC
|
|
RE Retail Receivables, LLC
|
NEO Power Services Inc.
|
|
RERH Holdings, LLC
|
New Genco GP LLC
|
|
Reliant Energy Services Texas LLC
|
Norwalk Power LLC
|
|
Reliant Energy Texas Retail LLC
|
NRG Affiliate Services Inc.
|
|
Saguaro Power LLC
|
NRG Arthur Kill Operations Inc.
|
|
San Juan Mesa Wind Project II, LLC
|
NRG Asia-Pacific Ltd.
|
|
Somerset Operations Inc.
|
NRG Astoria Gas Turbine Operations Inc.
|
|
Somerset Power LLC
|
NRG Bayou Cove LLC
|
|
Texas Genco Financing Corp.
|
NRG Cabrillo Power Operations Inc.
|
|
Texas Genco GP, LLC
|
223
|
|
|
NRG Cadillac Operations Inc.
|
|
Texas Genco Holdings, Inc.
|
NRG California Peaker Operations LLC
|
|
Texas Genco LP, LLC
|
NRG Cedar Bayou Development Company LLC
|
|
Texas Genco Operating Services, LLC
|
NRG Connecticut Affiliate Services Inc.
|
|
Texas Genco Services, LP
|
NRG Construction LLC
|
|
Vienna Operations, Inc.
|
NRG Devon Operations Inc.
|
|
Vienna Power LLC
|
NRG Dunkirk Operations, Inc.
|
|
WCP (Generation) Holdings LLC
|
NRG El Segundo Operations Inc.
|
|
West Coast Power LLC
|
The non-guarantor subsidiaries include all of NRGs foreign
subsidiaries and certain domestic subsidiaries. NRG conducts
much of its business through and derives much of its income from
its subsidiaries. Therefore, the Companys ability to make
required payments with respect to its indebtedness and other
obligations depends on the financial results and condition of
its subsidiaries and NRGs ability to receive funds from
its subsidiaries. Except for NRG Bayou Cove, LLC, which is
subject to certain restrictions under the Companys Peaker
financing agreements, there are no restrictions on the ability
of any of the guarantor subsidiaries to transfer funds to NRG.
In addition, there may be restrictions for certain non-guarantor
subsidiaries.
The following condensed consolidating financial information
presents the financial information of NRG Energy, Inc., the
guarantor subsidiaries and the non-guarantor subsidiaries in
accordance with
Rule 3-10
under the Securities and Exchange Commissions
Regulation S-X.
The financial information may not necessarily be indicative of
results of operations or financial position had the guarantor
subsidiaries or non-guarantor subsidiaries operated as
independent entities.
In this presentation, NRG Energy, Inc. consists of parent
company operations. Guarantor subsidiaries and non-guarantor
subsidiaries of NRG are reported on an equity basis. For
companies acquired, the fair values of the assets and
liabilities acquired have been presented on a push-down
accounting basis.
224
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED
CONSOLIDATING STATEMENTS OF OPERATIONS
For the
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy,
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Inc.
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
(Note Issuer)
|
|
|
Eliminations (a)
|
|
|
Balance
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
8,584
|
|
|
$
|
357
|
|
|
$
|
31
|
|
|
$
|
(20
|
)
|
|
$
|
8,952
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
5,110
|
|
|
|
236
|
|
|
|
1
|
|
|
|
(24
|
)
|
|
|
5,323
|
|
Depreciation and amortization
|
|
|
772
|
|
|
|
40
|
|
|
|
6
|
|
|
|
|
|
|
|
818
|
|
Selling, general and administrative
|
|
|
266
|
|
|
|
11
|
|
|
|
273
|
|
|
|
|
|
|
|
550
|
|
Acquisition-related transaction and integration costs
|
|
|
|
|
|
|
|
|
|
|
54
|
|
|
|
|
|
|
|
54
|
|
Development costs
|
|
|
6
|
|
|
|
8
|
|
|
|
34
|
|
|
|
|
|
|
|
48
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
6,154
|
|
|
|
295
|
|
|
|
368
|
|
|
|
(24
|
)
|
|
|
6,793
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
2,430
|
|
|
|
62
|
|
|
|
(337
|
)
|
|
|
4
|
|
|
|
2,159
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
166
|
|
|
|
|
|
|
|
1,503
|
|
|
|
(1,669
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
10
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
41
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
128
|
|
|
|
|
|
|
|
|
|
|
|
128
|
|
Other income/(loss), net
|
|
|
9
|
|
|
|
(16
|
)
|
|
|
6
|
|
|
|
(4
|
)
|
|
|
(5
|
)
|
Refinancing expense
|
|
|
(1
|
)
|
|
|
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
(20
|
)
|
Interest expense
|
|
|
(106
|
)
|
|
|
(86
|
)
|
|
|
(442
|
)
|
|
|
|
|
|
|
(634
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
78
|
|
|
|
57
|
|
|
|
1,048
|
|
|
|
(1,673
|
)
|
|
|
(490
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Losses) Before Income Taxes
|
|
|
2,508
|
|
|
|
119
|
|
|
|
711
|
|
|
|
(1,669
|
)
|
|
|
1,669
|
|
Income tax expense/(benefit)
|
|
|
964
|
|
|
|
(5
|
)
|
|
|
(231
|
)
|
|
|
|
|
|
|
728
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss)
|
|
|
1,544
|
|
|
|
124
|
|
|
|
942
|
|
|
|
(1,669
|
)
|
|
|
941
|
|
Less: Net loss attributable to noncontrolling interest
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) attributable to NRG Energy, Inc.
|
|
$
|
1,545
|
|
|
$
|
124
|
|
|
$
|
942
|
|
|
$
|
(1,669
|
)
|
|
$
|
942
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
225
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
BALANCE SHEETS
December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
20
|
|
|
$
|
120
|
|
|
$
|
2,164
|
|
|
$
|
|
|
|
$
|
2,304
|
|
Funds deposited by counterparties
|
|
|
177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
177
|
|
Restricted cash
|
|
|
1
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Accounts receivable-trade, net
|
|
|
837
|
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
876
|
|
Inventory
|
|
|
529
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
541
|
|
Derivative instruments valuation
|
|
|
1,636
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,636
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
359
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
361
|
|
Prepayments and other current assets
|
|
|
194
|
|
|
|
61
|
|
|
|
157
|
|
|
|
(101
|
)
|
|
|
311
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
3,753
|
|
|
|
235
|
|
|
|
2,321
|
|
|
|
(101
|
)
|
|
|
6,208
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
10,494
|
|
|
|
1,009
|
|
|
|
61
|
|
|
|
|
|
|
|
11,564
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
613
|
|
|
|
222
|
|
|
|
16,862
|
|
|
|
(17,697
|
)
|
|
|
|
|
Equity investments in affiliates
|
|
|
42
|
|
|
|
367
|
|
|
|
|
|
|
|
|
|
|
|
409
|
|
Capital leases and note receivable, less current portion
|
|
|
4,982
|
|
|
|
504
|
|
|
|
3,027
|
|
|
|
(8,009
|
)
|
|
|
504
|
|
Goodwill
|
|
|
1,718
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,718
|
|
Intangible assets, net
|
|
|
1,755
|
|
|
|
20
|
|
|
|
33
|
|
|
|
(31
|
)
|
|
|
1,777
|
|
Nuclear decommissioning trust fund
|
|
|
367
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
367
|
|
Derivative instruments valuation
|
|
|
718
|
|
|
|
|
|
|
|
8
|
|
|
|
(43
|
)
|
|
|
683
|
|
Other non-current assets
|
|
|
29
|
|
|
|
8
|
|
|
|
111
|
|
|
|
|
|
|
|
148
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other assets
|
|
|
10,224
|
|
|
|
1,121
|
|
|
|
20,041
|
|
|
|
(25,780
|
)
|
|
|
5,606
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
24,471
|
|
|
$
|
2,365
|
|
|
$
|
22,423
|
|
|
$
|
(25,881
|
)
|
|
$
|
23,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases
|
|
$
|
58
|
|
|
$
|
310
|
|
|
$
|
261
|
|
|
$
|
(58
|
)
|
|
$
|
571
|
|
Accounts payable
|
|
|
(852
|
)
|
|
|
393
|
|
|
|
1,156
|
|
|
|
|
|
|
|
697
|
|
Derivative instruments valuation
|
|
|
1,469
|
|
|
|
2
|
|
|
|
2
|
|
|
|
|
|
|
|
1,473
|
|
Deferred income taxes
|
|
|
456
|
|
|
|
11
|
|
|
|
(270
|
)
|
|
|
|
|
|
|
197
|
|
Cash collateral received in support of energy risk management
activities
|
|
|
177
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
177
|
|
Accrued expenses and other current liabilities
|
|
|
261
|
|
|
|
82
|
|
|
|
347
|
|
|
|
(43
|
)
|
|
|
647
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities
|
|
|
1,569
|
|
|
|
798
|
|
|
|
1,496
|
|
|
|
(101
|
)
|
|
|
3,762
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases
|
|
|
2,533
|
|
|
|
1,003
|
|
|
|
12,320
|
|
|
|
(8,009
|
)
|
|
|
7,847
|
|
Nuclear decommissioning reserve
|
|
|
300
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
300
|
|
Nuclear decommissioning trust liability
|
|
|
255
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
255
|
|
Deferred income taxes
|
|
|
1,711
|
|
|
|
(165
|
)
|
|
|
237
|
|
|
|
|
|
|
|
1,783
|
|
Derivative instruments valuation
|
|
|
323
|
|
|
|
28
|
|
|
|
79
|
|
|
|
(43
|
)
|
|
|
387
|
|
Out-of-market
contracts
|
|
|
318
|
|
|
|
7
|
|
|
|
|
|
|
|
(31
|
)
|
|
|
294
|
|
Other non-current liabilities
|
|
|
431
|
|
|
|
16
|
|
|
|
359
|
|
|
|
|
|
|
|
806
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-current liabilities
|
|
|
5,871
|
|
|
|
889
|
|
|
|
12,995
|
|
|
|
(8,083
|
)
|
|
|
11,672
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities
|
|
|
7,440
|
|
|
|
1,687
|
|
|
|
14,491
|
|
|
|
(8,184
|
)
|
|
|
15,434
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3.625% Preferred Stock
|
|
|
|
|
|
|
|
|
|
|
247
|
|
|
|
|
|
|
|
247
|
|
Stockholders Equity
|
|
|
17,031
|
|
|
|
678
|
|
|
|
7,685
|
|
|
|
(17,697
|
)
|
|
|
7,697
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Liabilities and Stockholders Equity
|
|
$
|
24,471
|
|
|
$
|
2,365
|
|
|
$
|
22,423
|
|
|
$
|
(25,881
|
)
|
|
$
|
23,378
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
226
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF CASH FLOWS
Year Ended December 31, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
Energy,
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
|
|
|
|
|
|
(In millions)
|
|
|
|
|
|
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,544
|
|
|
$
|
124
|
|
|
$
|
942
|
|
|
$
|
(1,669
|
)
|
|
$
|
941
|
|
Adjustments to reconcile net income to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity (earnings)/losses of unconsolidated
affiliates
|
|
|
154
|
|
|
|
(31
|
)
|
|
|
(1,173
|
)
|
|
|
1,009
|
|
|
|
(41
|
)
|
Depreciation and amortization
|
|
|
772
|
|
|
|
40
|
|
|
|
6
|
|
|
|
|
|
|
|
818
|
|
Provision for bad debts
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
61
|
|
Amortization of nuclear fuel
|
|
|
36
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36
|
|
Amortization of financing costs and debt discounts/premiums
|
|
|
|
|
|
|
13
|
|
|
|
31
|
|
|
|
|
|
|
|
44
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
153
|
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
934
|
|
|
|
(16
|
)
|
|
|
(229
|
)
|
|
|
|
|
|
|
689
|
|
Changes in nuclear decommissioning liability
|
|
|
26
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
Changes in derivatives
|
|
|
(228
|
)
|
|
|
3
|
|
|
|
|
|
|
|
|
|
|
|
(225
|
)
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
129
|
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
127
|
|
Loss on disposals and sales of assets
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Gain on sales of equity method investments
|
|
|
|
|
|
|
(128
|
)
|
|
|
|
|
|
|
|
|
|
|
(128
|
)
|
Gain on sale of emission allowances
|
|
|
(4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4
|
)
|
Gain recognized on settlement of pre-existing relationship
|
|
|
|
|
|
|
|
|
|
|
(31
|
)
|
|
|
|
|
|
|
(31
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
Changes in option premiums collected
|
|
|
(282
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(282
|
)
|
Cash provided/(used) by changes in other working capital, net of
acquisition/disposition affects
|
|
|
(487
|
)
|
|
|
31
|
|
|
|
335
|
|
|
|
|
|
|
|
(121
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
2,825
|
|
|
|
34
|
|
|
|
(93
|
)
|
|
|
(660
|
)
|
|
|
2,106
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
(1,755
|
)
|
|
|
|
|
|
|
159
|
|
|
|
1,596
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
200
|
|
|
|
60
|
|
|
|
(260
|
)
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(507
|
)
|
|
|
(197
|
)
|
|
|
(30
|
)
|
|
|
|
|
|
|
(734
|
)
|
Acquisition of businesses, net of cash acquired
|
|
|
(72
|
)
|
|
|
(67
|
)
|
|
|
(288
|
)
|
|
|
|
|
|
|
(427
|
)
|
Increase in restricted cash, net
|
|
|
6
|
|
|
|
8
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
(Increase)/decrease in notes receivable
|
|
|
|
|
|
|
(58
|
)
|
|
|
36
|
|
|
|
|
|
|
|
(22
|
)
|
Purchases of emission allowances
|
|
|
(78
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78
|
)
|
Proceeds from sale of emission allowances
|
|
|
40
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(305
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(305
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
279
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
279
|
|
Proceeds from sale of assets, net
|
|
|
6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6
|
|
Proceeds from sale of equity method investment
|
|
|
|
|
|
|
284
|
|
|
|
|
|
|
|
|
|
|
|
284
|
|
Equity investment in unconsolidated affiliate
|
|
|
|
|
|
|
|
|
|
|
(6
|
)
|
|
|
|
|
|
|
(6
|
)
|
Other
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
(2,186
|
)
|
|
|
30
|
|
|
|
(394
|
)
|
|
|
1,596
|
|
|
|
(954
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans
|
|
|
(258
|
)
|
|
|
99
|
|
|
|
1,755
|
|
|
|
(1,596
|
)
|
|
|
|
|
Payment of intercompany dividends
|
|
|
(330
|
)
|
|
|
(330
|
)
|
|
|
|
|
|
|
660
|
|
|
|
|
|
Payment of dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(33
|
)
|
|
|
|
|
|
|
(33
|
)
|
Net payments to settle acquired derivatives that include
financing elements
|
|
|
(79
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(79
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(500
|
)
|
|
|
|
|
|
|
(500
|
)
|
Installment proceeds from sale of noncontrolling interest in
subsidiary
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
2
|
|
Proceeds from issuance of long-term debt
|
|
|
77
|
|
|
|
127
|
|
|
|
688
|
|
|
|
|
|
|
|
892
|
|
Payment of deferred debt issuance costs
|
|
|
(2
|
)
|
|
|
(3
|
)
|
|
|
(26
|
)
|
|
|
|
|
|
|
(31
|
)
|
Payments of short and long-term debt
|
|
|
(25
|
)
|
|
|
(47
|
)
|
|
|
(572
|
)
|
|
|
|
|
|
|
(644
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(617
|
)
|
|
|
(104
|
)
|
|
|
1,314
|
|
|
|
(936
|
)
|
|
|
(343
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
22
|
|
|
|
(39
|
)
|
|
|
827
|
|
|
|
|
|
|
|
810
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
(2
|
)
|
|
|
159
|
|
|
|
1,337
|
|
|
|
|
|
|
|
1,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
20
|
|
|
$
|
120
|
|
|
$
|
2,164
|
|
|
$
|
|
|
|
$
|
2,304
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
227
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
6,504
|
|
|
$
|
405
|
|
|
$
|
|
|
|
$
|
(24
|
)
|
|
$
|
6,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,321
|
|
|
|
303
|
|
|
|
|
|
|
|
(26
|
)
|
|
|
3,598
|
|
Depreciation and amortization
|
|
|
618
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
General and administrative
|
|
|
64
|
|
|
|
14
|
|
|
|
241
|
|
|
|
|
|
|
|
319
|
|
Development costs
|
|
|
(1
|
)
|
|
|
7
|
|
|
|
40
|
|
|
|
|
|
|
|
46
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
4,002
|
|
|
|
351
|
|
|
|
285
|
|
|
|
(26
|
)
|
|
|
4,612
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
2,502
|
|
|
|
54
|
|
|
|
(285
|
)
|
|
|
2
|
|
|
|
2,273
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
276
|
|
|
|
|
|
|
|
1,638
|
|
|
|
(1,914
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
(2
|
)
|
|
|
61
|
|
|
|
|
|
|
|
|
|
|
|
59
|
|
Other income/(expense), net
|
|
|
23
|
|
|
|
11
|
|
|
|
(15
|
)
|
|
|
(2
|
)
|
|
|
17
|
|
Interest expense
|
|
|
(183
|
)
|
|
|
(77
|
)
|
|
|
(323
|
)
|
|
|
|
|
|
|
(583
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
114
|
|
|
|
(5
|
)
|
|
|
1,300
|
|
|
|
(1,916
|
)
|
|
|
(507
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations Before Income Taxes
|
|
|
2,616
|
|
|
|
49
|
|
|
|
1,015
|
|
|
|
(1,914
|
)
|
|
|
1,766
|
|
Income tax expense/(benefit)
|
|
|
1,001
|
|
|
|
19
|
|
|
|
(307
|
)
|
|
|
|
|
|
|
713
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income From Continuing Operations
|
|
|
1,615
|
|
|
|
30
|
|
|
|
1,322
|
|
|
|
(1,914
|
)
|
|
|
1,053
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
269
|
|
|
|
(97
|
)
|
|
|
|
|
|
|
172
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) attributable to NRG Energy, Inc.
|
|
$
|
1,615
|
|
|
$
|
299
|
|
|
$
|
1,225
|
|
|
$
|
(1,914
|
)
|
|
$
|
1,225
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
228
NRG
ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
NRG Energy,
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Inc.
|
|
|
Eliminations
(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
ASSETS
|
Current Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
(2
|
)
|
|
$
|
159
|
|
|
$
|
1,337
|
|
|
$
|
|
|
|
$
|
1,494
|
|
Funds deposited by counterparties
|
|
|
|
|
|
|
|
|
|
|
754
|
|
|
|
|
|
|
|
754
|
|
Restricted cash
|
|
|
7
|
|
|
|
9
|
|
|
|
|
|
|
|
|
|
|
|
16
|
|
Accounts receivable-trade, net
|
|
|
422
|
|
|
|
42
|
|
|
|
|
|
|
|
|
|
|
|
464
|
|
Inventory
|
|
|
443
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
455
|
|
Derivative instruments valuation
|
|
|
4,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,600
|
|
Cash collateral paid in support of energy risk management
activities
|
|
|
494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
494
|
|
Prepayments and other current assets
|
|
|
130
|
|
|
|
37
|
|
|
|
278
|
|
|
|
(230
|
)
|
|
|
215
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets
|
|
|
6,094
|
|
|
|
259
|
|
|
|
2,369
|
|
|
|
(230
|
)
|
|
|
8,492
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Property, Plant and Equipment
|
|
|
10,725
|
|
|
|
791
|
|
|
|
29
|
|
|
|
|
|
|
|
11,545
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries
|
|
|
651
|
|
|
|
|
|
|
|
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.
|
229
NRG
ENERGY, INC. AND
NRG ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations
(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,615
|
|
|
$
|
299
|
|
|
$
|
1,225
|
|
|
$
|
(1,914
|
)
|
|
$
|
1,225
|
|
Adjustments to reconcile net income to net cash provided/(used)
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity (earnings)/losses of unconsolidated
affiliates
|
|
|
(274
|
)
|
|
|
(46
|
)
|
|
|
(1,638
|
)
|
|
|
1,914
|
|
|
|
(44
|
)
|
Depreciation and amortization
|
|
|
618
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
649
|
|
Amortization of nuclear fuel
|
|
|
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
39
|
|
Amortization of financing costs and debt discount/premiums
|
|
|
|
|
|
|
15
|
|
|
|
22
|
|
|
|
|
|
|
|
37
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
(270
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(270
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
|
|
|
|
|
26
|
|
Loss on disposals and sales of assets
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
Impairment charges and asset write downs
|
|
|
|
|
|
|
|
|
|
|
23
|
|
|
|
|
|
|
|
23
|
|
Changes in derivatives
|
|
|
(482
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
|
|
|
|
(484
|
)
|
Changes in deferred income taxes and liability for unrecognized
tax benefits
|
|
|
312
|
|
|
|
(16
|
)
|
|
|
466
|
|
|
|
|
|
|
|
762
|
|
Gain on sale of discontinued operations
|
|
|
|
|
|
|
(273
|
)
|
|
|
|
|
|
|
|
|
|
|
(273
|
)
|
Gain on sale of emission allowances
|
|
|
(51
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(51
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(417
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(417
|
)
|
Cash provided/(used) by changes in other working capital, net of
disposition affects
|
|
|
745
|
|
|
|
88
|
|
|
|
(635
|
)
|
|
|
|
|
|
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
1,894
|
|
|
|
92
|
|
|
|
(507
|
)
|
|
|
|
|
|
|
1,479
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
(238
|
)
|
|
|
|
|
|
|
696
|
|
|
|
(458
|
)
|
|
|
|
|
Capital expenditures
|
|
|
(597
|
)
|
|
|
(294
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
(899
|
)
|
(Increase)/decrease in restricted cash
|
|
|
(6
|
)
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
13
|
|
Decrease/(increase) in notes receivable
|
|
|
|
|
|
|
45
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
10
|
|
Purchases of emission allowances
|
|
|
(8
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(8
|
)
|
Proceeds from sale of emission allowances
|
|
|
75
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
75
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(616
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(616
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
582
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
582
|
|
Proceeds from sale of assets, net
|
|
|
14
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14
|
|
Equity investment in unconsolidated affiliate
|
|
|
|
|
|
|
(84
|
)
|
|
|
|
|
|
|
|
|
|
|
(84
|
)
|
Proceeds from sale of discontinued operations, net of cash
divested
|
|
|
|
|
|
|
(59
|
)
|
|
|
300
|
|
|
|
|
|
|
|
241
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
(794
|
)
|
|
|
(373
|
)
|
|
|
953
|
|
|
|
(458
|
)
|
|
|
(672
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans
|
|
|
(1,059
|
)
|
|
|
315
|
|
|
|
286
|
|
|
|
458
|
|
|
|
|
|
Payment for dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
(55
|
)
|
Net payments to settle acquired derivatives that include
financing elements
|
|
|
(43
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(43
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(185
|
)
|
|
|
|
|
|
|
(185
|
)
|
Installment proceeds from sale of noncontrolling interest of
subsidiary
|
|
|
|
|
|
|
50
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Payment to settle CSF I CAGR
|
|
|
|
|
|
|
(45
|
)
|
|
|
|
|
|
|
|
|
|
|
(45
|
)
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
9
|
|
|
|
|
|
|
|
9
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
|
|
|
|
|
(4
|
)
|
Payments of short and long-term debt
|
|
|
|
|
|
|
(60
|
)
|
|
|
(174
|
)
|
|
|
|
|
|
|
(234
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Financing Activities
|
|
|
(1,102
|
)
|
|
|
278
|
|
|
|
(121
|
)
|
|
|
458
|
|
|
|
(487
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
43
|
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
(2
|
)
|
|
|
39
|
|
|
|
325
|
|
|
|
|
|
|
|
362
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
|
|
|
|
120
|
|
|
|
1,012
|
|
|
|
|
|
|
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
(2
|
)
|
|
$
|
159
|
|
|
$
|
1,337
|
|
|
$
|
|
|
|
$
|
1,494
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
230
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING
STATEMENTS OF OPERATIONS
For the
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Non-Guarantor
|
|
|
NRG
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
Energy, Inc.
|
|
|
Eliminations
(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Operating Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues
|
|
$
|
5,614
|
|
|
$
|
375
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
5,989
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations
|
|
|
3,130
|
|
|
|
248
|
|
|
|
|
|
|
|
|
|
|
|
3,378
|
|
Depreciation and amortization
|
|
|
630
|
|
|
|
24
|
|
|
|
4
|
|
|
|
|
|
|
|
658
|
|
General and administrative
|
|
|
102
|
|
|
|
18
|
|
|
|
189
|
|
|
|
|
|
|
|
309
|
|
Development costs
|
|
|
66
|
|
|
|
2
|
|
|
|
33
|
|
|
|
|
|
|
|
101
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses
|
|
|
3,928
|
|
|
|
292
|
|
|
|
226
|
|
|
|
|
|
|
|
4,446
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain/(loss) on sale of assets
|
|
|
18
|
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income/(Loss)
|
|
|
1,704
|
|
|
|
83
|
|
|
|
(227
|
)
|
|
|
|
|
|
|
1,560
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income/(Expense)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries
|
|
|
204
|
|
|
|
|
|
|
|
973
|
|
|
|
(1,177
|
)
|
|
|
|
|
Equity in earnings of unconsolidated affiliates
|
|
|
(3
|
)
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
54
|
|
Gains on sales of equity method investments
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
1
|
|
Other income, net
|
|
|
9
|
|
|
|
13
|
|
|
|
33
|
|
|
|
|
|
|
|
55
|
|
Refinancing expenses
|
|
|
|
|
|
|
|
|
|
|
(35
|
)
|
|
|
|
|
|
|
(35
|
)
|
Interest expense
|
|
|
(250
|
)
|
|
|
(77
|
)
|
|
|
(375
|
)
|
|
|
|
|
|
|
(702
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income/(expense)
|
|
|
(40
|
)
|
|
|
(6
|
)
|
|
|
596
|
|
|
|
(1,177
|
)
|
|
|
(627
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) From Continuing Operations Before Income
Taxes
|
|
|
1,664
|
|
|
|
77
|
|
|
|
369
|
|
|
|
(1,177
|
)
|
|
|
933
|
|
Income tax expense/(benefit)
|
|
|
576
|
|
|
|
5
|
|
|
|
(204
|
)
|
|
|
|
|
|
|
377
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) From Continuing Operations
|
|
|
1,088
|
|
|
|
72
|
|
|
|
573
|
|
|
|
(1,177
|
)
|
|
|
556
|
|
Income from discontinued operations, net of income taxes
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss)
|
|
$
|
1,088
|
|
|
$
|
89
|
|
|
$
|
573
|
|
|
$
|
(1,177
|
)
|
|
$
|
573
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
231
NRG
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor
|
|
|
Guarantor
|
|
|
|
|
|
|
|
|
Consolidated
|
|
|
|
Subsidiaries
|
|
|
Subsidiaries
|
|
|
NRG Energy, Inc.
|
|
|
Eliminations(a)
|
|
|
Balance
|
|
|
|
(In millions)
|
|
|
Cash Flows from Operating Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
1,088
|
|
|
$
|
89
|
|
|
$
|
573
|
|
|
$
|
(1,177
|
)
|
|
$
|
573
|
|
Adjustments to reconcile net income to net cash provided/(used)
by operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions and equity (earnings)/losses of unconsolidated
affiliates
|
|
|
101
|
|
|
|
(36
|
)
|
|
|
(684
|
)
|
|
|
586
|
|
|
|
(33
|
)
|
Depreciation and amortization
|
|
|
630
|
|
|
|
27
|
|
|
|
4
|
|
|
|
|
|
|
|
661
|
|
Amortization of nuclear fuel
|
|
|
58
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
58
|
|
Amortization of financing costs and debt discount/premiums
|
|
|
|
|
|
|
19
|
|
|
|
60
|
|
|
|
|
|
|
|
79
|
|
Amortization of intangibles and
out-of-market
contracts
|
|
|
(160
|
)
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
(156
|
)
|
Amortization of unearned equity compensation
|
|
|
|
|
|
|
|
|
|
|
19
|
|
|
|
|
|
|
|
19
|
|
(Gain)/loss on sale of assets
|
|
|
(18
|
)
|
|
|
|
|
|
|
1
|
|
|
|
|
|
|
|
(17
|
)
|
Impairment charges and asset write downs
|
|
|
9
|
|
|
|
|
|
|
|
11
|
|
|
|
|
|
|
|
20
|
|
Changes in derivatives
|
|
|
77
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
77
|
|
Changes in deferred income taxes and liability for unearned tax
benefits
|
|
|
112
|
|
|
|
(31
|
)
|
|
|
278
|
|
|
|
|
|
|
|
359
|
|
Gains on sale of equity method investments
|
|
|
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(1
|
)
|
Gain on sale of emission allowances
|
|
|
(30
|
)
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
(31
|
)
|
Change in nuclear decommissioning trust liability
|
|
|
32
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32
|
|
Changes in collateral deposits supporting energy risk management
activities
|
|
|
(125
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(125
|
)
|
Cash provided/(used) by changes in other working capital, net of
disposition affects
|
|
|
218
|
|
|
|
96
|
|
|
|
(299
|
)
|
|
|
(13
|
)
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Operating Activities
|
|
|
1,992
|
|
|
|
166
|
|
|
|
(37
|
)
|
|
|
(604
|
)
|
|
|
1,517
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Investing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany (loans to)/receipts from subsidiaries
|
|
|
655
|
|
|
|
|
|
|
|
2,109
|
|
|
|
(2,764
|
)
|
|
|
|
|
Capital expenditures
|
|
|
(389
|
)
|
|
|
(84
|
)
|
|
|
(8
|
)
|
|
|
|
|
|
|
(481
|
)
|
Decrease in restricted cash, net
|
|
|
|
|
|
|
12
|
|
|
|
|
|
|
|
|
|
|
|
12
|
|
Decrease in notes receivable
|
|
|
|
|
|
|
34
|
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Decrease in trust fund balances
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
|
|
Purchases of emission allowances
|
|
|
(161
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(161
|
)
|
Proceeds from sale of emission allowances
|
|
|
271
|
|
|
|
1
|
|
|
|
|
|
|
|
|
|
|
|
272
|
|
Investments in nuclear decommissioning trust fund securities
|
|
|
(265
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(265
|
)
|
Proceeds from sales of nuclear decommissioning trust fund
securities
|
|
|
233
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
233
|
|
Proceeds from sale of assets
|
|
|
|
|
|
|
2
|
|
|
|
|
|
|
|
|
|
|
|
2
|
|
Purchase of securities
|
|
|
|
|
|
|
|
|
|
|
(49
|
)
|
|
|
|
|
|
|
(49
|
)
|
Proceeds from sale of discontinued operations and assets, net of
cash divested
|
|
|
29
|
|
|
|
|
|
|
|
28
|
|
|
|
|
|
|
|
57
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash Provided/(Used) by Investing Activities
|
|
|
392
|
|
|
|
(35
|
)
|
|
|
2,080
|
|
|
|
(2,764
|
)
|
|
|
(327
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flows from Financing Activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Payments)/proceeds from intercompany loans
|
|
|
(2,101
|
)
|
|
|
(38
|
)
|
|
|
(625
|
)
|
|
|
2,764
|
|
|
|
|
|
Payment from intercompany dividends
|
|
|
(302
|
)
|
|
|
(302
|
)
|
|
|
|
|
|
|
604
|
|
|
|
|
|
Payment for dividends to preferred stockholders
|
|
|
|
|
|
|
|
|
|
|
(55
|
)
|
|
|
|
|
|
|
(55
|
)
|
Payment for treasury stock
|
|
|
|
|
|
|
|
|
|
|
(353
|
)
|
|
|
|
|
|
|
(353
|
)
|
Proceeds from issuance of common stock, net of issuance costs
|
|
|
|
|
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
7
|
|
Proceeds from issuance of long-term debt
|
|
|
|
|
|
|
|
|
|
|
1,411
|
|
|
|
|
|
|
|
1,411
|
|
Payment of deferred debt issuance costs
|
|
|
|
|
|
|
|
|
|
|
(5
|
)
|
|
|
|
|
|
|
(5
|
)
|
Payments of short and long-term debt
|
|
|
(1
|
)
|
|
|
(64
|
)
|
|
|
(1,754
|
)
|
|
|
|
|
|
|
(1,819
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Cash (Used)/Provided by Financing Activities
|
|
|
(2,404
|
)
|
|
|
(404
|
)
|
|
|
(1,374
|
)
|
|
|
3,368
|
|
|
|
(814
|
)
|
Change in cash from discontinued operations
|
|
|
|
|
|
|
(25
|
)
|
|
|
|
|
|
|
|
|
|
|
(25
|
)
|
Effect of exchange rate changes on cash and cash equivalents
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents
|
|
|
(20
|
)
|
|
|
(294
|
)
|
|
|
669
|
|
|
|
|
|
|
|
355
|
|
Cash and Cash Equivalents at Beginning of Period
|
|
|
20
|
|
|
|
414
|
|
|
|
343
|
|
|
|
|
|
|
|
777
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents at End of Period
|
|
$
|
|
|
|
$
|
120
|
|
|
$
|
1,012
|
|
|
$
|
|
|
|
$
|
1,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
All significant intercompany
transactions have been eliminated in consolidation.
|
232
Schedule of valuation and qualifying accounts disclosure
NRG
ENERGY, INC.
SCHEDULE II.
VALUATION AND QUALIFYING ACCOUNTS
For the
Years Ended December 31, 2009, 2008, and 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at
|
|
Charged to
|
|
Charged to
|
|
|
|
|
|
|
Beginning of
|
|
Costs and
|
|
Other
|
|
|
|
Balance at
|
|
|
Period
|
|
Expenses
|
|
Accounts
|
|
Deductions
|
|
End of Period
|
|
|
(In millions)
|
|
Allowance for doubtful accounts, deducted from accounts
receivable
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009
|
|
$
|
3
|
|
|
$
|
61
|
(a)
|
|
$
|
|
|
|
$
|
(35
|
)(b)
|
|
$
|
29
|
|
Year ended December 31, 2008
|
|
$
|
1
|
|
|
$
|
2
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
3
|
|
Year ended December 31, 2007
|
|
$
|
1
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
|
$
|
1
|
|
Income tax valuation allowance, deducted from deferred tax
assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2009
|
|
$
|
359
|
|
|
$
|
(130
|
)
|
|
$
|
4
|
|
|
$
|
|
|
|
$
|
233
|
|
Year ended December 31, 2008
|
|
$
|
539
|
|
|
$
|
(12
|
)
|
|
$
|
(6
|
)
|
|
$
|
(162
|
)
|
|
$
|
359
|
|
Year ended December 31, 2007
|
|
$
|
581
|
|
|
$
|
6
|
|
|
$
|
8
|
|
|
$
|
(56
|
)
|
|
$
|
539
|
|
|
|
|
(a)
|
|
Significant increase reflects
acquisition of Reliant Energy in May 2009.
|
(b)
|
|
Represents principally net amounts
charged as uncollectable.
|
233
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned
thereunto duly authorized.
NRG
Energy, Inc.
(Registrant)
David W. Crane
Chief Executive Officer
Date: February 23, 2010
234
POWER OF
ATTORNEY
Each person whose signature appears below constitutes and
appoints David W. Crane, Michael R. Bramnick, Tanuja M. Dehne
and Brian Curci, each or any of them, such persons true
and lawful attorney-in-fact and agent with full power of
substitution and resubstitution for such person and in such
persons name, place and stead, in any and all capacities,
to sign any and all amendments to this report on
Form 10-K,
and to file the same with all exhibits thereto, and other
documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorneys-in-fact and
agents, and each of them, full power and authority to do and
perform each and every act and thing necessary or desirable to
be done in and about the premises, as fully to all intents and
purposes as such person, hereby ratifying and confirming all
that said attorneys-in-fact and agents, or any of them or his or
their substitute or substitutes, may lawfully do or cause to be
done by virtue hereof.
In accordance with the Exchange Act, this report has been signed
by the following persons on behalf of the registrant in the
capacities indicated on February 23, 2010.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ David W. Crane
David W. Crane
|
|
President, Chief Executive Officer and Director
(Principle Executive Officer)
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Gerald Luterman
Gerald Luterman
|
|
Chief Financial Officer and Director
(Principle Financial Officer)
|
|
February 23, 2010
|
|
|
|
|
|
/s/ James J. Ingoldsby
James J. Ingoldsby
|
|
Chief Accounting Officer
(Principle Accounting Officer)
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Howard E. Cosgrove
Howard E. Cosgrove
|
|
Chairman of the Board
|
|
February 23, 2010
|
|
|
|
|
|
Kirbyjon
H. Caldwell
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ John F. Chlebowski
John F. Chlebowski
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Lawrence S. Coben
Lawrence S. Coben
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Stephen L. Cropper
Stephen L. Cropper
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ William E. Hantke
William E. Hantke
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Paul W. Hobby
Paul W. Hobby
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Kathleen A. McGinty
Kathleen A. McGinty
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Anne C. Schaumburg
Anne C. Schaumburg
|
|
Director
|
|
February 23, 2010
|
235
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
/s/ Herbert H. Tate
Herbert H. Tate
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
/s/ Thomas H. Weidemeyer
Thomas H. Weidemeyer
|
|
Director
|
|
February 23, 2010
|
|
|
|
|
|
Walter
R. Young
|
|
Director
|
|
February 23, 2010
|
236
EXHIBIT INDEX
|
|
|
|
|
|
|
|
|
|
|
2
|
.1
|
|
Third Amended Joint Plan of Reorganization of NRG Energy, Inc.,
NRG Power Marketing, Inc., NRG Capital LLC, NRG Finance Company
I LLC, and NRGenerating Holdings (No. 23) B.V.(5)
|
|
|
|
|
|
|
2
|
.2
|
|
First Amended Joint Plan of Reorganization of NRG Northeast
Generating LLC (and certain of its subsidiaries), NRG South
Central Generating (and certain of its subsidiaries) and
Berrians I Gas Turbine Power LLC.(5)
|
|
|
|
|
|
|
2
|
.3
|
|
Acquisition Agreement, dated as of September 30, 2005, by
and among NRG Energy, Inc., Texas Genco LLC and the Direct and
Indirect Owners of Texas Genco LLC.(11)
|
|
|
|
|
|
|
3
|
.1
|
|
Amended and Restated Certificate of Incorporation.(45)
|
|
|
|
|
|
|
3
|
.2
|
|
Amended and Restated By-Laws.(47)
|
|
|
|
|
|
|
3
|
.3
|
|
Certificate of Designations of 3.625% Convertible Perpetual
Preferred Stock, as filed with the Secretary of State of the
State of Delaware on August 11, 2005.(17)
|
|
|
|
|
|
|
3
|
.4
|
|
Certificate of Designations relating to the Series 1
Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance I LLC, as filed with the Secretary of
State of Delaware on August 14, 2006.(27)
|
|
|
|
|
|
|
3
|
.5
|
|
Certificate of Amendment to Certificate of Designations relating
to the Series 1 Exchangeable Limited Liability Company
Preferred Interests of NRG Common Stock Finance I LLC, as filed
with the Secretary of State of Delaware on February 27,
2008.(36)
|
|
|
|
|
|
|
3
|
.6
|
|
Second Certificate of Amendment to Certificate of Designations
relating to the Series 1 Exchangeable Limited Liability
Company Preferred Interests of NRG Common Stock Finance I LLC,
as filed with the Secretary of State of Delaware on
August 8, 2008.(37)
|
|
|
|
|
|
|
4
|
.1
|
|
Supplemental Indenture dated as of December 30, 2005, among
NRG Energy, Inc., the subsidiary guarantors named on
Schedule A thereto and Law Debenture Trust Company of
New York, as trustee.(13)
|
|
|
|
|
|
|
4
|
.2
|
|
Amended and Restated Common Agreement among XL Capital Assurance
Inc., Goldman Sachs Mitsui Marine Derivative Products, L.P., Law
Debenture Trust Company of New York, as Trustee, The Bank
of New York, as Collateral Agent, NRG Peaker Finance Company LLC
and each Project Company Party thereto dated as of
January 6, 2004, together with Annex A to the Common
Agreement.(2)
|
|
|
|
|
|
|
4
|
.3
|
|
Amended and Restated Security Deposit Agreement among NRG Peaker
Finance Company, LLC and each Project Company party thereto, and
the Bank of New York, as Collateral Agent and Depositary Agent,
dated as of January 6, 2004.(2)
|
|
|
|
|
|
|
4
|
.4
|
|
NRG Parent Agreement by NRG Energy, Inc. in favor of the Bank of
New York, as Collateral Agent, dated as of January 6,
2004.(2)
|
|
|
|
|
|
|
4
|
.5
|
|
Indenture dated June 18, 2002, between NRG Peaker Finance
Company LLC, as Issuer, Bayou Cove Peaking Power LLC, Big Cajun
I Peaking Power LLC, NRG Rockford LLC, NRG Rockford II LLC
and Sterlington Power LLC, as Guarantors, XL Capital Assurance
Inc., as Insurer, and Law Debenture Trust Company, as
Successor Trustee to the Bank of New York.(3)
|
|
|
|
|
|
|
4
|
.6
|
|
Specimen of Certificate representing common stock of NRG Energy,
Inc.(26)
|
|
|
|
|
|
|
4
|
.7
|
|
Indenture, dated February 2, 2006, among NRG Energy, Inc.
and Law Debenture Trust Company of New York.(19)
|
|
|
|
|
|
|
4
|
.8
|
|
First Supplemental Indenture, dated February 2, 2006, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(20)
|
|
|
|
|
|
|
4
|
.9
|
|
Second Supplemental Indenture, dated February 2, 2006,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2016.(20)
|
237
|
|
|
|
|
|
|
|
|
|
|
4
|
.10
|
|
Form of 7.250% Senior Note due 2014.(20)
|
|
|
|
|
|
|
4
|
.11
|
|
Form of 7.375% Senior Note due 2016.(20)
|
|
|
|
|
|
|
4
|
.12
|
|
Form of 7.375% Senior Note due 2017.(29)
|
|
|
|
|
|
|
4
|
.13
|
|
Form of 8.5% Senior Note due 2019.(42)
|
|
|
|
|
|
|
4
|
.14
|
|
Third Supplemental Indenture, dated March 14, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.250% Senior Notes due 2014.(22)
|
|
|
|
|
|
|
4
|
.15
|
|
Fourth Supplemental Indenture, dated March 14, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.375% Senior Notes due 2016.(22)
|
|
|
|
|
|
|
4
|
.16
|
|
Fifth Supplemental Indenture, dated April 28, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.250% Senior Notes due 2014.(23)
|
|
|
|
|
|
|
4
|
.17
|
|
Sixth Supplemental Indenture, dated April 28, 2006, among
NRG, the existing guarantors named therein, the guaranteeing
subsidiaries named therein and Law Debenture Trust Company
of New York as Trustee, re: NRG Energy, Inc.s
7.375% Senior Notes due 2016.(23)
|
|
|
|
|
|
|
4
|
.18
|
|
Seventh Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(28)
|
|
|
|
|
|
|
4
|
.19
|
|
Eighth Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(28)
|
|
|
|
|
|
|
4
|
.20
|
|
Ninth Supplemental Indenture, dated November 13, 2006,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2017.(29)
|
|
|
|
|
|
|
4
|
.21
|
|
Tenth Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(33)
|
|
|
|
|
|
|
4
|
.22
|
|
Eleventh Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(33)
|
|
|
|
|
|
|
4
|
.23
|
|
Twelfth Supplemental Indenture, dated July 19, 2007, among
NRG Energy, Inc., the guarantors named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2017.(33)
|
|
|
|
|
|
|
4
|
.24
|
|
Thirteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.250% Senior Notes due 2014.(34)
|
|
|
|
|
|
|
4
|
.25
|
|
Fourteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2016.(34)
|
|
|
|
|
|
|
4
|
.26
|
|
Fifteenth Supplemental Indenture, dated August 28, 2007,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.375% Senior Notes due 2017.(34)
|
|
|
|
|
|
|
4
|
.27
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(40)
|
238
|
|
|
|
|
|
|
|
|
|
|
4
|
.28
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(40)
|
|
|
|
|
|
|
4
|
.29
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2017.(40)
|
|
|
|
|
|
|
4
|
.30
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.250% Senior Notes due 2014.(41)
|
|
|
|
|
|
|
4
|
.31
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(41)
|
|
|
|
|
|
|
4
|
.32
|
|
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 as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2017.(41)
|
|
|
|
|
|
|
4
|
.33
|
|
Twenty-Second Supplemental Indenture, dated June 5, 2009,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 8.5% Senior Notes due 2019.(42)
|
|
|
|
|
|
|
4
|
.34
|
|
Twenty-Third Supplemental Indenture, dated July 14, 2009,
among NRG Energy, Inc., the guarantors named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 8.5% Senior Notes due 2019. (44).
|
|
|
|
|
|
|
4
|
.35
|
|
Twenty-Fourth Supplemental Indenture, dated October 5,
2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiaries named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 7.250% Senior Notes due 2014.(46)
|
|
|
|
|
|
|
4
|
.36
|
|
Twenty-Fifth Supplemental Indenture, dated October 5, 2009,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2016.(46).
|
|
|
|
|
|
|
4
|
.37
|
|
Twenty-Sixth Supplemental Indenture, dated October 5, 2009,
among NRG Energy, Inc., the existing guarantors named therein,
the guaranteeing subsidiaries named therein and Law Debenture
Trust Company of New York as Trustee, re: NRG Energy,
Inc.s 7.375% Senior Notes due 2017.(46).
|
|
|
|
|
|
|
4
|
.38
|
|
Twenty-Seventh Supplemental Indenture, dated October 5,
2009, among NRG Energy, Inc., the existing guarantors named
therein, the guaranteeing subsidiaries named therein and Law
Debenture Trust Company of New York as Trustee, re: NRG
Energy, Inc.s 8.5% Senior Notes due 2019. (46).
|
|
|
|
|
|
|
10
|
.1
|
|
Note Agreement, dated August 20, 1993, between NRG Energy,
Inc., Energy Center, Inc. and each of the purchasers named
therein.(4)
|
|
|
|
|
|
|
10
|
.2
|
|
Master Shelf and Revolving Credit Agreement, dated
August 20, 1993, between NRG Energy, Inc., Energy Center,
Inc., The Prudential Insurance Registrants of America and each
Prudential Affiliate, which becomes party thereto.(4)
|
|
|
|
|
|
|
10
|
.3*
|
|
Form of NRG Energy Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Officers and Key Management.(15)
|
|
|
|
|
|
|
10
|
.4*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Deferred Stock
Unit Agreement for Directors.(15)
|
|
|
|
|
|
|
10
|
.5*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified
Stock Option Agreement.(8)
|
|
|
|
|
|
|
10
|
.6*
|
|
Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted
Stock Unit Agreement.(8)
|
|
|
|
|
|
|
10
|
.7*
|
|
Form of NRG Energy, Inc. Long Term Incentive Plan Performance
Unit Agreement.(1)
|
|
|
|
|
|
|
10
|
.8*
|
|
Annual Incentive Plan for Designated Corporate Officers.(43)
|
239
|
|
|
|
|
|
|
|
|
|
|
10
|
.9
|
|
Railroad Car Full Service Master Leasing Agreement, dated as of
February 18, 2005, between General Electric Railcar
Services Corporation and NRG Power Marketing Inc.(15)
|
|
|
|
|
|
|
10
|
.10
|
|
Purchase Agreement (West Coast Power) dated as of
December 27, 2005, by and among NRG Energy, Inc., NRG West
Coast LLC (Buyer), DPC II Inc. (Seller) and Dynegy, Inc.(14)
|
|
|
|
|
|
|
10
|
.11
|
|
Purchase Agreement (Rocky Road Power), dated as of
December 27, 2005, by and among Termo Santander Holding,
L.L.C.(Buyer), Dynegy, Inc., NRG Rocky Road LLC (Seller) and NRG
Energy, Inc.(14)
|
|
|
|
|
|
|
10
|
.12
|
|
Stock Purchase Agreement, dated as of August 10, 2005, by
and between NRG Energy, Inc. and Credit Suisse First Boston
Capital LLC.(17)
|
|
|
|
|
|
|
10
|
.13
|
|
Agreement with respect to the Stock Purchase Agreement, dated
December 19, 2008, by and between NRG Energy, Inc. and
Credit Suisse First Boston Capital LLC.(37)
|
|
|
|
|
|
|
10
|
.14
|
|
Investor Rights Agreement, dated as of February 2, 2006, by
and among NRG Energy, Inc. and Certain Stockholders of NRG
Energy, Inc. set forth therein.(21)
|
|
|
|
|
|
|
10
|
.15
|
|
Terms and Conditions of Sale, dated as of October 5, 2005,
between Texas Genco II LP and Freight Car America, Inc.,
(including the Proposal Letter and Amendment thereto).(25)
|
|
|
|
|
|
|
10
|
.16*
|
|
Amended and Restated Employment Agreement, dated
December 4, 2008, between NRG Energy, Inc. and David
Crane.(37)
|
|
|
|
|
|
|
10
|
.17*
|
|
CEO Compensation Table.(48)
|
|
|
|
|
|
|
10
|
.18
|
|
Limited Liability Company Agreement of NRG Common Stock Finance
I LLC.(27)
|
|
|
|
|
|
|
10
|
.19
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG
Common Stock Finance I LLC, Credit Suisse International and
Credit Suisse Securities (USA) LLC.(27)
|
|
|
|
|
|
|
10
|
.20
|
|
Amendment Agreement, dated February 27, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(36)
|
|
|
|
|
|
|
10
|
.21
|
|
Amendment Agreement, dated August 8, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(37)
|
|
|
|
|
|
|
10
|
.22
|
|
Amendment Agreement, dated December 19, 2008, to the Note
Purchase Agreement by and among NRG Common Stock Finance I LLC,
Credit Suisse International, and Credit Suisse Securities (USA)
LLC.(37)
|
|
|
|
|
|
|
10
|
.23
|
|
Agreement with respect to Note Purchase Agreement, dated
December 19, 2008, by and among NRG Common Stock Finance I
LLC, Credit Suisse International, and Credit Suisse Securities
(USA) LLC.(37)
|
|
|
|
|
|
|
10
|
.24
|
|
Preferred Interest Purchase Agreement, dated August 4,
2006, between NRG Common Stock Finance I LLC, Credit Suisse
Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(27)
|
|
|
|
|
|
|
10
|
.25
|
|
Preferred Interest Amendment Agreement, dated February 27,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(36)
|
|
|
|
|
|
|
10
|
.26
|
|
Preferred Interest Amendment Agreement, dated August 8,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(37)
|
|
|
|
|
|
|
10
|
.27
|
|
Preferred Interest Amendment Agreement, dated December 19,
2008, by and among NRG Common Stock Finance I LLC, Credit Suisse
International, and Credit Suisse Securities (USA) LLC.(37)
|
|
|
|
|
|
|
10
|
.28
|
|
Agreement with respect to Preferred Interest Purchase Agreement,
dated December 19, 2008, by and among NRG Common Stock
Finance I LLC, Credit Suisse International, and Credit Suisse
Securities (USA) LLC.(37)
|
240
|
|
|
|
|
|
|
|
|
|
|
10
|
.29
|
|
Second Amended and Restated Credit Agreement, dated June 8,
2007, by and among NRG Energy, Inc., the lenders party thereto,
Citigroup Global Markets Inc., Credit Suisse Securities (USA)
LLC, Citicorp North America Inc. and Credit Suisse.(32)
|
|
|
|
|
|
|
10
|
.30*
|
|
Amended and Restated Long-Term Incentive Plan(43)
|
|
|
|
|
|
|
10
|
.31*
|
|
NRG Energy, Inc. Executive
Change-in-Control
and General Severance Agreement, dated December 9, 2008.(37)
|
|
|
|
|
|
|
10
|
.32
|
|
Amended and Restated Contribution Agreement (NRG), dated
March 25, 2008, by and among Texas Genco Holdings, Inc.,
NRG South Texas LP and NRG Nuclear Development Company LLC and
Certain Subsidiaries Thereof.(36)
|
|
|
|
|
|
|
10
|
.33
|
|
Contribution Agreement (Toshiba), dated February 29, 2008,
by and between Toshiba Corporation and NRG Nuclear Development
Company LLC.(36)
|
|
|
|
|
|
|
10
|
.34
|
|
Multi-Unit
Agreement, dated February 29, 2008, by and among Toshiba
Corporation, NRG Nuclear Development Company LLC and NRG Energy,
Inc.(36)
|
|
|
|
|
|
|
10
|
.35
|
|
Amended and Restated Operating Agreement of Nuclear Innovation
North America LLC, dated May 1, 2008(36)
|
|
|
|
|
|
|
10
|
.36
|
|
Credit Agreement by and among Nuclear Innovation North America
LLC, Nuclear Innovation North America Investments LLC, NINA
Texas 3 LLC and NINA Texas 4 LLC, as Borrowers and Toshiba
America Nuclear Energy Corporation, as Administrative Agent and
as Collateral Agent.(38)
|
|
|
|
|
|
|
10
|
.37
|
|
LLC Membership Purchase Agreement between Reliant Energy, Inc.
and NRG Retail LLC, dated as of February 28, 2009.(39)
|
|
|
|
|
|
|
12
|
.1
|
|
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed
Charges.(1)
|
|
|
|
|
|
|
12
|
.2
|
|
NRG Energy, Inc. Computation of Ratio of Earnings to Fixed
Charges and Preferred Stock Dividend Requirements.(1)
|
|
|
|
|
|
|
21
|
.1
|
|
Subsidiaries of NRG Energy. Inc.(1)
|
|
|
|
|
|
|
23
|
.1
|
|
Consent of KPMG LLP.(1)
|
|
|
|
|
|
|
31
|
.1
|
|
Rule 13a-14(a)/15d-14(a)
certification of David W. Crane.(1)
|
|
|
|
|
|
|
31
|
.2
|
|
Rule 13a-14(a)/15d-14(a)
certification of Gerald Luterman.(1)
|
|
|
|
|
|
|
31
|
.3
|
|
Rule 13a-14(a)/15d-14(a)
certification of James J. Ingoldsby.(1)
|
|
|
|
|
|
|
32
|
|
|
Section 1350 Certification.(1)
|
|
|
|
|
|
|
101
|
.INS
|
|
XBRL Instance Document(1)
|
|
|
|
|
|
|
101
|
.SCH
|
|
XBRL Taxonomy Extension Schema(1)
|
|
|
|
|
|
|
101
|
.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase(1)
|
|
|
|
|
|
|
101
|
.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase(1)
|
|
|
|
|
|
|
101
|
.LAB
|
|
XBRL Taxonomy Extension Label Linkbase(1)
|
|
|
|
|
|
|
101
|
.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase(1)
|
|
|
|
* |
|
Exhibit relates to compensation arrangements. |
|
|
Portions of this exhibit have been redacted and are subject to a
confidential treatment request filed with the Secretary of the
Securities and Exchange Commission pursuant to
Rule 24b-2
under the Securities Exchange Act of 1934, as amended. |
(1) |
|
Filed herewith. |
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 16, 2004. |
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 31, 2003. |
241
|
|
|
(4) |
|
Incorporated herein by reference to NRG Energy Inc.s
Registration Statement on
Form S-1,
as amended, Registration
No. 333-33397. |
(5) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 19, 2003. |
(6) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended September 30, 2004. |
(7) |
|
Incorporated herein by reference to NRG Energy, Inc.s 2004
proxy statement on Scheduleb14A filed on July 12, 2004. |
(8) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended March 31, 2004. |
(9) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on October 3, 2005. |
(10) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
for the quarter ended June 30, 2005. |
(11) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on January 4, 2006. |
(12) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 28, 2005. |
(13) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 30, 2005. |
(14) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 24, 2005. |
(15) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 11, 2005. |
(16) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 3, 2005. |
(17) |
|
Incorporated herein by reference to NRG Energy, Inc.s
Form 8-A
filed on January 27, 2006. |
(18) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on February 6, 2006. |
(19) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on February 8, 2006. |
(20) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on March 16, 2006. |
(21) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 3, 2006. |
(22) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on May 4, 2006. |
(23) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on March 7, 2006. |
(24) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on August 4, 2006. |
(25) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 10, 2006. |
(26) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 14, 2006. |
(27) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on November 27, 2006. |
(28) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 26, 2007. |
(29) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on May 2, 2007. |
(30) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on June 13, 2007. |
242
|
|
|
(31) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on July 20, 2007. |
(32) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on September 4, 2007. |
(33) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on February 28, 2008. |
(34) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on May 1, 2008. |
(35) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on October 30, 2008. |
(36) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 9, 2008. |
(37) |
|
Incorporated herein by reference to NRG Energy, Inc.s
annual report on
Form 10-K
filed on February 12, 2009. |
(38) |
|
Incorporated herein by reference to NRG Energy Incs
current report on
Form 8-K
filed on February 27, 2009. |
(39) |
|
Incorporated herein by reference to NRG Energy, Inc.s
quarterly report on
Form 10-Q
filed on April 30, 2009. |
(40) |
|
Incorporated herein by reference to NRG Energy, Incs
current report on
Form 8-K
filed on May 4, 2009. |
(41) |
|
Incorporated herein by reference to NRG Energy, Incs
current report on
Form 8-K
filed on May 14, 2009. |
(42) |
|
Incorporated herein by reference to NRG Energy, Incs
current report on
Form 8-K
filed on June 5, 2009. |
(43) |
|
Incorporated herein by reference to NRG Energy, Inc.s 2009
proxy statement on Schedule 14A filed on June 16, 2009. |
(44) |
|
Incorporated herein by reference to NRG Energy, Incs
current report on
Form 8-K
filed on July 15, 2009. |
(45) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on August 4, 2009. |
(46) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on October 6, 2009. |
(47) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on October 21, 2009. |
(48) |
|
Incorporated herein by reference to NRG Energy, Inc.s
current report on
Form 8-K
filed on December 9, 2009. |
243