10-Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
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For the quarterly period ended: March 31, 2007
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Commission File Number: 001-15891 |
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
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Delaware
(State or other jurisdiction
of incorporation or organization)
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41-1724239
(I.R.S. Employer
Identification No.) |
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211 Carnegie Center
Princeton, New Jersey
(Address of principal executive offices)
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08540
(Zip Code) |
(609) 524-4500
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such period that the Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer or a non-accelerated filer (as defined in Rule 12 b-2 of the Exchange Act).
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act).
Yes o No þ
Indicate by check mark whether the registrant has filed all documents and reports required to
be filed by Section 12, 13 or 15 (d) of the Securities and Exchange Act of 1934 subsequent to the
distribution of securities under a plan confirmed by a court.
Yes þ No o
As of April 27, 2007, there were 121,158,437 shares of common stock outstanding, par value
$0.01 per share.
TABLE OF CONTENTS
Index
2
CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of
Section 27A of the Securities Act and Section 21E of the Exchange Act. The words believes,
projects, anticipates, plans, expects, intends, estimates and similar expressions are
intended to identify forward-looking statements. These forward-looking statements involve known and
unknown risks, uncertainties and other factors which may cause NRGs actual results, performance
and achievements, or industry results, to be materially different from any future results,
performance or achievements expressed or implied by such forward-looking statements. These factors,
risks and uncertainties include the factors described under Risks Related to NRG in Part II, Item
1A, of the Companys Annual Report on Form 10-K and the following:
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General economic conditions, changes in the wholesale power markets and fluctuations in
the cost of fuel; |
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Hazards customary to the power production industry and power generation operations such
as fuel and electricity price volatility, unusual weather conditions, catastrophic
weather-related or other damage to facilities, unscheduled generation outages, maintenance
or repairs, unanticipated changes to fuel supply costs or availability due to higher demand,
shortages, transportation problems or other developments, environmental incidents, or
electric transmission or gas pipeline system constraints and the possibility that NRG may
not have adequate insurance to cover losses as a result of such hazards; |
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The effectiveness of NRGs risk management policies and procedures, and the ability of
NRGs counterparties to satisfy their financial commitments; |
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Counterparties collateral demands and other factors affecting NRGs liquidity position
and financial condition; |
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NRGs ability to operate its businesses efficiently, manage capital expenditures and
costs tightly (including general and administrative expenses), and generate earnings and
cash flows from its asset-based businesses in relation to its debt and other obligations; |
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NRGs potential inability to enter into contracts to sell power and procure fuel on acceptable terms and prices; |
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The liquidity and competitiveness of wholesale markets for energy commodities; |
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Government regulation, including compliance with regulatory requirements and changes in
market rules, rates, tariffs and environmental laws; |
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Price mitigation strategies and other market structures employed by independent system
operators, or ISOs, or regional transmission organizations, or RTOs, that result in a
failure to adequately compensate NRGs generation units for all of its costs; |
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NRGs ability to borrow additional funds and access capital markets, as well as NRGs
substantial indebtedness and the possibility that NRG may incur additional indebtedness
going forward; |
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Operating and financial restrictions placed on NRG 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; and |
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NRGs ability to implement its RepoweringNRG strategy of developing and building new
power generation facilities, including new nuclear units and IGCC units. |
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NRGs ability to consummate or achieve the expected benefits of the Comprehensive Capital
Allocation Plan as described in this quarterly report. |
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 Quarterly Report on Form 10-Q should not be construed as exhaustive.
3
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the
meanings indicated below:
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Acquisition
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February 2, 2006 acquisition of Texas Genco LLC, now referred to as the Companys Texas
region |
ARO
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Asset Retirement Obligation |
BACT
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Best Available Control Technology |
Baseload capacity
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Electric power generation capacity normally expected to serve loads on an
around-the-clock basis throughout the calendar year |
BTA
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Best Technology Available |
BTU
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British Thermal Unit |
CAA
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Clean Air Act |
CAIR
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Clean Air Interstate Rule |
CAISO
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California Independent System Operator |
CAMR
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Clean Air Mercury Rule |
Capital Allocation Program
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Share repurchase program entered into in August 2006 |
Capacity factor
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The ratio of the actual net electricity generated to the energy that could have been
generated at continuous full-power operation during the year |
Comprehensive Capital Allocation Plan
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A comprehensive plan to support and facilitate the Companys capital allocation strategy
that includes a holding company structure to enable the distribution of cash dividend on
the Companys common stock, the pay down of debt, a stock split, and the Capital Allocation Program |
CDWR
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California Department of Water Resources |
CL&P
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Connecticut Light & Power |
CO2
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Carbon dioxide |
CPUC
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California Public Utilities Commission |
DNREC
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Delaware Department of Natural Resources and Environmental Control |
EFOR
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Equivalent Forced Outage Rates considers the equivalent impact that forced
de-ratings have in addition to full forced outages |
EITF
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Emerging Issues Task Force |
EITF 02-3
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EITF Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management
Activities |
EPC
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Engineering, Procurement and Construction |
ERCOT
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Electric Reliability Council of Texas, the Independent System Operator and the
regional reliability coordinator of the various electricity systems within Texas |
FASB
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Financial Accounting Standards Board, the designated organization for establishing
standards for financial accounting and reporting |
FCM
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Forward Capacity Market |
FERC
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Federal Energy Regulatory Commission |
FIN
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FASB Interpretation |
GHG
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Greenhouse Gases |
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 |
IGCC
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Integrated Gasification Combined Cycle |
ISO
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Independent System Operator, also referred to as Regional Transmission Organization, or
RTO |
ISO-NE
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ISO New England, Inc. |
ITISA
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Itiquira Energetica S.A. |
kW
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Kilowatts |
KWh
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Kilowatt-hours |
Letter
of Credit Facility |
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NRGs $1.5 billion senior secured
synthetic letter of credit facility which matures on February 1,
2013 |
LFRM
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Locational Forward Reserve Market |
LIBOR
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London Inter-Bank Offered Rate |
Merit Order
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A term used for the ranking of power stations in terms of increasing order of fuel costs. |
MMBtu
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Million British Thermal Units |
MW
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Megawatts |
MWh
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Saleable megawatt hours net of internal/parasitic load megawatt-hours |
NEPOOL
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New England Power Pool |
New York Rest of State
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New York State excluding New York City |
4
GLOSSARY OF TERMS contd
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NiMo
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Niagara Mohawk Power Corporation |
NOx
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Nitrogen oxide |
NOL
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Net Operating Loss |
NOV
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Notice of Violation |
NPNS
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Normal Purchase Normal Sale |
NSR
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New Source Review |
NYISO
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New York Independent System Operator |
OCI
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Other Comprehensive Income |
Phase II 316(b) Rule
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A section of the Clean Water Act regulating cooling water intake structures |
PJM
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PJM Interconnection, LLC |
PJM Market
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The wholesale and retail electric market operated by PJM primarily in all or parts of
Delaware, the District of Columbia, Illinois, Maryland, New Jersey, Ohio,
Pennsylvania, Virginia and West Virginia |
PMI
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NRG Power Marketing, Inc., 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 |
Powder River Basin, or PRB, Coal
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Coal produced in the northeastern Wyoming and southeastern Montana, which has low
sulfur content |
PPA
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Power Purchase Agreement |
PSD
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Prevention of Significant Deterioration |
PUSH
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Peaking Unit Safe Harbor |
RepoweringNRG
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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. |
Revolving
Credit Facility
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NRGs $1 billion senior
secured credit facility which matures on February 2, 2011 |
RMR
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Reliability Must-Run |
RTO
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Regional Transmission Organization, also referred to as an ISO |
Sarbanes-Oxley
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Sarbanes-Oxley Act of 2002 |
SEC
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United States Securities and Exchange Commission |
Senior
Credit Facility
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NRGs senior secured facility,
which is comprised of a $3.1 billion Term B loan facility which
matures on February 1, 2013, its $1.5 billion Letter of
Credit Facility, and its $1 billion Revolving Credit Facility |
SERC
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Southeastern Electric Reliability Council/ Entergy |
SFAS
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Statement of Financial Accounting Standards issued by the FASB |
SFAS 71
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SFAS No. 71 Accounting for the Effects of Certain Types of Regulation |
SFAS 109
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SFAS No. 109, Accounting for Income Taxes |
SFAS 123
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SFAS No. 123, Accounting for Stock-Based Compensation |
SFAS 123R
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SFAS No. 123 (revised 2004), Share-Based Payment |
SFAS 133
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SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities |
SFAS 142
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SFAS No. 142, Goodwill and Other Intangible Assets |
SFAS 144
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SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets |
SFAS 158
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SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other
Postretirement Plans an amendment of FASB Statements No. 87, 88, 106 and 132(R) |
SO2
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Sulfur dioxide |
SOP
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Statement of Position issued by the American Institute of Certified Public Accountants |
SOP 90-7
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Statement of Position 90-7 Financial Reporting by Entities in Reorganization Under
the Bankruptcy Code |
STP
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South Texas Project Nuclear generating facility located near Bay City, Texas in
which NRG owns a 44% interest |
Texas Genco
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Texas Genco LLC, now referred to as the Companys Texas region |
Uprate
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A sustainable increase in the electrical rating of a generating facility |
US
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United States of America |
USEPA
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United States Environmental Protection Agency |
U.S. GAAP
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Accounting principles generally accepted in the United States |
VAR
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Value at Risk |
WCP
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West Coast Power (Generation)
Holdings, LLC |
5
PART I FINANCIAL INFORMATION
ITEM 1 CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
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(In millions except per share amounts) |
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Three months ended March 31, |
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2007 |
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2006 |
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Operating Revenues |
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Total operating revenues |
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$ |
1,310 |
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$ |
1,043 |
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Operating Costs and Expenses |
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Cost of operations |
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784 |
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659 |
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Depreciation and amortization |
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161 |
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118 |
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General and administrative |
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86 |
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57 |
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Development costs |
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23 |
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Total operating costs and expenses |
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1,054 |
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834 |
|
Gain on sale of assets |
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17 |
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Operating Income |
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273 |
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209 |
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Other Income/(Expense) |
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Equity in earnings of unconsolidated affiliates |
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13 |
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21 |
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Write down of equity method investments |
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(3 |
) |
Other income, net |
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16 |
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80 |
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Refinancing expenses |
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(178 |
) |
Interest expense |
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|
(181 |
) |
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(115 |
) |
|
Total other expenses |
|
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(152 |
) |
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|
(195 |
) |
|
Income From Continuing Operations Before Income Taxes |
|
|
121 |
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14 |
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Income tax expense/(benefit) |
|
|
56 |
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(1 |
) |
|
Income From Continuing Operations |
|
|
65 |
|
|
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15 |
|
Income on Discontinued Operations, net of Income Taxes |
|
|
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|
11 |
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Net Income |
|
$ |
65 |
|
|
$ |
26 |
|
Preference stock dividends |
|
|
14 |
|
|
|
10 |
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|
Income Available for Common Stockholders |
|
$ |
51 |
|
|
$ |
16 |
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|
Weighted Average Number of Common Shares Outstanding Basic |
|
|
122 |
|
|
|
117 |
|
Income From Continuing Operations
per Weighted Average Common Share Basic |
|
$ |
0.42 |
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$ |
0.04 |
|
Income From Discontinued Operations
per Weighted Average Common Share Basic |
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|
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0.09 |
|
Net Income per Weighted Average Common Share Basic |
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$ |
0.42 |
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$ |
0.13 |
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Weighted Average Number of Common Shares Outstanding Diluted |
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135 |
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119 |
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Income From Continuing Operations
per Weighted Average Common Share Diluted |
|
$ |
0.41 |
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$ |
0.04 |
|
Income From Discontinued Operations
per Weighted Average Common Share Diluted |
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0.09 |
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Net Income per Weighted Average Common Share Diluted |
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$ |
0.41 |
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$ |
0.13 |
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See notes to condensed consolidated financial statements.
6
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
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March 31, 2007 |
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December 31, 2006 |
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(in millions, except shares and par value) |
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(unaudited) |
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ASSETS
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Current Assets |
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Cash and cash equivalents |
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$ |
655 |
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$ |
795 |
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Restricted cash |
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49 |
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44 |
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Accounts receivable, less allowance for doubtful accounts of $1 and $1 |
|
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409 |
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372 |
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Inventory |
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400 |
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421 |
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Derivative instruments valuation |
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854 |
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1,230 |
|
Deferred income taxes |
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43 |
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Prepayments and other current assets |
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259 |
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221 |
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Total current assets |
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2,669 |
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3,083 |
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Property, plant and equipment, net of accumulated depreciation of $1,159 and $984 |
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11,521 |
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11,600 |
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Other Assets |
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Equity investments in affiliates |
|
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361 |
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344 |
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Notes receivable and capital lease, less current portion |
|
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476 |
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479 |
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Goodwill |
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1,787 |
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1,789 |
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Intangible assets, net of accumulated amortization of $292 and $259 |
|
|
958 |
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|
981 |
|
Nuclear decommissioning trust fund |
|
|
357 |
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|
|
352 |
|
Derivative instruments valuation |
|
|
187 |
|
|
|
439 |
|
Deferred income taxes |
|
|
27 |
|
|
|
27 |
|
Other non-current assets |
|
|
256 |
|
|
|
262 |
|
Intangible assets held-for-sale |
|
|
112 |
|
|
|
79 |
|
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Total other assets |
|
|
4,521 |
|
|
|
4,752 |
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Total Assets |
|
$ |
18,711 |
|
|
$ |
19,435 |
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|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
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Current portion of long-term debt and capital leases |
|
$ |
129 |
|
|
$ |
130 |
|
Accounts payable |
|
|
295 |
|
|
|
332 |
|
Derivative instruments valuation |
|
|
824 |
|
|
|
964 |
|
Deferred income taxes |
|
|
|
|
|
|
164 |
|
Accrued expenses and other current liabilities |
|
|
320 |
|
|
|
442 |
|
|
Total current liabilities |
|
|
1,568 |
|
|
|
2,032 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
8,637 |
|
|
|
8,647 |
|
Nuclear decommissioning reserve |
|
|
280 |
|
|
|
289 |
|
Nuclear decommissioning trust liability |
|
|
335 |
|
|
|
324 |
|
Deferred income taxes |
|
|
623 |
|
|
|
554 |
|
Derivative instruments valuation |
|
|
418 |
|
|
|
351 |
|
Out-of-market contracts |
|
|
839 |
|
|
|
897 |
|
Other non-current liabilities |
|
|
437 |
|
|
|
435 |
|
|
Total non-current liabilities |
|
|
11,569 |
|
|
|
11,497 |
|
|
Total Liabilities |
|
|
13,137 |
|
|
|
13,529 |
|
|
Minority Interest |
|
|
1 |
|
|
|
1 |
|
3.625% Convertible perpetual preferred stock (at liquidation value, net of issuance costs) |
|
|
247 |
|
|
|
247 |
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock (at liquidation value, net of issuance costs) |
|
|
892 |
|
|
|
892 |
|
Common Stock |
|
|
1 |
|
|
|
1 |
|
Additional paid-in capital |
|
|
4,469 |
|
|
|
4,476 |
|
Retained earnings |
|
|
790 |
|
|
|
739 |
|
Less treasury stock, at cost 16,300,581 and 14,800,581 shares |
|
|
(835 |
) |
|
|
(732 |
) |
Accumulated other comprehensive income |
|
|
9 |
|
|
|
282 |
|
|
Total Stockholders Equity |
|
|
5,326 |
|
|
|
5,658 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
18,711 |
|
|
$ |
19,435 |
|
|
See notes to condensed consolidated financial statements.
7
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
65 |
|
|
$ |
26 |
|
Adjustments to reconcile net income to net cash provided by operating activities |
|
|
|
|
|
|
|
|
Distributions less than equity in earnings of unconsolidated affiliates |
|
|
(10 |
) |
|
|
(12 |
) |
Depreciation and amortization of nuclear fuel |
|
|
174 |
|
|
|
125 |
|
Amortization and write-off of financing costs and debt discount/premiums |
|
|
9 |
|
|
|
57 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(29 |
) |
|
|
9 |
|
Changes in deferred income taxes |
|
|
47 |
|
|
|
46 |
|
Changes in nuclear decommissioning trust liability |
|
|
9 |
|
|
|
(3 |
) |
Changes in derivatives |
|
|
90 |
|
|
|
(21 |
) |
Changes in collateral deposits supporting energy risk management activities |
|
|
(120 |
) |
|
|
230 |
|
Gain on sale of assets |
|
|
(17 |
) |
|
|
|
|
Gain on legal settlement |
|
|
|
|
|
|
(67 |
) |
Gain on sale of discontinued operations |
|
|
|
|
|
|
(10 |
) |
Gain on sale of emission allowances |
|
|
(5 |
) |
|
|
(59 |
) |
Amortization of unearned equity compensation |
|
|
7 |
|
|
|
3 |
|
Write down of equity method investments |
|
|
|
|
|
|
3 |
|
Cash provided/(used) by changes in other working capital, net of acquisition and disposition affects |
|
|
(114 |
) |
|
|
15 |
|
|
Net Cash Provided by Operating Activities |
|
|
106 |
|
|
|
342 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
Acquisition of Texas Genco LLC, net of cash acquired |
|
|
|
|
|
|
(4,263 |
) |
Acquisition of WCP, net of cash acquired |
|
|
|
|
|
|
(25 |
) |
Capital expenditures |
|
|
(107 |
) |
|
|
(35 |
) |
Increase in restricted cash, net |
|
|
(5 |
) |
|
|
(3 |
) |
Decrease in notes receivable |
|
|
9 |
|
|
|
8 |
|
Purchases of emission allowances |
|
|
(61 |
) |
|
|
(15 |
) |
Proceeds from sale of emission allowances |
|
|
32 |
|
|
|
68 |
|
Investments in nuclear decommissioning trust fund securities |
|
|
(68 |
) |
|
|
(42 |
) |
Proceeds from sales of nuclear decommissioning trust fund securities |
|
|
59 |
|
|
|
45 |
|
Proceeds from sale of assets |
|
|
29 |
|
|
|
|
|
Proceeds from sale of investments |
|
|
|
|
|
|
45 |
|
Proceeds from sale of discontinued operations |
|
|
|
|
|
|
15 |
|
|
Net Cash Used by Investing Activities |
|
|
(112 |
) |
|
|
(4,202 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
(14 |
) |
|
|
(10 |
) |
Payment of financing element of acquired derivatives |
|
|
|
|
|
|
(29 |
) |
Payment for treasury stock |
|
|
(103 |
) |
|
|
|
|
Funded letter of credit |
|
|
|
|
|
|
350 |
|
Proceeds from issuance of common stock, net of issuance costs |
|
|
|
|
|
|
986 |
|
Proceeds from issuance of preferred shares, net of issuance costs |
|
|
|
|
|
|
486 |
|
Proceeds from issuance of long-term debt |
|
|
|
|
|
|
7,175 |
|
Payment of deferred debt issuance costs |
|
|
|
|
|
|
(164 |
) |
Payments for short and long-term debt |
|
|
(19 |
) |
|
|
(4,623 |
) |
|
Net Cash Provided/(Used) by Financing Activities |
|
|
(136 |
) |
|
|
4,171 |
|
|
Change in Cash from Discontinued Operations |
|
|
|
|
|
|
(17 |
) |
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
|
|
2 |
|
|
|
1 |
|
|
Net Increase/(Decrease) in Cash and Cash Equivalents |
|
|
(140 |
) |
|
|
295 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
795 |
|
|
|
493 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
655 |
|
|
$ |
788 |
|
|
See notes to condensed consolidated financial statements.
8
NRG ENERGY, INC.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 Basis of Presentation
NRG Energy, Inc., or NRG or the Company, is a wholesale power generation company with a
significant presence in major competitive power markets in the United States. NRG is primarily
engaged in the ownership, development, construction and operation of power generation facilities,
the transacting in and trading of fuel and transportation services, and the trading of energy,
capacity and related products in the United States and internationally.
The accompanying unaudited interim consolidated financial statements have been prepared in
accordance with the Securities and Exchange Commissions regulations for interim financial
information and with the instructions to Form 10-Q. Accordingly, they do not include all of the
information and notes required by generally accepted accounting principles for complete financial
statements. The accounting policies NRG follows are set forth in Note 2 to the Companys financial
statements in its Annual Report on Form 10-K for the year ended December 31, 2006. The following
notes should be read in conjunction with such policies and other disclosures in the Form 10-K.
Interim results are not necessarily indicative of results for a full year.
In the opinion of management, the accompanying unaudited interim consolidated financial
statements contain all material adjustments consisting of normal and recurring accruals necessary
to present fairly the Companys consolidated financial position as of March 31, 2007, and the
results of operations and cash flows for the three months ended March 31, 2007 and 2006. Certain
prior-year amounts have been reclassified for comparative purposes.
Use of Estimates
The preparation of consolidated financial statements in accordance with generally accepted
accounting principles requires management to make estimates and assumptions. These estimates and
assumptions impact the reported amount of assets and liabilities and disclosures of contingent
assets and liabilities as of the date of the consolidated financial statements. They also impact
the reported amount of net earnings during the reporting period. Actual results could be different
from these estimates.
Recent Accounting Developments
In July 2006, the FASB issued FASB Interpretation Number 48, Accounting for Uncertainty in
Income Taxes an interpretation of FASB Statement No. 109, or FIN 48, which applies to all tax
positions related to income taxes subject to SFAS 109. FIN 48 requires a new evaluation process
for all tax positions taken, recognizing tax benefits 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. Differences between the amounts recognized in the
statement of financial position prior to the adoption of FIN 48 and the amounts reported after
adoption are to be accounted for as an adjustment to the beginning balance of retained earnings.
Subsequently, any such differences will be recorded as a charge to income tax expense. The Company
recognizes interest and penalties accrued related to unrecognized tax benefits as a component of
income tax expense. As of March 31, 2007, the Company had completed its evaluation of the impact
of the January 1, 2007, adoption of FIN 48 and has determined that such adoption will not have a
material impact on the Companys financial position, results of operations and cash flows.
Note 2 Comprehensive Income
The following table summarizes the components of the Companys comprehensive income for the
three months ended March 31, 2007 and 2006.
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Net income |
|
$ |
65 |
|
|
$ |
26 |
|
Changes in derivative activity, net of tax |
|
|
(283 |
) |
|
|
247 |
|
Foreign currency translation adjustment |
|
|
10 |
|
|
|
3 |
|
|
Other comprehensive income, net of tax |
|
|
(273 |
) |
|
|
250 |
|
|
Comprehensive income/(loss) |
|
$ |
(208 |
) |
|
$ |
276 |
|
|
9
The following table summarizes the changes in the Companys accumulated other comprehensive
income for the three months ended March 31, 2007:
|
|
|
|
|
(In millions) |
|
|
|
As of March 31, |
|
2007 |
|
|
Accumulated other comprehensive income as of December 31, 2006 |
|
$ |
282 |
|
Changes in derivative activity, net of tax |
|
|
(283 |
) |
Foreign currency translation adjustments |
|
|
10 |
|
|
Accumulated other comprehensive income as of March 31, 2007 |
|
$ |
9 |
|
|
Note 3 Business Acquisitions and Dispositions
Acquisition of Remaining 50% interest in WCP
On March 31, 2006, NRG completed purchase and sale agreements for projects co-owned with
Dynegy, Inc. Under the agreements, NRG acquired Dynegys 50% ownership interest in WCP (Generation)
Holdings, LLC., or WCP, for $205 million in cash and the assumption of a $1 million liability, with
NRG becoming the sole owner of WCPs 1,825 MW of generation capacity in Southern California. In
addition, NRG sold to Dynegy the Companys 50% ownership interest in Rocky Road Power LLC, or Rocky
Road, a 330 MW gas-fueled, simple cycle peaking plant located in Dundee, Illinois. NRG sold Rocky
Road for a fair value sale price of $45 million, paying Dynegy a net purchase price of $160 million
at closing. Prior to the purchase, NRG had an existing investment in WCP accounted for as an equity
method investment, or Original Investment.
The acquisition of the remaining 50% interest in WCP, or New Investment, was accounted for as
a step acquisition since the Original Investment was transacted in a prior period. As a result, the
value of the Original Investment and the purchase price of the New Investment were determined and
allocated separately. The value of the Original Investment was based on the book value of
approximately $159 million as of the date of the acquisition of the New Investment.
The value of the New Investment was allocated based on the fair value of assets acquired and
liabilities assumed as of March 31, 2006. The purchase price allocation reflected an excess of fair
value of the net assets acquired over the purchase price of the New Investment, resulting in
negative goodwill of approximately $48 million. The negative goodwill was subsequently allocated as
a reduction to the fair value of WCPs fixed assets.
The following summarizes the purchase price and allocation impact of the WCP acquisition as of
March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Investment |
|
|
|
|
|
|
|
|
|
|
Fair Value before |
|
|
|
|
|
|
Fair Value after |
|
|
|
|
|
|
Original |
|
|
Negative Goodwill |
|
|
Allocation of |
|
|
Negative Goodwill |
|
|
|
|
(in millions) |
|
Investment |
|
|
Allocation |
|
|
Negative Goodwill |
|
|
Allocation |
|
|
Purchase Price Allocation |
|
|
Current assets |
|
$ |
149 |
|
|
$ |
153 |
|
|
$ |
|
|
|
$ |
153 |
|
|
$ |
302 |
|
Property, plant and equipment |
|
|
24 |
|
|
|
103 |
|
|
|
(38 |
) |
|
|
65 |
|
|
|
89 |
|
Intangible assets |
|
|
2 |
|
|
|
26 |
|
|
|
(10 |
) |
|
|
16 |
|
|
|
18 |
|
Other non-current assets |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
9 |
|
|
|
9 |
|
Current liabilities |
|
|
(13 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
(18 |
) |
|
|
(31 |
) |
Non-current liabilities |
|
|
(3 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
(19 |
) |
|
|
(22 |
) |
Negative goodwill |
|
|
|
|
|
|
(48 |
) |
|
|
48 |
|
|
|
|
|
|
|
|
|
|
Total Equity |
|
$ |
159 |
|
|
$ |
206 |
|
|
$ |
|
|
|
$ |
206 |
|
|
$ |
365 |
|
|
Other Business Events
Red Bluff and Chowchilla On January 3, 2007, NRG completed the sale of the Companys Red
Bluff and Chowchilla II power plants to an entity controlled by Wayzata Investment Partners LLC.
These power plants, located in California, are fueled by natural gas, with generating capacity of
45 MW and 49 MW, respectively. The sale resulted in a pre-tax gain of approximately $18 million.
Note 4 Discontinued Operations
NRG has classified material business operations and gains/losses recognized on sale, as
discontinued operations for projects that were sold or have met the required criteria for such
classification. The financial results for the affected businesses have been
10
accounted for as discontinued operations. Accordingly, prior periods have been recast to
report the operations as discontinued. NRG classifies certain assets as held-for-sale when
management has committed to selling certain long lived assets within the next year. This
classification does not affect prior period operating results.
For the three months ended March 31, 2006, discontinued operations consisted of the results
related to the Companys Audrain, Flinders and Resource Recovery operations. NRG had no assets
classified as discontinued operations for the three months ended March 31, 2007.
Summarized results of operations of the Companys discontinued operations were as follows:
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Operating revenues |
|
$ |
|
|
|
$ |
68 |
|
Pre-tax income from operations of discontinued components |
|
|
|
|
|
|
2 |
|
Income from discontinued operations, net of income taxes |
|
$ |
|
|
|
$ |
11 |
|
|
Note 5 Accounting for Derivative Instruments and Hedging Activities
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, or
SFAS 133, requires NRG to recognize all derivative instruments on the balance sheet as either
assets or liabilities and to measure them at fair value each reporting period unless they qualify
for a Normal Purchase Normal Sale, or NPNS, exception. If certain conditions are met, NRG may be
able to designate certain derivatives as cash flow hedges and defer the effective portion of the
change in fair value of the derivatives to OCI and subsequently recognize in earnings when the
hedged transaction occurs. The ineffective portion of a cash flow hedge is immediately recognized
in earnings.
Accumulated Other Comprehensive Income
The following table summarizes the effects of SFAS 133 on NRGs OCI balance attributable to
hedged derivatives for the three months ended March 31, 2007, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
|
Rate |
|
|
Total |
|
|
Accumulated OCI balance at December 31, 2006 |
|
$ |
193 |
|
|
$ |
16 |
|
|
$ |
209 |
|
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
(17 |
) |
|
|
|
|
|
|
(17 |
) |
Mark-to-market of hedge contracts |
|
|
(259 |
) |
|
|
(7 |
) |
|
|
(266 |
) |
|
Accumulated OCI balance at March 31, 2007 |
|
$ |
(83 |
) |
|
$ |
9 |
|
|
$ |
(74 |
) |
|
Losses expected to be realized from OCI during the next 12 months |
|
$ |
4 |
|
|
$ |
|
|
|
$ |
4 |
|
|
The following table summarizes the effects of SFAS 133 on NRGs OCI balance attributable to
hedged derivatives for the three months ended March 31, 2006, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
|
Rate |
|
|
Total |
|
|
Accumulated OCI balance at December 31, 2005 |
|
$ |
(204 |
) |
|
$ |
8 |
|
|
$ |
(196 |
) |
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
20 |
|
|
|
(2 |
) |
|
|
18 |
|
Mark-to-market of hedge contracts |
|
|
187 |
|
|
|
42 |
|
|
|
229 |
|
|
Accumulated OCI balance at March 31, 2006 |
|
$ |
3 |
|
|
$ |
48 |
|
|
$ |
51 |
|
|
As of March 31, 2007, the net balance in OCI relating to SFAS 133 was an unrecognized loss of
approximately $74 million, which is net of $50 million in
income taxes. NRG expects $4 million of
net deferred losses on derivative instruments accumulated in OCI to be recognized in earnings during
the next twelve months.
Statement of Operations
In accordance with SFAS 133, unrealized gains and losses associated with changes in the fair
value of derivative instruments not accounted for as hedge derivatives and ineffectiveness of hedge
derivatives are reflected in current period earnings.
11
The following tables summarizes the pre-tax effects of non-hedge derivatives, derivatives that
do not qualify as hedges, and ineffectiveness of hedge derivatives on NRGs statement of
operations for the three months ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Operating Revenues |
|
$ |
(90 |
) |
|
$ |
|
|
|
$ |
(90 |
) |
Equity in earnings of unconsolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total statement of operations impact before tax |
|
$ |
(90 |
) |
|
$ |
|
|
|
$ |
(90 |
) |
|
The following tables summarizes the pre-tax effects of non-hedge derivatives, derivatives that
do not qualify as hedges, and ineffectiveness of hedge derivatives on NRGs statement of
operations for the three months ended March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Operating Revenues |
|
$ |
49 |
|
|
$ |
|
|
|
$ |
49 |
|
Equity in earnings of unconsolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
3 |
|
|
|
3 |
|
|
Total statement of operations impact before tax |
|
$ |
49 |
|
|
$ |
(3 |
) |
|
$ |
46 |
|
|
For the three months ended March 31, 2007, the unrealized loss associated with changes in the
fair value of derivative instruments not accounted for as hedge derivatives of $90 million is
comprised of $79 million of fair value decreases in forward sales of electricity and fuel, a $44
million gain 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 revenues of which $57 million was related to economic
hedges and $13 million was related to trading activity. In
addition, the Company recorded $15 million of gains
associated with open positions also related to trading activity.
For the three months ended March 31, 2006, the unrealized gain associated with changes in the
fair value of derivative instruments not accounted for as hedge derivatives of $49 million is
comprised of $37 million of fair value increases in forward sales of electricity and fuel, an $8
million loss due to the ineffectiveness associated with financial forward contracted electric and
gas sales, $21 million from the reversal of mark-to-market losses which ultimately settled as
financial revenues, of which $45 million was related to losses
on economic hedges and $24 million was related to gains on
trading activity. In addition, the Company recorded $1 million
of losses associated with open positions also related to trading activity. NRGs
pre-tax earnings were also affected by a $3 million loss due to ineffectiveness associated with the
Companys fixed-to-floating interest rate swap designated as a hedge of fair value changes in the
Senior Notes.
Note 6 Changes in Capital Structure
The following table reflects the changes in NRGs common stock issued and outstanding during
the three months ended March 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Authorized |
|
|
Issued |
|
|
Treasury |
|
|
Outstanding |
|
|
Balance as of December 31, 2006 |
|
|
500,000,000 |
|
|
|
137,124,132 |
|
|
|
(14,800,581 |
) |
|
|
122,323,551 |
|
Capital Allocation Program Phase II during the first quarter 2007 |
|
|
|
|
|
|
|
|
|
|
(1,500,000 |
) |
|
|
(1,500,000 |
) |
Shares issued from LTIP through March 31, 2007 |
|
|
|
|
|
|
299,457 |
|
|
|
|
|
|
|
299,457 |
|
|
Balance as of March 31, 2007 |
|
|
500,000,000 |
|
|
|
137,423,589 |
|
|
|
(16,300,581 |
) |
|
|
121,123,008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of December 31, 2005 |
|
|
500,000,000 |
|
|
|
100,048,676 |
|
|
|
(19,346,788 |
) |
|
|
80,701,888 |
|
Shares issued January 2006 |
|
|
|
|
|
|
20,855,057 |
|
|
|
|
|
|
|
20,855,057 |
|
Acquisition of Texas Genco LLC |
|
|
|
|
|
|
16,059,504 |
|
|
|
19,346,788 |
|
|
|
35,406,292 |
|
Shares issued from LTIP through March 31, 2006 |
|
|
|
|
|
|
12,038 |
|
|
|
|
|
|
|
12,038 |
|
|
Balance as of March 31, 2006 |
|
|
500,000,000 |
|
|
|
136,975,275 |
|
|
|
|
|
|
|
136,975,275 |
|
|
Common Stock
NRGs authorized common stock consists of 500 million shares of NRG stock. Common stock
issued as of March 31, 2007 and 2006 was 137,423,589 and 136,975,275 shares, respectively.
12
Treasury Stock
In 2006, NRG
initiated a Capital Allocation Program executed in two phases. Phase I was completed in the fourth
quarter 2006, with the repurchase of 10,587,700 shares of the Companys common stock for
approximately $500 million. Phase II is also a $500 million share buyback program that began in the
fourth quarter 2006 with the repurchase of 4,212,881 shares of NRG common stock for a total of
approximately $232 million. During the first quarter 2007, NRG repurchased an additional 1,500,000
shares of the Companys common stock for approximately $103 million. As of March 31, 2007, NRG had repurchased a total of 16,300,581 shares of its common stock at
a cost of approximately $835 million as part of its Capital
Allocation Program. The Company expects to
complete Phase II of the Capital Allocation Program in 2007 with the
repurchase of approximately an additional $165 million of NRG common stock.
As part of Phase I of the Capital Allocation Program, NRG issued Notes and Preferred Interests
to Credit Suisse which included an embedded derivative that NRG may choose to pay in cash or stock.
At maturity, should NRGs stock price exceed a compound annual growth rate of 20% beyond the
volume-weighted average share price at the time of repurchase, referred to as the Reference Price,
NRG will pay to Credit Suisse the excess of NRGs stock price over the Reference Price. As of
March 31, 2007, per the noted calculation, the amount owed to Credit Suisse was approximately $24
million.
Stock Dividend
On April 25, 2007, NRGs Board of Directors approved a two-for-one stock split of the
Companys outstanding shares of common stock to be effected in the form of stock dividend. The
stock split will entitle each stockholder of record at the close of business on May 22, 2007 to
receive one additional share for every outstanding share of common stock held. The additional
shares resulting from the stock split are expected to be distributed by the Companys transfer
agent on or about May 31, 2007. Upon the completion of the stock split, NRG will have
approximately 242 million shares of common stock outstanding.
Note 7 Equity Compensation
Stock Options, or NQSOs
The following table summarizes the change in the outstanding NQSO during the three months
ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
Weighted Average Grant-Date |
|
|
Shares |
|
Exercise Price |
|
Fair Value Per Share |
|
Outstanding as of December 31, 2006 |
|
|
1,705,536 |
|
|
$ |
35.18 |
|
|
$ |
13.40 |
|
Granted |
|
|
368,600 |
|
|
|
55.83 |
|
|
|
16.36 |
|
Forfeited |
|
|
(25,401 |
) |
|
|
49.76 |
|
|
|
15.01 |
|
Exercised |
|
|
(37,393 |
) |
|
|
43.29 |
|
|
|
13.45 |
|
|
Outstanding at March 31, 2007 |
|
|
2,011,342 |
|
|
|
38.63 |
|
|
|
13.92 |
|
Exercisable at March 31, 2007 |
|
|
1,037,003 |
|
|
$ |
27.74 |
|
|
$ |
12.74 |
|
|
Restricted Stock Units, or RSUs
The following table shows the change in the outstanding RSU balance during the three months
ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Grant-Date |
Non-vested Shares |
|
Shares |
|
Fair Value Per Share |
|
Non-vested as of December 31, 2006 |
|
|
1,138,593 |
|
|
$ |
31.48 |
|
Granted |
|
|
44,700 |
|
|
|
55.83 |
|
Vested |
|
|
(475,350 |
) |
|
|
19.99 |
|
Forfeited |
|
|
(17,550 |
) |
|
|
37.25 |
|
|
Outstanding as of March 31, 2007 |
|
|
690,393 |
|
|
$ |
40.78 |
|
|
Performance Units, or PUs
The following table shows the change in the outstanding PU balance during the three months
ended March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Grant-Date |
Non-vested Shares |
|
Shares |
|
Fair Value Per Share |
|
Non-vested as of December 31, 2006 |
|
|
205,332 |
|
|
$ |
34.49 |
|
Granted |
|
|
88,800 |
|
|
|
35.00 |
|
Vested |
|
|
|
|
|
|
|
|
Forfeited |
|
|
(8,500 |
) |
|
|
33.12 |
|
|
Outstanding as of March 31, 2007 |
|
|
285,632 |
|
|
$ |
34.69 |
|
|
13
Note 8 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.
The reconciliation of basic earnings per common share to diluted earnings per share is as
follows:
|
|
|
|
|
|
|
|
|
(In millions, except per share data) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Basic earnings per share |
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
65 |
|
|
$ |
15 |
|
Preferred stock dividends |
|
|
(14 |
) |
|
|
(11 |
) |
|
Net income available to common stockholders from continuing operations |
|
|
51 |
|
|
|
4 |
|
Discontinued operations, net of income tax expense |
|
|
|
|
|
|
11 |
|
|
Net income available to common stockholders |
|
$ |
51 |
|
|
$ |
15 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
122.0 |
|
|
|
117.4 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
0.42 |
|
|
$ |
0.04 |
|
Discontinued operations, net of income tax expense |
|
|
|
|
|
|
0.09 |
|
|
Net income |
|
$ |
0.42 |
|
|
$ |
0.13 |
|
|
Diluted earnings per share |
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
Net income available to common stockholders from continuing operations |
|
$ |
51 |
|
|
$ |
4 |
|
Add preferred stock dividends for dilutive preferred stock |
|
|
4 |
|
|
|
|
|
|
Adjusted income from continuing operations |
|
|
55 |
|
|
|
4 |
|
Discontinued operations, net of tax |
|
|
|
|
|
|
11 |
|
|
Net income available to common stockholders |
|
$ |
55 |
|
|
$ |
15 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
122.0 |
|
|
|
117.4 |
|
Incremental shares attributable to the issuance of equity
compensation (treasury stock method) |
|
|
1.6 |
|
|
|
1.4 |
|
Incremental shares attributable to embedded derivatives of certain
financial instruments (if-converted method) |
|
|
1.2 |
|
|
|
|
|
Incremental shares attributable to assumed conversion features of
outstanding preferred stock (if-converted method) |
|
|
10.5 |
|
|
|
|
|
|
Total dilutive shares |
|
|
135.3 |
|
|
|
118.8 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
Income from continuing operations |
|
$ |
0.41 |
|
|
$ |
0.04 |
|
Income from discontinued operations, net of tax |
|
|
|
|
|
|
0.09 |
|
|
Net income |
|
$ |
0.41 |
|
|
$ |
0.13 |
|
|
Effects on Earnings per Share
Stock Awards
Non-Qualified Stock Options For the three months ended March 31, 2007, none of the
Companys stock options were anti-dilutive. For the three months ended March 31, 2006, options to
purchase 595,121 shares of common stock were not included in the computation of diluted earnings
per share because the exercise price of the options was greater than the average market price of the
14
common stock for the respective periods, and therefore the effect would have been
anti-dilutive.
Performance Units For the three months ended March 31, 2007 and 2006, performance units of
252,332 and 206,332, respectively, were not included in the computation of diluted earnings per
share because the average market price of NRGs common stock was less than the target price of the
outstanding performance units, and therefore the effect would have been anti-dilutive.
Preferred Stock
5.75% Preferred Stock For the three months ended March 31, 2007 and 2006, the shares of
common stock associated with the 5.75% Preferred Stock were not included in the diluted earnings
per share computation since its effect would have been anti-dilutive.
4% Preferred Stock For the three months ended March 31, 2007, 10,500,000 shares of common
stock associated with the 4% Preferred Stock were included in diluted earnings per share. For the
three months ended March 31, 2006, the shares of common stock associated with the 4% Preferred
Stock were not included in the diluted earnings per share computation since its effect would have
been anti-dilutive.
3.625% Preferred Stock The Companys 3.625% Preferred Stock contains an embedded derivative
which allows for additional cash or common shares to be issued if the average stock price for a
20-day period prior to redemption exceeds $59.08 the market price trigger. For the three months
ended March 31, 2007, the dilutive effect of the embedded derivative included in diluted earnings
per share was 773,607 shares of common stock. For the three months ended March 31, 2006 calculation
of diluted earnings per share was not impacted by this derivative because the market price trigger
was higher than the average market price of NRGs common stock, and therefore its effect would have
been anti-dilutive.
Notes and Preferred Interests As part of Phase I of the Capital Allocation Program, NRG
issued Notes and Preferred Interests to Credit Suisse which included an embedded derivative that
NRG may choose to pay in cash or stock. At maturity, should NRGs stock price exceed a compound
annual growth rate of 20% beyond the volume-weighted average share price at the time of repurchase,
referred to as the Reference Price, NRG will pay to Credit Suisse the excess of NRGs stock price
over the Reference Price. The value of this excess is considered dilutive for purposes of earnings
per share. As of March 31, 2007, NRGs stock price exceeded the Reference Price creating a
dilutive effect of 385,286 shares.
Pro forma Earnings Per Share
As discussed in Note 6, Changes in Capital Structure, on April 25, 2007, the Companys Board
of Directors approved a two-for-one stock split of the Companys outstanding common stock to be
effected in the form of a stock dividend, payable on or about May 31, 2007 to stockholders of
record on May 22, 2007. Once the split becomes effective, future presentation of earnings
per share will be retroactively recast for all prior periods. Taking into account the effect of
the split, basic and diluted earnings per share for the three months ended March 31, 2007, would
have been $0.21 and $0.20, respectively. Taking into account the effect of the split, basic and
diluted earnings per share for the three months ended March 31, 2006, would have been $0.06 and
$0.06, respectively.
Note 9 Segment Reporting
The Companys segment structure reflects NRGs core areas of operation which are primarily the
geographic regions of the Companys wholesale power generation, thermal and chilled water business,
and corporate activities. Within NRGs wholesale power generation operations, there are distinct
components with separate operating results and management structures for the following regions:
Texas, Northeast, South Central, West and International. All prior period information has been
restated to reflect the change in the Companys segment structure as discussed in Note 17, Segment
Reporting, to the Companys financial statements in its Annual Report on Form 10-K for the year
ended December 31, 2006.
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2007 |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
West |
|
|
International |
|
|
Thermal |
|
|
Corporate |
|
|
Elimination |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
695 |
|
|
$ |
342 |
|
|
$ |
151 |
|
|
$ |
28 |
|
|
$ |
43 |
|
|
$ |
49 |
|
|
$ |
5 |
|
|
$ |
(3 |
) |
|
$ |
1,310 |
|
Depreciation and amortization |
|
|
114 |
|
|
|
25 |
|
|
|
17 |
|
|
|
|
|
|
|
1 |
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
161 |
|
Equity in earnings of
unconsolidated affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13 |
|
Income/(loss) from continuing
operations before income taxes |
|
|
113 |
|
|
|
38 |
|
|
|
10 |
|
|
|
5 |
|
|
|
24 |
|
|
|
23 |
|
|
|
(92 |
) |
|
|
|
|
|
|
121 |
|
|
Net income/(loss) |
|
$ |
60 |
|
|
$ |
38 |
|
|
$ |
10 |
|
|
$ |
5 |
|
|
$ |
17 |
|
|
$ |
23 |
|
|
$ |
(88 |
) |
|
$ |
|
|
|
$ |
65 |
|
|
Total assets |
|
$ |
12,731 |
|
|
$ |
1,561 |
|
|
$ |
1,014 |
|
|
$ |
185 |
|
|
$ |
1,028 |
|
|
$ |
222 |
|
|
$ |
11,510 |
|
|
$ |
(9,540 |
) |
|
$ |
18,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions) |
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2006 |
|
Texas (a) |
|
|
Northeast |
|
|
Central |
|
|
West (b) |
|
|
International |
|
|
Thermal |
|
|
Corporate |
|
|
Elimination |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
406 |
|
|
$ |
392 |
|
|
$ |
172 |
|
|
$ |
1 |
|
|
$ |
42 |
|
|
$ |
42 |
|
|
$ |
8 |
|
|
$ |
(20 |
) |
|
$ |
1,043 |
|
Depreciation and amortization |
|
|
74 |
|
|
|
22 |
|
|
|
16 |
|
|
|
|
|
|
|
1 |
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
118 |
|
Equity in earnings of
unconsolidated affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
|
|
21 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
21 |
|
Income/(loss) from continuing
operations before income taxes |
|
|
(7 |
) |
|
|
132 |
|
|
|
28 |
|
|
|
(4 |
) |
|
|
31 |
|
|
|
4 |
|
|
|
(150 |
) |
|
|
(20 |
) |
|
|
14 |
|
Income on discontinued
operations, net of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
10 |
|
|
|
|
|
|
|
11 |
|
|
Net income/(loss) |
|
$ |
18 |
|
|
$ |
132 |
|
|
$ |
28 |
|
|
$ |
(2 |
) |
|
$ |
23 |
|
|
$ |
4 |
|
|
$ |
(157 |
) |
|
$ |
(20 |
) |
|
$ |
26 |
|
|
|
|
|
(a) |
|
For the period February 2, 2006 to March 31, 2006. |
|
(b) |
|
Only included the equity earnings of WCP. |
16
Note 10 Income Taxes
Income tax expense for the three months ended March 31, 2007 was $56 million and an income tax
benefit of $1 million for the three months ended March 31, 2006. The income tax expense for the
three months ended March 31, 2007 included domestic tax expense of $48 million and foreign tax
expense of $8 million. The income tax benefit for the three months ended March 31, 2006 included
domestic tax benefit of $10 million and foreign tax expense of $9 million.
A reconciliation of the U.S. statutory rate to NRGs effective tax rate from continuing
operations for the three months ended March 31, 2007 and 2006 is as follows:
|
|
|
|
|
|
|
|
|
(In millions except rate data) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Income from continuing operations before income taxes |
|
$ |
121 |
|
|
$ |
14 |
|
Tax at 35% |
|
|
42 |
|
|
|
5 |
|
State taxes |
|
|
6 |
|
|
|
2 |
|
Valuation allowance |
|
|
|
|
|
|
2 |
|
Disputed claims reserve |
|
|
|
|
|
|
(7 |
) |
Foreign operations |
|
|
(1 |
) |
|
|
(6 |
) |
Foreign dividend |
|
|
5 |
|
|
|
1 |
|
Permanent
differences including subpart F income and non-deductible interest
expense |
|
|
4 |
|
|
|
2 |
|
|
Income tax expense/(benefit) |
|
$ |
56 |
|
|
$ |
(1 |
) |
|
Effective income tax rate |
|
|
46.3 |
% |
|
|
(7.1 |
)% |
|
The effective income tax rate for the three months ended March 31, 2007 and 2006 differs from
the U.S. statutory rate of 35% due to a taxable dividend from foreign operations and non-deductible
interest, offset by earnings in foreign jurisdictions that are taxed at rates lower than the U.S.
statutory rate.
Deferred tax assets and valuation allowance
Net deferred tax balance As of March 31, 2007, NRG recorded a net deferred tax asset of $30
million. However, due to an assessment of positive and negative evidence, including projected
capital gains and available tax planning strategies, NRG believes that it is more likely than not
that a benefit will not be realized on $583 million of tax assets, thus a valuation allowance has
remained, resulting in a net deferred tax liability of $553 million.
NOL carryforwards As of March 31, 2007, the Company had NOL carryforwards available for
domestic income tax purposes of $70 million that will expire through 2027. In addition, NRG has
cumulative foreign NOL carryforwards of $273 million of which $73 million will expire in 2016 and
of which $200 million does not have an expiration date.
Uncertain tax benefits
NRG
has identified certain unrecognized tax benefits whose after tax
value was $712 million,
and if recognized, $19 million will impact the Companys
effective tax rate. Of the $712 million
in unrecognized tax benefits, $693 million relates to periods prior to the Companys emergence from
bankruptcy, and in accordance with SOP 90-7 and the application
of Fresh Start accounting, any recognized benefit would not
impact the Companys effective tax rate but would increase
Additional Paid In Capital. NRG
has accrued interest and penalty related to these unrecognized tax
benefits of approximately $4
million as of the adoption of FIN 48 by the Company on January 1, 2007. There were no interest and
penalties related to unrecognized tax benefits that were recognized in the Companys results of
operations for the three months ended March 31, 2007.
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, Australia, and Brazil. 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.
17
Note 11 Benefit Plans and Other Postretirement Benefits
The net annual periodic pension cost for the three months ended March 31, 2007 and 2006
related to all of the Companys defined benefit pension plans, include the following components:
|
|
|
|
|
|
|
|
|
(In millions) |
|
Defined Benefit Pension Plans |
|
Three months ended March 31 |
|
2007 |
|
|
2006 |
|
|
Service cost benefits earned |
|
$ |
4 |
|
|
$ |
4 |
|
Interest cost on benefit obligation |
|
|
4 |
|
|
|
3 |
|
Expected return on plan assets |
|
|
(3 |
) |
|
|
(1 |
) |
|
Net periodic benefit cost |
|
$ |
5 |
|
|
$ |
6 |
|
|
The net annual periodic cost for the three months ended March 31, 2007 and 2006 related to all
of the Companys other post retirement benefits plans, include the following components:
|
|
|
|
|
|
|
|
|
(In millions) |
|
Other Postretirement Benefits Plans |
|
Three months ended March 31 |
|
2007 |
|
|
2006 |
|
|
Service cost benefits earned |
|
$ |
1 |
|
|
$ |
1 |
|
Interest cost on benefit obligation |
|
|
1 |
|
|
|
1 |
|
|
Net periodic benefit cost |
|
$ |
2 |
|
|
$ |
2 |
|
|
The total amount of employer contributions paid for the three months ended March 31, 2007 was
$12 million.
Note 12 Commitments and Contingencies
Commitments
Second Lien Structure
NRG has granted second priority liens to certain counterparties on substantially all of the
Companys assets in the United States in order to secure obligations, which are primarily long-term
in nature under certain power sale agreements and related contracts. NRG uses the second lien
structure to reduce the amount of cash collateral and letters of credit that it may otherwise be
required to post from time to time to support its obligations under these agreements. Within the
second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its
non-baseload assets with these counterparties. As of March 31, 2007, the net discounted exposure on
the agreements and hedges that were subject to the second lien structure was approximately $90
million.
Coal Commitments
NRG enters into long-term contractual arrangements to procure fuel and transportation services
for the Companys generation assets. NRG entered into additional coal purchase agreements during
the first quarter 2007 with total commitments of approximately $303 million spanning over the next
six years.
Contingencies
Set forth below is a description of the Companys material legal proceedings. Pursuant to the
requirements of SFAS 5, Accounting for Contingencies, 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 is reasonably estimable. Because litigation is subject to
inherent uncertainties and unfavorable rulings or developments could occur, there can be no
certainty that NRG may not ultimately incur charges in excess of presently recorded reserves. A
future adverse ruling or unfavorable development could result in future charges, which could have a
materially adverse effect on NRGs consolidated financial position, results of operations, or cash
flows.
With respect to a number of the items listed below, management has determined that a loss is
not probable or the amount of the loss
18
is not reasonably estimable, or both. In some cases, management is not able to predict with
any degree of substantial certainty the range of possible loss that could be incurred.
Notwithstanding these facts, management has assessed each of these 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. Managements
judgment may, as a result of facts arising prior to resolution of these matters, or other factors,
prove inaccurate and investors should be aware that such judgment is made subject to the
uncertainty of litigation.
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 effect
NRGs consolidated financial position, results of operations, or cash flows.
NRG believes that it has valid defenses to the legal proceedings and investigations described
below 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 below, the Company is
unable to predict the outcome of 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. NRG also has indemnity
rights for some of these proceedings to reimburse NRG for certain legal expenses and to offset
certain amounts deemed to be owed in the event of an unfavorable litigation outcome.
California Electricity and Related Litigation
NRG, WCP, WCPs four operating subsidiaries, Dynegy, Inc., and numerous other unrelated
parties are the subject of numerous lawsuits that arose based on events that occurred in the
California power market in 2000 and 2001. The complaints primarily allege that the defendants
engaged in unfair business practices, price fixing, antitrust violations, and other market gaming
activities. Certain of these lawsuits originally commenced in 2000 and 2001, which seek unspecified
treble damages and injunctive relief, were consolidated and made a part of a Multi-District
Litigation proceeding before the U.S. District Court for the Southern District of California. The
consolidated cases moved between state and federal court several times. On May 5, 2005, the case
was remanded to California state court, and under a scheduling order, defendants filed their
objections to the pleadings. On July 22, 2005, based upon the filed rate doctrine and federal
preemption, the court dismissed NRG Energy, Inc. without prejudice, leaving only subsidiaries of
WCP remaining in the case. On October 3, 2005, the court sustained defendants demurrer, dismissing
the case against all remaining defendants. On December 2, 2005, the plaintiffs filed their notice
of appeal from the dismissal with the California State Court of Appeals Fourth District and on
February 26, 2007, the court affirmed the lower courts judgment of dismissal. Other cases,
including putative class actions, have been filed in state and federal court on behalf of business
and residential electricity consumers that name WCP and/or subsidiaries of WCP, in addition to
numerous other defendants. These complaints allege the defendants attempted to manipulate gas
indexes by reporting false and fraudulent trades, and violated Californias antitrust law and
unfair business practices law. The complaints seek restitution and disgorgement, civil fines,
compensatory and punitive damages, attorneys fees, and declaratory and injunctive relief. Motion
practice is proceeding in these cases and dispositive motions have been filed in several of these
proceedings.
In September 2006, Dynegy executed a settlement agreement to resolve the class action claims
in the natural gas anti-trust cases consolidated and pending in state court in San Diego,
California. Approved in late December 2006, the Court has dismissed the class action claims. WCP
and some of its subsidiaries were named defendants and Dynegys settlement includes full releases
for these entities. The settlement resolves claims by core and non-core California consumers of
natural gas for damages arising from or relating to allegations of misreporting of natural gas
transactions or wash trading. Preliminarily approved by the court, the settlement excludes similar
cases filed by individual plaintiffs, which Dynegy continues to defend. Neither WCP and its
subsidiaries nor NRG paid any defense costs or settlement funds, as Dynegy owed and provided a
complete defense and indemnification.
In August 2006, Dynegy entered into an agreement to settle class action claims by California
natural gas resellers and cogenerators. These claims are pending in Nevada federal district court
in In Re Western States Wholesale Natural Gas Antitrust Litigation. WCP and its subsidiaries are
named defendants and Dynegys settlement would include full releases for these entities. The
settlement is expected to be submitted to the court for approval in 2007. Neither WCP, its
subsidiaries, nor NRG paid any defense costs or settlement funds, as Dynegy owed and provided a
complete defense and indemnification.
In cases relating to natural gas, Dynegy is defending WCP and/or its subsidiaries pursuant to
an indemnification agreement and will be the responsible party for any loss. In cases relating to
electricity, Dynegys counsel is representing it and WCP and/or its subsidiaries, with each party
responsible for half of the costs and each party responsible for half of any loss.
19
California Department of Water Resources
On December 19, 2006, the U.S. Court of Appeals for the Ninth Circuit reversed FERCs prior
determinations regarding the enforceability of certain wholesale power contracts and remanded the
case to FERC for further proceedings consistent with the decision. One of these contracts was the
wholesale power contract between the California Department of Water Resources, or CDWR, and
subsidiaries of WCP. This case originated with a February 2002 complaint filed at FERC by the State
of California alleging that many parties, including WCP subsidiaries, overcharged the State. For
WCP, the alleged overcharges totaled approximately $940 million for 2001 and 2002. The complaint
demanded that FERC abrogate the CDWR contract and sought refunds associated with revenues collected
under the contract. In 2003, FERC rejected this complaint, denied rehearing, and the case was
appealed to the Ninth Circuit where oral argument was held on December 8, 2004. On December 19,
2006, the Court decided that in FERCs review of the contracts at issue, FERC could not rely on the
Mobile-Sierra standard presumption of just and reasonable rates, where such contracts were not
reviewed by FERC with full knowledge of the then existing market conditions. WCP and the other
defendants expect to seek review by the U.S. Supreme Court prior to the May 3, 2007, deadline. The
Supreme Court is expected to decide in 2007 whether it will accept the appeal. At this time, while
NRG cannot predict with certainty whether WCP will be required to make refunds for rates collected
under the CDWR contract or estimate the range of any such possible refunds, a reconsideration of
the CDWR contract by FERC with a resulting order mandating significant refunds could have a
material adverse impact on NRGs financial position, statement of operations, and statement of cash
flows. As part of the 2006 acquisition of Dynegys 50% ownership interest in WCP, WCP and NRG
assumed responsibility for any risk of loss arising from this case, unless any such loss was deemed
to have resulted from certain acts of gross negligence or willful misconduct on the part of Dynegy,
in which case any such loss would be shared equally between WCP and Dynegy.
Connecticut Congestion Charges
On November 28, 2001, CL&P sought recovery in the U.S. District Court for Connecticut for
amounts it claimed were owed for congestion charges under the October 29, 1999 Standard Offer
Services Contract. CL&P withheld approximately $30 million from amounts owed to PMI under contract
and PMI counterclaimed. CL&Ps motion for summary judgment, which PMI opposed, remains pending. NRG
cannot estimate at this time the overall exposure for congestion charges for the term of the
contract prior to the implementation of standard market design, which occurred on March 1, 2003;
however, the full amount withheld by CL&P has been reserved as a reduction to outstanding accounts
receivable.
Station Service Disputes
On October 2, 2000, NiMo commenced an action against NRG in New York state court seeking
damages related to NRGs alleged failure to pay retail tariff amounts for utility services at the
Dunkirk Plant between June 1999 and September 2000. The parties agreed to consolidate this action
with two other actions against the Huntley and Oswego Plants. On October 8, 2002, by stipulation
and order, this action was stayed pending submission to FERC of the disputes in the action. At
FERC, NiMo asserted the same claims and legal theories, and on November 19, 2004, FERC denied
NiMos petition and ruled that the NRG facilities could net their service obligations over each 30
calendar day period from the day NRG acquired the facilities. In addition, FERC ruled that neither
NiMo nor the New York Public Service Commission could impose a retail delivery charge on the NRG
facilities because they are interconnected to transmission and not to distribution. On April 22,
2005, FERC denied NiMos motion for rehearing. NiMo appealed to the U.S. Court of Appeals for the
D.C. Circuit which, on June 23, 2006, denied the appeal finding that NYISOs station service
program that permits generators to self supply their station power needs by netting consumption
against production in a month is lawful. On October 23, 2006, the D.C. Circuit denied NiMos
petition for rehearing and on January 22, 2007, NiMo sought review before the U.S. Supreme Court.
On April 30, 2007, the U.S. Supreme Court denied NiMos
request for the review thus ending further avenues to appeal FERCs
ruling in this matter. NRG currently believes
it is adequately reserved.
On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose
over station service power and delivery services provided to the facilities. On December 20, 2002,
as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself
and CL&P, FERC issued an order finding that, at times when NRG is not able to self-supply its
station power needs, there is a sale of station power from a third-party and retail charges apply.
In August 2003, the parties agreed to submit the dispute to binding arbitration. In July and August
2006, the parties submitted their respective statements of the case to the three member arbitration
panel. A discovery and briefing schedule was issued and a hearing is set for September 2007. NRG
believes it is adequately reserved.
20
ITISA
NRGs Brazilian project company, ITISA, the owner of a 155 MW hydro project in Brazil, is in
arbitration with the former Engineering, Procurement and Construction, or EPC, contractor for the
project, Inepar Industria e Construcoes, or Inepar. The dispute was commenced in arbitration by
ITISA in September 2002 and pertains to certain matters arising under the EPC contract between the
parties. ITISA sought Real 140 million and asserted that Inepar breached the contract. Inepar
sought Real 39 million and alleged that ITISA breached the contract. On September 2, 2005, the
arbitration panel ruled in favor of ITISA, awarding it Real 139 million and Inepar Real 4.7
million. Due to interest accrued from the commencement of the arbitration to the award date,
ITISAs award was increased to approximately Real 227 million (approximately $110 million as of
March 31, 2007). ITISA has commenced the lengthy process in Brazil to execute on the arbitral
award. NRG is unable to predict the outcome of this execution process. On December 21, 2005,
Inepars request for clarifications was denied. Due to the uncertainty of the ongoing collection
process, NRG is accounting for receipt of any amounts as a gain contingency.
Disputed Claims Reserve
As part of NRGs plan of reorganization, NRG funded a disputed claims reserve for the
satisfaction of certain general unsecured claims that were disputed claims as of the effective date
of the plan. Under the terms of the plan, as such claims are resolved, the claimants are paid from
the reserve on the same basis as if they had been paid out in the bankruptcy. To the extent the
aggregate amount required to be paid on the disputed claims exceeds the amount remaining in the
funded claims reserve, NRG will be obligated to provide additional cash and common stock to satisfy
the claims. Any excess funds in the disputed claims reserve will be reallocated to the creditor
pool for the pro rata benefit of all allowed claims. The contributed common stock and cash in the
reserves is held by an escrow agent to complete the distribution and settlement process. Since NRG
has surrendered control over the common stock and cash provided to the disputed claims reserve, NRG
recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts
from the balance sheet. Similarly, NRG removed the obligations relevant to the claims from the
balance sheet when the common stock was issued and cash contributed.
On April 3, 2006, the Company made a supplemental distribution to creditors under the
Companys Chapter 11 plan, totaling $25 million in cash and 2,541,000 shares of common stock. As of
April 18, 2007, the reserve held approximately $10 million in cash and approximately 691,709 shares
of common stock. NRG believes the cash and stock together represent sufficient funds to satisfy all
remaining disputed claims.
Note 13 Regulatory Matters
With the exception of NRGs thermal and chilled water business and decommissioning
responsibilities related to STP, NRGs operations are not regulated operations subject to SFAS 71
and NRG does not record assets and liabilities that result from the regulated ratemaking processes.
NRG does operate, however, in a highly regulated industry and the Company 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.
Northeast Region
New England On December 28, 2006, the Attorneys General of the State of Connecticut and
Commonwealth of Massachusetts filed an appeal of the FERC orders accepting the settlement of the
New England capacity market design with the U.S. Court of Appeals for the D.C. Circuit. The
settlement, filed March 7, 2006, by a broad group of New England market participants, provides for
interim capacity transition payments for all generators in New England for the period starting
December 1, 2006 through May 31, 2010, and the establishment of a Forward Capacity Market, or FCM,
commencing May 31, 2010. On June 16, 2006, FERC issued an order accepting the settlement, which was
reaffirmed on rehearing by order dated October 31, 2006. Interim capacity transition payments
provided for under the FCM settlement commenced December 1, 2006, as scheduled. A successful
appeal by the Attorneys General could disturb the settlement and create a refund obligation of
interim capacity transition payments. On April 5, 2007, the Connecticut Attorney General filed a
motion seeking to stay the interim capacity transition payments.
New York A dispute is ongoing with respect to high prices for spinning reserves, or SR, and
non-spinning reserves, or NSR, in the NYISO-administered markets during the period from January 29,
2000 to March 27, 2000. Certain entities have argued that the NYISO acted unreasonably in
declining to invoke Temporary Extraordinary Operating Procedures, or TEP, to recalculate prices and
that the markets should be resettled for various reasons. In a series of orders, FERC declined to
grant the requested relief. On appeal, the U.S. Court of Appeals for the D.C. Circuit remanded the
case back to FERC to further explain its decision not to utilize TEP to remedy certain of these
market issues. On March 4, 2005, FERC issued an order reaffirming that (i) the NYISO acted
reasonably in not invoking TEP, (ii) NYISO did not violate its tariff, and (iii) refunds should not
be granted; this order was reaffirmed on rehearing
21
on November 17, 2005. These orders have subsequently been appealed to the D.C. Circuit.
Resettlement of the market, while viewed as unlikely, could have a material financial impact on the
Companys results of operations.
West Region
On December 1, 2006, NRG filed to extend the existing RMR agreements for NRGs Cabrillo Power
I, LLC (Encina) and Cabrillo Power II, LLC (San Diego Jets) for 2007, seeking to continue
the then-existing rate effective January 1, 2007. On January 24, 2007, FERC accepted the Cabrillo Power
I filing. On January 30, 2007, FERC accepted the Cabrillo II filing, subject to refund, in response
to protests filed by the CPUC and CAISO, and established settlement procedures. The parties have
reached a settlement in principle that will result in an annual fixed revenue requirement of
approximately $5 million.
Note 14 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. In addition, increased public concern and mounting political pressure
may result in federal or additional state requirements to reduce or mitigate the effects of greenhouse gases emissions,
including carbon dioxide. In general, the effect of such future laws or regulations is expected
to require the addition of pollution control equipment or the imposition of restrictions or additional costs on the
Companys operations.
Environmental Capital Expenditures
Based on current rules, technology and plans, NRG has estimated that $1.3 billion of capital
expenditures will be incurred during the period 2007 through 2012 in order to keep NRGs facilities
in compliance with environmental laws. These expenditures are primarily related to installation of
particulate, SO2, NOx, and mercury controls to comply with Clean Air
Interstate Rule, or CAIR, and the Clean Air Mercury Rule, or CAMR, as well as installation of Best
Technology Available under the Phase II 316(b) Rule. NRG typically updates its estimates for
environmental capital expenditures annually. These plans, including installed equipment and timing
as well as cost can be expected to change over time, in some cases materially. These plans are
based on current regulatory requirements and best engineering practices. Changes to regulations or
market conditions could result in changes to installed equipment timing or associated costs.
Depending upon the outcome of the challenge to DNRECs Regulation No. 1146 discussed below, NRG
will reassess its options for its Indian River power plant and associated costs.
Other Environmental Matters
Under various federal, state, and local environmental laws and regulations, a current or
previous owner or operator of any facility may be required to investigate and remediate releases or
threatened releases of hazardous or toxic substances or petroleum products located at a facility,
and may be held liable to a governmental entity or to third parties for property damage, personal
injury and investigation and remediation costs incurred by the party in connection with any
releases or threatened releases. These laws impose strict (without fault) and joint and several
liability. The cost of investigation, remediation, or removal of any hazardous or toxic substances
or petroleum products could be substantial.
Texas Region
The lignite used to fuel the Texas regions Limestone facility is obtained from a surface mine
adjacent to the facility under an amended long-term contract with Texas Westmoreland Coal Co., or
TWCC, entered into in August 1999. 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 $70 million on TWCC for the
reclamation of this lignite mine. Final reclamation activity is expected to commence in 2015.
Pursuant to the contract with TWCC, an affiliate of CenterPoint Energy, Inc. has guaranteed $50
million of this obligation until 2010. The remaining sum of approximately $20 million has been
bonded by the mine operator, TWCC. Under the terms of the agreement, NRG is required to post a
corporate guarantee of TWCC's bond obligation in the amount of $50 million when CenterPoints
obligation lapses. As of March 31, 2007, NRG has established an ARO of approximately $20 million
related to the mine reclamation obligation.
Northeast Region
In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification
from the Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that
it may be a potentially responsible party with respect to a
22
historic captive landfill. NRG is working with DNREC through the Voluntary Clean-up Program to
investigate the site. The Company is unable to predict the financial impact at this time.
In November 2006, DNREC promulgated Regulation No. 1146, or Reg 1146, Electric Generating Unit
Multi-Pollutant Regulation and Section 111(d) of the State Plan for the Control of Mercury
Emissions from Coal-Fired Electric Steam Generating Units. These regulations govern the control of
SO2, NOx, and mercury emissions from electric generating units. NRGs current
plan to install controls at the Companys Indian River facility, while on an accelerated basis, is
unable to meet certain deadlines for SO2 and NOx controls in Phase 1, taking
into account the time required, as a practical matter, to design, install, and commission the
necessary equipment. NRG and the owners of all other subject facilities in the state filed a
challenge to Reg 1146 with the Environmental Appeals Board, or EAB, on December 6, 2006. In
addition, NRG also filed a protective appeal with the Delaware Superior Court on December 29, 2006.
A hearing is scheduled to commence before the EAB on June 18, 2007. NRG is unable to predict the
outcome of the proceedings at this time, but failure to obtain relief may result in a material
impact on the Companys results of operations.
South Central Region
On January 27, 2004, NRGs Louisiana Generating, LLC and the Companys Big Cajun II plant
received a request under Section 114 of the Clean Air Act, or CAA, from USEPA seeking information
primarily related to physical changes made at the Big Cajun II plant, and subsequently received a
notice of violation, or NOV, on February 15, 2005, alleging that NRGs predecessors had undertaken
projects that triggered requirements under the PSD program, including the installation of emission
controls. NRG submitted multiple responses commencing February 27, 2004 and ending on October 20,
2004. On May 9, 2006, these entities received from the Department of Justice, or DOJ, a notice of
deficiency related to their responses, to which NRG responded on May 22, 2006. A document review
was conducted at NRGs Louisiana Generating, LLC offices by the DOJ during the week of August 14,
2006. On December 8, 2006, the USEPA issued a supplemental NOV updating the original February 15,
2005 NOV. Discussions with the USEPA are ongoing and the Company cannot predict with certainty the
outcome of this matter.
Note 15 Guarantees
NRG and its subsidiaries enter into various contracts that include indemnification and
guarantee provisions as a routine part of the Companys business activities. Examples of these
contracts include asset purchases and sale agreements, commodity sale and purchase agreements,
joint venture agreements, operation and maintenance agreements, service agreements, settlement
agreements, and other types of contractual agreements with vendors and other third parties. These
contracts generally indemnify the counterparty for tax, environmental liability, litigation and
other matters, as well as breaches of representations, warranties and covenants set forth in these
agreements. In some cases, NRGs maximum potential liability cannot be estimated, since the
underlying agreements contain no limits on potential liability.
This footnote should be read in conjunction with the complete description under Note 25,
Guarantees, to the Companys financial statements in its Annual Report on Form 10-K for the year
ended December 31, 2006.
For the three months ended March 31, 2007, NRG had net increases to its guarantee obligations
under other commercial arrangements of approximately $128 million. These pertain to payment
obligations of NRG Power Marketing, Inc., or PMI.
Note 16 Condensed Consolidating Financial Information
As of March 31, 2007, the Company had $1.2 billion of 7.25% Senior Notes due 2014, $2.4
billion of 7.375% Senior Notes due 2016 and $1.1 billion of 7.375% Senior Notes due 2017
outstanding. These notes are guaranteed by certain of NRGs current and future wholly-owned
domestic subsidiaries, or guarantor subsidiaries.
Each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior
Notes as of March 31, 2007:
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Arthur Kill Power LLC
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NRG Connecticut Affiliate Services Inc. |
Astoria Gas Turbine Power LLC
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NRG Devon Operations Inc. |
Berrians I Gas Turbine Power LLC
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NRG Dunkirk Operations Inc. |
Big Cajun II Unit 4 LLC
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NRG El Segundo Operations Inc. |
Cabrillo Power I LLC
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NRG Generation Holdings, Inc. |
Cabrillo Power II LLC
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NRG Huntley Operations Inc. |
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Chickahominy River Energy Corp.
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NRG International LLC |
Commonwealth Atlantic Power LLC
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NRG Kaufman LLC |
Conemaugh Power LLC
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NRG Mesquite LLC |
Connecticut Jet Power LLC
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NRG MidAtlantic Affiliate Services Inc. |
Devon Power LLC
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NRG Middletown Operations Inc. |
Dunkirk Power LLC
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NRG Montville Operations Inc. |
Eastern Sierra Energy Company
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NRG New Jersey Energy Sales LLC |
El Segundo Power, LLC
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NRG New Roads Holdings LLC |
El Segundo Power II LLC
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NRG North Central Operations Inc. |
GCP Funding Company, LLC
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NRG Northeast Affiliate Services Inc. |
Hanover Energy Company
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NRG Norwalk Harbor Operations Inc. |
Hoffman Summit Wind Project, LLC
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NRG Operating Services, Inc. |
Huntley IGCC LLC
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NRG Oswego Harbor Power Operations Inc. |
Huntley Power LLC
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NRG Power Marketing Inc. |
Indian River IGCC LLC
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NRG Rocky Road LLC |
Indian River Operations Inc.
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NRG Saguaro Operations Inc. |
Indian River Power LLC
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NRG South Central Affiliate Services Inc. |
James River Power LLC
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NRG South Central Generating LLC |
Kaufman Cogen LP
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NRG South Central Operations Inc. |
Keystone Power LLC
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NRG South Texas LP |
Lake Erie Properties Inc.
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NRG Texas LLC |
Louisiana Generating LLC
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NRG Texas LP |
Middletown Power LLC
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NRG West Coast LLC |
Montville IGCC LLC
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NRG Western Affiliate Services Inc. |
Montville Power LLC
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Oswego Harbor Power LLC |
NEO Chester-Gen LLC
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Padoma Wind Power, LLC |
NEO Corporation
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Saguaro Power LLC |
NEO Freehold-Gen LLC
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San Juan Mesa Wind Project II, LLC |
NEO Landfill Gas Holdings Inc.
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Somerset Operations Inc. |
NEO Power Services Inc.
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Somerset Power LLC |
New Genco GP, LLC
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Texas Genco Financing Corp. |
New Genco LP, LLC
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Texas Genco GP, LLC |
Norwalk Power LLC
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Texas Genco Holdings, Inc. |
NRG Affiliate Services Inc.
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Texas Genco LP, LLC |
NRG Arthur Kill Operations Inc.
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Texas Genco Operating Services, LLC |
NRG Asia-Pacific, Ltd.
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Texas Genco Services, LP |
NRG Astoria Gas Turbine Operations Inc.
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Vienna Operations Inc. |
NRG Bayou Cove LLC
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Vienna Power LLC |
NRG Cabrillo Power Operations Inc.
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WCP (Generation) Holdings LLC |
NRG Cadillac Operations Inc.
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West Coast Power LLC |
NRG California Peaker Operations LLC |
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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.
24
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2007
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NRG Energy, |
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Guarantor |
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Non-Guarantor |
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Inc. |
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Consolidated |
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(Note Issuer) |
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Eliminations(a) |
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Balance |
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Operating Revenues |
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
1,215 |
|
|
$ |
95 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,310 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
716 |
|
|
|
66 |
|
|
|
2 |
|
|
|
|
|
|
|
784 |
|
Depreciation and amortization |
|
|
153 |
|
|
|
7 |
|
|
|
1 |
|
|
|
|
|
|
|
161 |
|
General and administrative |
|
|
28 |
|
|
|
3 |
|
|
|
55 |
|
|
|
|
|
|
|
86 |
|
Development costs |
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23 |
|
|
Total operating costs and expenses |
|
|
920 |
|
|
|
76 |
|
|
|
58 |
|
|
|
|
|
|
|
1,054 |
|
Gain on sale of assets |
|
|
18 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
17 |
|
|
Operating Income/(Loss) |
|
|
313 |
|
|
|
19 |
|
|
|
(59 |
) |
|
|
|
|
|
|
273 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
32 |
|
|
|
|
|
|
|
156 |
|
|
|
(188 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
(2 |
) |
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
Other income, net |
|
|
2 |
|
|
|
9 |
|
|
|
10 |
|
|
|
(5 |
) |
|
|
16 |
|
Interest expense |
|
|
(70 |
) |
|
|
(26 |
) |
|
|
(90 |
) |
|
|
5 |
|
|
|
(181 |
) |
|
Total other income/( expense) |
|
|
(38 |
) |
|
|
(2 |
) |
|
|
76 |
|
|
|
(188 |
) |
|
|
(152 |
) |
|
Income From Continuing Operations Before Income Taxes |
|
|
275 |
|
|
|
17 |
|
|
|
17 |
|
|
|
(188 |
) |
|
|
121 |
|
Income Tax Expense/(Benefit) |
|
|
99 |
|
|
|
5 |
|
|
|
(48 |
) |
|
|
|
|
|
|
56 |
|
|
Net Income |
|
$ |
176 |
|
|
$ |
12 |
|
|
$ |
65 |
|
|
$ |
(188 |
) |
|
$ |
65 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
25
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
NRG Energy, Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(a) |
|
|
Balance |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
|
|
|
$ |
170 |
|
|
$ |
534 |
|
|
$ |
|
|
|
$ |
704 |
|
Accounts receivable, net |
|
|
369 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
409 |
|
Inventory |
|
|
387 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
400 |
|
Derivative instruments valuation |
|
|
853 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
854 |
|
Prepayments and other current assets |
|
|
213 |
|
|
|
13 |
|
|
|
200 |
|
|
|
(124 |
) |
|
|
302 |
|
|
Total current assets |
|
|
1,822 |
|
|
|
236 |
|
|
|
735 |
|
|
|
(124 |
) |
|
|
2,669 |
|
|
Net property, plant and equipment |
|
|
11,104 |
|
|
|
399 |
|
|
|
18 |
|
|
|
|
|
|
|
11,521 |
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
488 |
|
|
|
|
|
|
|
9,155 |
|
|
|
(9,643 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
28 |
|
|
|
333 |
|
|
|
|
|
|
|
|
|
|
|
361 |
|
Notes receivable and capital lease |
|
|
1,027 |
|
|
|
476 |
|
|
|
5,474 |
|
|
|
(6,501 |
) |
|
|
476 |
|
Goodwill |
|
|
1,787 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,787 |
|
Intangible assets, net |
|
|
957 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
958 |
|
Nuclear decommissioning trust |
|
|
357 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
357 |
|
Derivative instruments valuation |
|
|
182 |
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
187 |
|
Other non-current assets |
|
|
24 |
|
|
|
84 |
|
|
|
175 |
|
|
|
|
|
|
|
283 |
|
Intangible assets held-for-sale |
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
112 |
|
|
Total other assets |
|
|
4,962 |
|
|
|
894 |
|
|
|
14,809 |
|
|
|
(16,144 |
) |
|
|
4,521 |
|
|
Total Assets |
|
$ |
17,888 |
|
|
$ |
1,529 |
|
|
$ |
15,562 |
|
|
$ |
(16,268 |
) |
|
$ |
18,711 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt |
|
$ |
40 |
|
|
$ |
100 |
|
|
$ |
36 |
|
|
$ |
(47 |
) |
|
$ |
129 |
|
Accounts payable |
|
|
(850 |
) |
|
|
271 |
|
|
|
874 |
|
|
|
|
|
|
|
295 |
|
Derivative instruments valuation |
|
|
824 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
824 |
|
Accrued expenses and other current liabilities |
|
|
340 |
|
|
|
65 |
|
|
|
(8 |
) |
|
|
(77 |
) |
|
|
320 |
|
|
Total current liabilities |
|
|
354 |
|
|
|
436 |
|
|
|
902 |
|
|
|
(124 |
) |
|
|
1,568 |
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
5,474 |
|
|
|
837 |
|
|
|
8,827 |
|
|
|
(6,501 |
) |
|
|
8,637 |
|
Nuclear decommissioning reserve |
|
|
280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
280 |
|
Nuclear decommissioning trust liability |
|
|
335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
335 |
|
Deferred income taxes |
|
|
532 |
|
|
|
(123 |
) |
|
|
214 |
|
|
|
|
|
|
|
623 |
|
Derivative instruments valuation |
|
|
394 |
|
|
|
6 |
|
|
|
18 |
|
|
|
|
|
|
|
418 |
|
Out-of-market contracts |
|
|
839 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
839 |
|
Other long-term obligations |
|
|
379 |
|
|
|
30 |
|
|
|
28 |
|
|
|
|
|
|
|
437 |
|
|
Total non-current liabilities |
|
|
8,233 |
|
|
|
750 |
|
|
|
9,087 |
|
|
|
(6,501 |
) |
|
|
11,569 |
|
|
Total liabilities |
|
|
8,587 |
|
|
|
1,186 |
|
|
|
9,989 |
|
|
|
(6,625 |
) |
|
|
13,137 |
|
|
Minority interest |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
9,301 |
|
|
|
342 |
|
|
|
5,326 |
|
|
|
(9,643 |
) |
|
|
5,326 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
17,888 |
|
|
$ |
1,529 |
|
|
$ |
15,562 |
|
|
$ |
(16,268 |
) |
|
$ |
18,711 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
26
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Guarantor |
|
|
Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(a) |
|
|
Balance |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
176 |
|
|
$ |
12 |
|
|
$ |
65 |
|
|
$ |
(188 |
) |
|
$ |
65 |
|
Adjustments to reconcile net income to net cash provided
by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions less than equity earnings of
unconsolidated affiliates and consolidated
subsidiaries |
|
|
272 |
|
|
|
(12 |
) |
|
|
146 |
|
|
|
(416 |
) |
|
|
(10 |
) |
Depreciation and amortization of nuclear fuel |
|
|
166 |
|
|
|
7 |
|
|
|
1 |
|
|
|
|
|
|
|
174 |
|
Amortization of financing costs and debt discount |
|
|
|
|
|
|
2 |
|
|
|
7 |
|
|
|
|
|
|
|
9 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29 |
) |
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
7 |
|
Changes in deferred income taxes |
|
|
21 |
|
|
|
(3 |
) |
|
|
29 |
|
|
|
|
|
|
|
47 |
|
Changes in nuclear decommissioning liability |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Changes in derivatives |
|
|
91 |
|
|
|
1 |
|
|
|
(2 |
) |
|
|
|
|
|
|
90 |
|
Gain on sale of assets |
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(17 |
) |
Gain on sale of emission allowances |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Changes in collateral deposits supporting energy risk
management activities |
|
|
(120 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(120 |
) |
Cash provided by/(used by) changes in other working
capital, net of dispositions affects |
|
|
(155 |
) |
|
|
(11 |
) |
|
|
52 |
|
|
|
|
|
|
|
(114 |
) |
|
Net Cash Provided by Operating Activities |
|
|
409 |
|
|
|
(4 |
) |
|
|
305 |
|
|
|
(604 |
) |
|
|
106 |
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from payment of intercompany loans |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
(12 |
) |
|
|
|
|
Capital expenditures |
|
|
(106 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(107 |
) |
Decrease/(increase) in restricted cash |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
(5 |
) |
Decrease/(increase) in notes receivable |
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Purchases of emission allowances |
|
|
(61 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(61 |
) |
Proceeds from sale of emission allowances |
|
|
32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32 |
|
Proceeds from sale of assets |
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29 |
|
Purchases in trust fund securities |
|
|
(68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(68 |
) |
Proceeds from sales of trust fund securities |
|
|
59 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59 |
|
|
Net Cash Provided/Used by Investing Activities |
|
|
(115 |
) |
|
|
3 |
|
|
|
12 |
|
|
|
(12 |
) |
|
|
(112 |
) |
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments to Parent for intercompany loans |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
12 |
|
|
|
|
|
Payments from intercompany dividends |
|
|
(302 |
) |
|
|
(302 |
) |
|
|
|
|
|
|
604 |
|
|
|
|
|
Payments for dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
(14 |
) |
Payments for treasury stock |
|
|
|
|
|
|
|
|
|
|
(103 |
) |
|
|
|
|
|
|
(103 |
) |
Payments for short and long-term debt |
|
|
(1 |
) |
|
|
(9 |
) |
|
|
(9 |
) |
|
|
|
|
|
|
(19 |
) |
|
Net Cash Used by Financing Activities |
|
|
(315 |
) |
|
|
(311 |
) |
|
|
(126 |
) |
|
|
616 |
|
|
|
(136 |
) |
Effect of Exchange Rate Changes on Cash and Cash
Equivalents |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
Net Increase/(Decrease) in Cash and Cash Equivalent |
|
|
(21 |
) |
|
|
(310 |
) |
|
|
191 |
|
|
|
|
|
|
|
(140 |
) |
Cash and Cash Equivalents at Beginning of Period |
|
|
20 |
|
|
|
432 |
|
|
|
343 |
|
|
|
|
|
|
|
795 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
(1 |
) |
|
$ |
122 |
|
|
$ |
534 |
|
|
$ |
|
|
|
$ |
655 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
27
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
December 31, 2006
|
|
|
|
|
|
|
|
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|
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|
Guarantor |
|
|
Non-Guarantor |
|
|
NRG Energy, Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(a) |
|
|
Balance |
|
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
20 |
|
|
$ |
432 |
|
|
$ |
343 |
|
|
$ |
|
|
|
$ |
795 |
|
Restricted cash |
|
|
1 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
44 |
|
Accounts receivable-trade, net |
|
|
332 |
|
|
|
40 |
|
|
|
|
|
|
|
|
|
|
|
372 |
|
Inventory |
|
|
408 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
421 |
|
Derivative instruments valuation |
|
|
1,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,230 |
|
Prepayments and other current assets |
|
|
200 |
|
|
|
32 |
|
|
|
736 |
|
|
|
(747 |
) |
|
|
221 |
|
|
Total current assets |
|
|
2,191 |
|
|
|
560 |
|
|
|
1,079 |
|
|
|
(747 |
) |
|
|
3,083 |
|
|
Net property, plant and equipment |
|
|
11,178 |
|
|
|
403 |
|
|
|
19 |
|
|
|
|
|
|
|
11,600 |
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
730 |
|
|
|
|
|
|
|
9,163 |
|
|
|
(9,893 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
31 |
|
|
|
313 |
|
|
|
|
|
|
|
|
|
|
|
344 |
|
Notes receivable and capital lease |
|
|
1,015 |
|
|
|
479 |
|
|
|
5,503 |
|
|
|
(6,518 |
) |
|
|
479 |
|
Goodwill |
|
|
1,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,789 |
|
Intangible assets, net |
|
|
977 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
981 |
|
Nuclear decommissioning trust fund |
|
|
352 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
352 |
|
Derivative instruments valuation |
|
|
424 |
|
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
439 |
|
Other non-current assets |
|
|
51 |
|
|
|
56 |
|
|
|
182 |
|
|
|
|
|
|
|
289 |
|
Intangible assets held-for-sale |
|
|
78 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
79 |
|
|
Total other assets |
|
|
5,447 |
|
|
|
852 |
|
|
|
14,864 |
|
|
|
(16,411 |
) |
|
|
4,752 |
|
|
Total Assets |
|
$ |
18,816 |
|
|
$ |
1,815 |
|
|
$ |
15,962 |
|
|
$ |
(17,158 |
) |
|
$ |
19,435 |
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt |
|
$ |
460 |
|
|
$ |
101 |
|
|
$ |
37 |
|
|
$ |
(468 |
) |
|
$ |
130 |
|
Accounts payable |
|
|
(682 |
) |
|
|
287 |
|
|
|
727 |
|
|
|
|
|
|
|
332 |
|
Derivative instruments valuation |
|
|
964 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
964 |
|
Deferred income taxes |
|
|
23 |
|
|
|
7 |
|
|
|
134 |
|
|
|
|
|
|
|
164 |
|
Accrued expenses and other current liabilities |
|
|
509 |
|
|
|
53 |
|
|
|
160 |
|
|
|
(280 |
) |
|
|
442 |
|
|
Total current liabilities |
|
|
1,274 |
|
|
|
448 |
|
|
|
1,058 |
|
|
|
(748 |
) |
|
|
2,032 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital lease |
|
|
5,504 |
|
|
|
869 |
|
|
|
8,791 |
|
|
|
(6,517 |
) |
|
|
8,647 |
|
Nuclear decommissioning reserve |
|
|
289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
289 |
|
Nuclear decommissioning trust liability |
|
|
324 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
324 |
|
Deferred income taxes |
|
|
494 |
|
|
|
(104 |
) |
|
|
164 |
|
|
|
|
|
|
|
554 |
|
Derivative instruments valuation |
|
|
325 |
|
|
|
6 |
|
|
|
20 |
|
|
|
|
|
|
|
351 |
|
Out-of-market contracts |
|
|
897 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
897 |
|
Other non-current liabilities |
|
|
385 |
|
|
|
26 |
|
|
|
24 |
|
|
|
|
|
|
|
435 |
|
|
Total non-current liabilities |
|
|
8,218 |
|
|
|
797 |
|
|
|
8,999 |
|
|
|
(6,517 |
) |
|
|
11,497 |
|
|
Total liabilities |
|
|
9,492 |
|
|
|
1,245 |
|
|
|
10,057 |
|
|
|
(7,265 |
) |
|
|
13,529 |
|
|
Minority interest |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
9,324 |
|
|
|
569 |
|
|
|
5,658 |
|
|
|
(9,893 |
) |
|
|
5,658 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
18,816 |
|
|
$ |
1,815 |
|
|
$ |
15,962 |
|
|
$ |
(17,158 |
) |
|
$ |
19,435 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
28
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(a) |
|
|
Balance |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
$ |
957 |
|
|
$ |
86 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,043 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
596 |
|
|
|
61 |
|
|
|
2 |
|
|
|
|
|
|
|
659 |
|
Depreciation and amortization |
|
|
111 |
|
|
|
6 |
|
|
|
1 |
|
|
|
|
|
|
|
118 |
|
General and administrative |
|
|
22 |
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
57 |
|
|
Total operating costs and expenses |
|
|
729 |
|
|
|
67 |
|
|
|
38 |
|
|
|
|
|
|
|
834 |
|
|
Operating Income |
|
|
228 |
|
|
|
19 |
|
|
|
(38 |
) |
|
|
|
|
|
|
209 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
22 |
|
|
|
|
|
|
|
161 |
|
|
|
(183 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
|
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
21 |
|
Write down of equity method investment |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Other income, net |
|
|
3 |
|
|
|
75 |
|
|
|
7 |
|
|
|
(5 |
) |
|
|
80 |
|
Refinancing expenses |
|
|
|
|
|
|
|
|
|
|
(178 |
) |
|
|
|
|
|
|
(178 |
) |
Interest expense |
|
|
(54 |
) |
|
|
(16 |
) |
|
|
(50 |
) |
|
|
5 |
|
|
|
(115 |
) |
|
Total other income/(expense) |
|
|
(32 |
) |
|
|
80 |
|
|
|
(60 |
) |
|
|
(183 |
) |
|
|
(195 |
) |
|
Income From Continuing Operations Before Income Taxes |
|
|
196 |
|
|
|
99 |
|
|
|
(98 |
) |
|
|
(183 |
) |
|
|
14 |
|
Income tax expense/(benefit) |
|
|
85 |
|
|
|
35 |
|
|
|
(121 |
) |
|
|
|
|
|
|
(1 |
) |
|
Income From Continuing Operations |
|
|
111 |
|
|
|
64 |
|
|
|
23 |
|
|
|
(183 |
) |
|
|
15 |
|
Income from discontinued operations, net of
income taxes |
|
|
|
|
|
|
8 |
|
|
|
3 |
|
|
|
|
|
|
|
11 |
|
|
Net Income |
|
$ |
111 |
|
|
$ |
72 |
|
|
$ |
26 |
|
|
$ |
(183 |
) |
|
$ |
26 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
29
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2006
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non- |
|
|
NRG Energy, |
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Guarantor |
|
|
Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(a) |
|
|
Balance |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
111 |
|
|
$ |
72 |
|
|
$ |
26 |
|
|
$ |
(183 |
) |
|
$ |
26 |
|
Adjustments to reconcile net income to net cash
provided by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions more/(less) than equity earnings of
unconsolidated affiliates and consolidated
subsidiaries |
|
|
22 |
|
|
|
(12 |
) |
|
|
161 |
|
|
|
(183 |
) |
|
|
(12 |
) |
Depreciation and amortization of nuclear fuel |
|
|
111 |
|
|
|
12 |
|
|
|
2 |
|
|
|
|
|
|
|
125 |
|
Amortization of financing costs and debt discount |
|
|
|
|
|
|
2 |
|
|
|
8 |
|
|
|
|
|
|
|
10 |
|
Amortization of intangibles and out-of-market contracts |
|
|
3 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
3 |
|
Write-off of deferred financing costs and debt premium |
|
|
|
|
|
|
|
|
|
|
47 |
|
|
|
|
|
|
|
47 |
|
Write down of equity method investments |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Changes in deferred income taxes |
|
|
28 |
|
|
|
3 |
|
|
|
15 |
|
|
|
|
|
|
|
46 |
|
Changes in nuclear decommissioning liability |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Changes in derivatives |
|
|
(23 |
) |
|
|
(2 |
) |
|
|
4 |
|
|
|
|
|
|
|
(21 |
) |
Gain on sale of emission allowances |
|
|
(59 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(59 |
) |
Gain on legal settlement |
|
|
|
|
|
|
(67 |
) |
|
|
|
|
|
|
|
|
|
|
(67 |
) |
Gain on sale of discontinued operations |
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
Changes in collateral deposits supporting energy risk
management activities |
|
|
230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
230 |
|
Cash provided by(used by) changes in other working
capital, net of dispositions affects |
|
|
(281 |
) |
|
|
36 |
|
|
|
(106 |
) |
|
|
366 |
|
|
|
15 |
|
|
Net Cash Provided by Operating Activities |
|
|
142 |
|
|
|
40 |
|
|
|
160 |
|
|
|
|
|
|
|
342 |
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Texas Genco LLC and WCP |
|
|
|
|
|
|
|
|
|
|
(4,288 |
) |
|
|
|
|
|
|
(4,288 |
) |
Capital expenditures |
|
|
(32 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
(35 |
) |
Decrease/(increase) in restricted cash |
|
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Changes in notes receivable |
|
|
|
|
|
|
8 |
|
|
|
(2,760 |
) |
|
|
2,760 |
|
|
|
8 |
|
Investments in trust fund securities |
|
|
(42 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(42 |
) |
Purchases of emission allowances |
|
|
(15 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(15 |
) |
Proceeds from the sale of emission allowances |
|
|
68 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
68 |
|
Proceeds from sales of trust fund securities |
|
|
45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45 |
|
Proceeds from sale of investments |
|
|
45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45 |
|
Proceeds from sale of discontinued operations |
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
15 |
|
|
Net Cash Used by Investing Activities |
|
|
69 |
|
|
|
17 |
|
|
|
(7,048 |
) |
|
|
2,760 |
|
|
|
(4,202 |
) |
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments for dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
|
|
|
|
(10 |
) |
Payment of financing element of acquired derivatives |
|
|
(29 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(29 |
) |
Proceeds from issuance of common stock, net |
|
|
|
|
|
|
|
|
|
|
986 |
|
|
|
|
|
|
|
986 |
|
Proceeds from issuance of preferred shares, net |
|
|
|
|
|
|
|
|
|
|
486 |
|
|
|
|
|
|
|
486 |
|
Proceeds from issuance of long-term debt |
|
|
2,760 |
|
|
|
|
|
|
|
7,175 |
|
|
|
(2,760 |
) |
|
|
7,175 |
|
Funded letter of credit |
|
|
|
|
|
|
|
|
|
|
350 |
|
|
|
|
|
|
|
350 |
|
Payment of deferred debt issuance costs |
|
|
|
|
|
|
|
|
|
|
(164 |
) |
|
|
|
|
|
|
(164 |
) |
Payments for short and long-term debt |
|
|
(2,735 |
) |
|
|
(12 |
) |
|
|
(1,876 |
) |
|
|
|
|
|
|
(4,623 |
) |
|
Net Cash Provided/(Used) by Financing Activities |
|
|
(4 |
) |
|
|
(12 |
) |
|
|
6,947 |
|
|
|
(2,760 |
) |
|
|
4,171 |
|
Effect of Exchange Rate Changes on Cash and Cash
Equivalents |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Change in Cash from Discontinued Operations |
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
|
|
|
|
(17 |
) |
|
Net Increase/(Decrease) in Cash and Cash
Equivalents |
|
|
207 |
|
|
|
29 |
|
|
|
59 |
|
|
|
|
|
|
|
295 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
(7 |
) |
|
|
78 |
|
|
|
422 |
|
|
|
|
|
|
|
493 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
200 |
|
|
$ |
107 |
|
|
$ |
481 |
|
|
$ |
|
|
|
$ |
788 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
30
Note 17 Subsequent Events
During May 2007, the Company plans to seek several amendments to its Senior Credit Facility.
The amendments include:
|
|
|
Lower pricing for NRGs Term B loan and synthetic Letter of Credit facility; |
|
|
|
|
A provision that enables up to $150 million annually for the payment of a recurring cash
dividend on the Companys common stock; |
|
|
|
|
Reduction in the synthetic Letter of Credit facility from $1.5 billion to $1.3 billion; |
|
|
|
|
Ability to utilize a first lien position to support commercial hedges; |
|
|
|
|
Additional flexibility for RepoweringNRG projects; and |
|
|
|
|
A commitment from lenders that effectively converts one-third of existing Term B debt (approximately $1 billion in the
aggregate) to
a holding company level planned for later this year. |
To improve the efficiency of its capital allocation, the Company is planning to implement a
holding company structure in the second half of 2007. Under the planned structure:
|
|
|
NRG will become a wholly-owned operating subsidiary, or Opco, of a newly created holding
company, or Holdco, and the shareholders of the Company will become shareholders of Holdco; |
|
|
|
|
Holdco will borrow up to $1 billion in new Term B loan financing from its existing bank
group; and |
|
|
|
|
Holdco will use the net proceeds to make a capital contribution to Opco, which Opco in
turn will use for the prepayment of its Term B debt under the Senior Credit Facility. |
Upon completion of the above, the Companys restricted payments capacity under its unsecured
indenture will increase by an amount equal to the capital
contribution from Holdco to Opco, thereby
allowing a more efficient allocation of capital within the Company. On May 1, 2007, the Company
entered into a commitment with certain financial institutions to backstop the $1 billion financing
planned for the Holdco level. Implementation of
the Holdco structure described above is contingent upon a number of conditions being satisfied,
including receiving certain regulatory approvals. While there can be no assurance that all of
these conditions will be satisfied, the Company believes that the Holdco structure will be
implemented by the end of 2007.
31
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction and Overview
NRG Energy, Inc., NRG, or the Company, is a wholesale power generation company with a
significant presence in major competitive power markets in the United States. NRG is primarily
engaged in the ownership, development, construction and operation of power generation facilities,
the transacting in and trading of fuel and transportation services, and the trading of energy,
capacity and related products in the United States and internationally. As of March 31, 2007, NRG
had a total global portfolio of 191 active operating generation units at 49 power generation
plants, with an aggregate generation capacity of approximately 24,025 MW. Within the United
States, the Company has one of the largest and most diversified power generation portfolios in
terms of geography, fuel-type and dispatch levels, with approximately 22,790 MW of generation
capacity in 175 active generating units at 43 plants. These power generation facilities are
primarily located in Texas (approximately 10,785 MW), and the Northeast (approximately 7,160 MW),
South Central (approximately 2,850 MW), and the West (approximately 1,870 MW) regions of the United
States, with approximately 125 MW of additional generation capacity from the Companys thermal
assets. NRGs principal domestic power plants consist of a diversified mix of natural gas-, coal-,
oil-fired and nuclear facilities, representing approximately 45%, 34%, 16% and 5% of the Companys
total domestic generation capacity, respectively. In addition, 15% of NRGs domestic generating
facilities have dual or multiple fuel capacity, which allows plants to dispatch with the lowest
cost fuel option, and consist primarily of baseload, intermediate and peaking power generation
facilities, which are referred to as the merit order, and also include thermal energy production
plants. The sale of capacity and power from baseload generation facilities accounts for the
majority of the Companys revenues and provides a stable source of cash flow. In addition, NRGs
diverse 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. In
addition, NRG is pursuing opportunities to repower existing facilities and develop new generation
capacity in markets in which NRG currently owns assets in an initiative referred to as
RepowerinNRG. In connection with NRGs acquisition of Padoma Wind Power LLC, the Company has and
will continue to actively evaluate and potentially develop or construct domestic terrestrial wind
projects as part of the RepoweringNRG program.
NRGs 2006 Annual Report on Form 10-K includes a detailed discussion of various items
impacting its business, results of operations, and financial condition. These include:
|
|
|
Introduction and Overview section which provides a description of NRGs business segments; |
|
|
|
Strategy section; |
|
|
|
Business Environment section, including how regulation, weather, and other factors affect NRGs business; and |
|
|
|
Critical Accounting Policies section. |
Critical accounting policies are the accounting policies that are most important to the
portrayal of NRGs financial condition and results of operations and require managements most
difficult, subjective, or complex judgment. NRGs critical accounting policies include revenue
recognition and derivative accounting, income taxes and valuation allowance for deferred taxes,
evaluation of assets for impairment and other than temporary decline in value, goodwill and other
intangible assets, and contingencies.
This discussion and analysis explains the general financial condition and the results of
operations for NRG, including:
|
|
|
factors which affect the business; |
|
|
|
earnings and costs in the periods presented; |
|
|
|
changes in earnings and costs between periods; |
|
|
|
sources of earnings; |
|
|
|
impact of these factors on NRGs overall financial condition; |
|
|
|
expected future expenditures for capital projects; and |
|
|
|
expected sources of cash for further operations and capital expenditures. |
As you read this discussion and analysis, refer to the consolidated statements of income which
present the results of operations for the three months ended March 31, 2007 and 2006. NRG analyzes
and explains the differences between periods in the specific line items of the consolidated
statements of income.
NRG has organized the discussion and analysis as follows:
|
|
|
changes to the business environment during the period; |
32
|
|
|
results of operations beginning with an overview of NRGs consolidated results, followed
by a more detailed discussion of those results by major operating segment; |
|
|
|
financial condition, addressing liquidity, the sources and uses of cash, capital resources and commitments; |
|
|
|
known trends that will affect its results of operation and financial condition in the future. |
Changes in Accounting Standards
See Note 1 to the condensed consolidated financial statements of this Form 10-Q as found in
Item 1 for a discussion of recent accounting developments.
Environmental Matters
On April 2, 2007, in Environmental Defense v. Duke Energy, the U.S. Supreme Court overturned a
decision by a lower court that had previously upheld Duke Energys modification of its coal plants
as consistent with the USEPAs PSD regulations. NRG has not relied upon the Duke Energy
interpretation of the PSD regulations whenever the Company has performed modifications at its
plants and thus does not expect any material adverse impact regarding NSR from the Supreme Courts
decision. Similarly, the Company has not relied upon the Duke Energy interpretation to support
its repowering program.
The January 2007 court ruling on the appeal of the Phase II 316(b) water regulation created
uncertainty for power plants that use once through cooling water. The regulation, for the most
part, was sent back to EPA for reconsideration and expressly prohibited restoration. On March 20,
2007, the EPA issued a memo to Regional Administrators suspending the rule and directing them to
rely on best professional judgment. Suspension of the rule is not expected to materially impact NRG
plans, but could delay implementation.
Regulatory Matters
As an operator of power plants and a participant in the wholesale markets, NRG is subject to
regulation by various federal and state government agencies. In addition, NRG is subject to the
market rules, procedures, and protocols of the various ISO markets in which NRG participates.
These wholesale power markets are subject to ongoing legislative and regulatory changes. In some
of NRGs regions, interested parties have advocated for material market design changes, including
the elimination of a single clearing price mechanism, as well as proposals to re-regulate the
markets or require divestiture by generating companies in order to reduce their market share. The
Company cannot predict the future design of the wholesale power markets or the ultimate effect that
the changing regulatory environment will have on NRGs business.
Northeast Region
New England - On April 26, 2007, the Company filed an RMR agreement for its Norwalk Power
facility, Units 1 & 2, with FERC, seeking a June 19, 2007 effective date and an annual fixed
revenue requirement of $38 million. This filing is in response to FERCs order eliminating the
Peaking Unit Safe Harbor, or PUSH, bidding mechanism effective June 19, 2007.
New York - On March 6, 2007, FERC rejected the NYISOs proposed tariff revisions that would
have imposed additional market power mitigation on the current owners of Consolidated Edisons
divested generation units in New York City, including NRGs Arthur Kill and Astoria facilities.
The proposed mitigation would have effectively lowered the capacity offer cap for those units from
$105/kW-year to $82/kW-year. Although the specific proposal was rejected, FERC initiated an
investigation to determine the justness and reasonableness of the NYISOs in-city ICAP market,
setting a refund effective date of May 12, 2007. FERC is expected to commence hearing procedures
as settlement procedures have concluded. The result of this proceeding could adversely impact
capacity revenues for NRGs units in New York.
West Region
In November 2006, NRG was awarded a 260 MW PPA by Southern California Edison, or SCE, to
repower Units 1-4 at the Companys Long Beach Generating Station in Long Beach, California. On
January 25, 2007, the CPUC issued its order approving the agreement and authorizing cost recovery
by SCE. Intervenors sought rehearing, and the CPUC issued an order on April 19, 2007 denying the petition of two intervenors.
These intervenors could appeal. NRG has reached a resolution with the
remaining intervenor. Although the CPUC approval is not final and NRG may face other challenges, NRG is
proceeding with the project.
33
Consolidated Results of Operations
The following table provides selected financial information for the Company for the three months
ended March 31, 2007 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
(In millions except otherwise noted) |
|
2007 |
|
|
2006 |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
947 |
|
|
$ |
556 |
|
|
|
70 |
% |
Capacity revenue |
|
|
273 |
|
|
|
290 |
|
|
|
(6 |
) |
Risk management activities |
|
|
(43 |
) |
|
|
52 |
|
|
|
NA |
|
Contract amortization |
|
|
52 |
|
|
|
44 |
|
|
|
18 |
|
Thermal revenue |
|
|
41 |
|
|
|
38 |
|
|
|
8 |
|
Other revenues |
|
|
40 |
|
|
|
63 |
|
|
|
(37 |
) |
|
|
|
|
|
Total operating revenues |
|
|
1,310 |
|
|
|
1,043 |
|
|
|
26 |
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
784 |
|
|
|
659 |
|
|
|
19 |
|
Depreciation and amortization |
|
|
161 |
|
|
|
118 |
|
|
|
36 |
|
General and administrative |
|
|
86 |
|
|
|
57 |
|
|
|
51 |
|
Development costs |
|
|
23 |
|
|
|
|
|
|
|
NA |
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,054 |
|
|
|
834 |
|
|
|
26 |
|
Gain on sale of assets |
|
|
17 |
|
|
|
|
|
|
|
NA |
|
|
|
|
|
|
Operating income |
|
|
273 |
|
|
|
209 |
|
|
|
31 |
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
13 |
|
|
|
21 |
|
|
|
(38 |
) |
Write down of equity method investments |
|
|
|
|
|
|
(3 |
) |
|
|
NA |
|
Other income, net |
|
|
16 |
|
|
|
80 |
|
|
|
(80 |
) |
Refinancing expenses |
|
|
|
|
|
|
(178 |
) |
|
|
NA |
|
Interest expense |
|
|
(181 |
) |
|
|
(115 |
) |
|
|
57 |
|
|
|
|
|
|
Total other expenses |
|
|
(152 |
) |
|
|
(195 |
) |
|
|
(22 |
) |
Income from Continuing Operations before income
tax expense |
|
|
121 |
|
|
|
14 |
|
|
|
764 |
|
Income tax expense/(benefit) |
|
|
56 |
|
|
|
(1 |
) |
|
|
NA |
|
|
|
|
|
|
Income from Continuing Operations |
|
|
65 |
|
|
|
15 |
|
|
|
333 |
|
Income from discontinued operations, net of
income tax expense |
|
|
|
|
|
|
11 |
|
|
|
NA |
|
|
|
|
|
|
Net Income |
|
$ |
65 |
|
|
$ |
26 |
|
|
|
150 |
|
|
|
|
|
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub (S/MMbtu) |
|
|
7.19 |
|
|
|
7.69 |
|
|
|
(7 |
)% |
|
NA Not Applicable
Consolidated Discussion:
Operating Revenues
Operating revenues increased by $267 million during the three months ended March 31, 2007,
compared to 2006. This was primarily due to:
o |
|
Energy revenues energy revenues increased by $391 million during the three months ended
March 31, 2007, compared to 2006: |
|
|
|
Texas energy revenues increased by $361 million for the three months ended March 31,
2007, compared to 2006. Of this increase $217 million was due to the inclusion of three
months activity in 2007 compared to two months in 2006, and $39 million is due to the Hedge
Reset as average forward prices increased by approximately $12 per MWh for 2007 compared to
2006. The remaining increase was due to a reduction of the Power Utility Commission of
Texas, or PUCT, auctioned capacity that is now being sold on the merchant market at higher
prices. Prior to the Acquisition, PUCT regulations required that Texas sell 15% of its
capacity by auction at reduced rates. In March 2006, the PUCT accepted NRGs request to
discontinue these auctions and such capacity is now being sold in the merchant market at
higher prices. |
34
|
|
|
Northeast energy revenues
increased by approximately $49 million of which $24 million
was due to an 11% increase in generation led by the regions oil-fired assets whose
generation increased by 176 thousand MWh compared to 2006 and $25 million was due to a
7% increase in average power prices. These increases were due to a relatively colder
winter during 2007 compared to 2006 as demonstrated by a 12% increase in HDDs in the
region. |
o |
|
Capacity revenues capacity revenues decreased by $17 million during the three months ended
March 31, 2007, compared to 2006, due to a decrease in the Texas capacity revenues that were
partially offset by increases in capacity revenues in the Northeast and West regions: |
|
|
|
Texas capacity revenues decreased by $73 million in the first quarter 2007 compared to
2006 due to a reduction of auction sales mandated by the PUCT in prior years as described
above. |
|
|
|
Northeast
capacity revenues increased by $25 million - $12 million of the increase is
from the NEPOOL assets and $12 million is from New York Rest of State assets. The NEPOOL
assets benefited from the new LFRM market and transition capacity market, both introduced
in the fourth quarter of 2006. During the three months ended March 31, 2007, capacity
revenues increased by $9 million from the LFRM market and $7 million from transition
capacity payments, offset by a reduction of $4 million due to the expiration of an RMR
agreement for our Devon plant on December 31, 2006. New York Rest of State capacity prices
increased by 174% during the first quarter of 2007 compared to 2006 as load requirement
growth increased demand for capacity, coupled with the impact from the new capacity markets
in NEPOOL which reduced exported supply into the New York market that further improved the
supply/demand dynamics. |
|
|
|
West capacity revenues increased by $26 million as its results were not consolidated
during the three months ended March 31, 2006. These capacity revenues are comprised of new
tolling agreements at the El Segundo and Encina plants that will expire in April 2008 and
December 2009, respectively. |
o |
|
Contract amortization
revenues from contract amortization increased
by $8 million during the three months ended March 31, 2007, compared
to 2006, as a result of in-the-market power contracts acquired with
Texas Genco LLC that were fully amortized in 2006. In-the-market
power contracts are amortized as a reduction to revenues. |
o |
|
Other revenues other revenues decreased by $23 million during the
three months ended March 31, 2007 compared to 2006 due to the
following factors: |
|
|
|
Sale of SO2 allowances net sales of emission allowances decreased by $53
million for the quarter ended March 31, 2007, compared to 2006. Due to increased
generation and a decrease of approximately 59% in market prices, the Company reduced its
activity in the sale of emission allowances. |
|
|
|
Physical sale of natural gas with natural gas generation decreasing by 14%, the
Company sold its excess natural gas to third parties increasing other revenues by
approximately $19 million during the three months ended March 31, 2007, compared to 2006. |
|
|
|
Ancillary revenues during the three months ended March 31, 2007, the Companys
revenues from ancillary services increased by approximately $8 million due to a change in
strategy to actively provide ancillary services in the Texas region in lieu of merchant
revenues. |
o |
|
Risk management activities revenues from risk management activities include all derivative
activity that does not qualify for hedge accounting as well as the ineffective portion
associated with hedged transactions. Such revenues decreased by $95 million during the three
months ended March 31, 2007, compared to 2006. The breakdown of changes by region are as
follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended March 31, 2007 |
|
|
Three months ended March 31, 2006 |
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
(In millions) |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
Total |
|
|
Texas (a) |
|
|
Northeast |
|
|
Central |
|
|
Total |
|
|
|
|
Net gains/(losses) on
settled positions, or financial
revenues |
|
$ |
18 |
|
|
$ |
29 |
|
|
$ |
|
|
|
$ |
47 |
|
|
$ |
|
|
|
$ |
(1 |
) |
|
$ |
4 |
|
|
$ |
3 |
|
|
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously
recognized unrealized
(gains)/losses on settled
positions related to economic
hedges |
|
|
(31 |
) |
|
|
(26 |
) |
|
|
|
|
|
|
(57 |
) |
|
|
|
|
|
|
45 |
|
|
|
|
|
|
|
45 |
|
Reversal of previously
recognized unrealized
(gains)/losses on settled
positions related to trading
activity |
|
|
1 |
|
|
|
(9 |
) |
|
|
(5 |
) |
|
|
(13 |
) |
|
|
|
|
|
|
(24 |
) |
|
|
|
|
|
|
(24 |
) |
Net unrealized
gains/(losses) on open
positions related to economic
hedges |
|
|
(10 |
) |
|
|
(25 |
) |
|
|
|
|
|
|
(35 |
) |
|
|
(2 |
) |
|
|
30 |
|
|
|
1 |
|
|
|
29 |
|
Net unrealized
gains/(losses) on open
positions related to trading
activity |
|
|
2 |
|
|
|
2 |
|
|
|
11 |
|
|
|
15 |
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
Subtotal mark-to-market results |
|
|
(38 |
) |
|
|
(58 |
) |
|
|
6 |
|
|
|
(90 |
) |
|
|
(2 |
) |
|
|
50 |
|
|
|
1 |
|
|
|
49 |
|
Total derivative gain/(loss) |
|
$ |
(20 |
) |
|
$ |
(29 |
) |
|
$ |
6 |
|
|
$ |
(43 |
) |
|
$ |
(2 |
) |
|
$ |
49 |
|
|
$ |
5 |
|
|
$ |
52 |
|
|
|
|
|
(a) |
|
the period February 2, 2006 to March 31, 2006 only. |
35
NRGs first quarter 2007 loss was comprised of $90 million of mark-to-market losses
offset by $47 million in settled gains, or financial revenue. Of the $90 million of mark-to-market
losses, $57 million represents the reversal of mark-to-market gains recognized on economic hedges
during 2006 and $13 million from the reversal of mark-to-market gains recognized on trading
activity during 2006. Both of these gains ultimately settled as financial revenues during 2007.
The $35 million loss from economic hedge positions is comprised of a $79 million decrease in value
of forward sales of electricity and fuel due to unfavorable power and gas prices offset by a $44
million gain from hedge accounting ineffectiveness related to gas swaps in the Texas region due to
a change in the correlation at March 31, 2007, between natural gas and power prices.
Since these hedging activities are intended to mitigate the risk of commodity price movements
on revenues and cost of energy sold, the changes in such results should not be viewed in isolation,
but rather taken together with the effects of pricing and cost changes on energy revenues (which
are recorded net of financial instruments hedges that are afforded hedge accounting treatment) and
cost of energy.
Cost of Operations
Cost of operations for the year ended March 31, 2007, increased by $125 million compared to
2006, but as a percentage of revenues it decreased from 63% in 2006 to 60% in 2007:
|
o |
|
Cost of energy cost of energy increased by approximately $52 million during the three
month period ended March 31, 2007, compared to 2006. This increase is due to: |
|
|
|
Texas although Texas results included an additional months expense of $96 million
in 2007, this was offset by a $35 million reduction in purchased power during 2007 as
compared to 2006 and a reduction in amortized fuel costs of $15 million during 2007
compared to 2006. During 2006, Texas purchased power due to forced outages at the
Parish and Limestone plants. Amortized fuel costs decreased by $15 million due to
changes in purchase price allocations that were finalized in the fourth quarter of 2006.
In addition, coal expense decreased by approximately $6 million due to lower contractual
rates for coal purchases. |
|
|
|
Northeast Northeast expenses increased by $36 million due to an 11% increase in
generation, resulting in $33 million of additional oil costs and $15 million of
additional natural gas costs. This was offset by reduced emission allowance
amortization expense of $8 million and lower coal expense of approximately $4 million.
The change in emission amortization expense was due to the reduced value of emission
allowances with the reduction in coal expense due to lower contractual rates on coal
purchases. |
|
|
|
South Central although South Central generation was relatively flat, cost of
energy decreased by $9 million. Higher coal and transportation costs due to contractual
rate increases resulted in a $7 million increase in fuel expense, while transmission
costs increased by $4 million due to contractual increases in transmission rates; these
increases were offset by lower purchased power of $19 million
due to the increased
reliance of satisfying contract load requirements with generation from the regions Big
Cajun II plant. |
|
o |
|
Other operating expenses Other operating expenses increased by $73 million during the
three month period ended March 31, 2007, compared to 2006. This increase was primarily due
to: |
|
|
|
Acquisition of Texas and WCP the results for the three months ended March 31,
2007, included $38 million of Texas expenses and $15 million of WCP expenses that were
not included in the Companys results in 2006. |
|
|
|
Planned outages
Operations and maintenance expense increased by $16 million during
the two months ended March 31, 2007, compared to 2006 due to the planned refueling
outage at STP and an acceleration of the W. A. Parish Unit 5 planned outage. |
|
|
|
Property taxes property taxes increased by approximately $6 million due to the
increase in assessed values of the Companys assets following the acquisition of Texas
Genco LLC in 2006. |
36
Depreciation and Amortization
NRGs depreciation and amortization expense for the three months ended March 31, 2007
increased by $43 million compared to 2006. This increase was primarily due to:
|
o |
|
Texas acquisition
the inclusion of Texas results for three months in 2007 compared to
only two months in 2006 that resulted in an increase of approximately $38 million. |
|
o |
|
Impact of new environmental legislation Due to new and more restrictive environmental
legislation, the useful life of certain types of pollution control equipment has been reduced. The
company accelerated the depreciation of these types of equipment to reflect the remaining
useful life, resulting in increased depreciation of approximately $3 million. |
General and Administrative
NRGs general and administrative, or G&A, costs for the three months ended March 31, 2007
increased by $29 million compared to 2006. This increase was primarily due to:
|
o |
|
Texas acquisition
the inclusion of Texas results for three months in 2007 compared to
only two months in 2006 resulted in an increase of approximately $7 million. |
|
o |
|
Wage and Benefit Costs an increase in headcount, higher bonus accrual rates and
related benefit costs resulted in a $17 million increase in G&A. |
|
o |
|
Franchise tax the Companys Louisiana state franchise tax increased by approximately
$6 million during the three months ended March 31, 2007, as compared to 2006. This is
because the state of Louisiana franchise tax is assessed based on the Companys total debt
and equity that significantly increased following the acquisition of Texas Genco LLC. |
Development Costs
NRGs development costs were $23 million for the three months ended March 31, 2007. These
costs were due to the Companys RepoweringNRG projects:
|
o |
|
Texas Costs to develop nuclear units 3 and 4 at STP accounted for approximately $17
million of the Companys first quarter 2007 development costs. |
|
o |
|
Other project $5 million in development costs related to other RepoweringNRG project
in the Northeast and West regions as well as certain wind projects. |
Gain on Sale of Assets
NRGs gain on sale of assets for the three months ended March 31, 2007 was approximately $17
million. On January 3, 2007, NRG completed the sale of the Companys Red Bluff and Chowchilla II
power plants resulting in a pre-tax gain of approximately $18 million.
Equity in Earnings of Unconsolidated Affiliates
NRGs equity earnings from unconsolidated affiliates for the three months ended March 31, 2007
decreased by $8 million compared to 2006. This decrease was primarily due to:
|
o |
|
Sale of multiple equity investments equity earnings of $5 million were earned in the
three months ended March 31, 2006, from multiple affiliates that were either sold or
subsequently consolidated, including: WCP, Rocky Road, James River and Latin American Fund. |
|
o |
|
MIBRAG equity earnings were $5 million less during 2007 compared to 2006 following
reduced sales of coal. The reduction in sales is due to reduced demand from MIBRAGs
customers due to the warm winter in Germany this quarter and transmission difficulties
experienced by one of its primary customers. |
Other Income, Net
NRGs other income for the three months ended March 31, 2007 decreased by $64 million compared
to 2006. This decrease was primarily due to:
|
o |
|
Non-cash settlement during the first quarter 2006, NRG recorded approximately $67
million of other income associated with a settlement with an equipment manufacturer related
to turbine purchase agreements entered into in 1999 and 2001. The |
37
|
|
|
settlement resulted in the reversal of accounts payable totaling $35 million resulting from
the discharge of the previously recorded liability, and an adjustment
to record the value
of the equipment received to its fair value, resulting in income of approximately $32
million. |
|
o |
|
Interest income increased by approximately $2 million for the three months ended March
31, 2007 compared to 2006 due to higher market interest rates on deposits. |
Interest Expense
NRGs interest expense for the three months ended March 31, 2007 increased by $66 million
compared to 2006. This increase is due to:
|
o |
|
Refinancing for the
acquisition of Texas Genco LLC in February 2006 the Company
significantly increased its corporate debt facilities from approximately $2 billion as of
December 31, 2005, to approximately $7 billion as of March 31, 2006. This increased
interest expense for the three months ended March 31, 2007, by
$37 million compared to 2006. |
|
o |
|
Increase of $1.1 billion in debt for Hedge Reset the Company issued $1.1 billion in
Senior Notes due 2017 in November 2006 related to the Hedge Reset, which increased interest
expense by $20 million for the three months ended March 31, 2007. |
|
o |
|
Capital Allocation Program the Company issued a total of $330 million of debt to fund
Phase I of the Capital Allocation Program. This increased interest expense for the three
months ended March 31, 2007 by $7 million compared to 2006. |
In the first quarter 2006, NRG entered into interest rate swaps with the objective of fixing
the interest rate on a portion of NRGs new Senior Credit Facility. These swaps were designated as
cash flow hedges under FAS 133, and the impact associated with ineffectiveness was immaterial to
NRG financial results. For the three months ended March 31, 2007, NRG had deferred a loss of $7
million in other comprehensive income compared to deferred gains of $42 million in 2006.
Refinancing Expense
Refinancing expense decreased by $178 million during the three months ended March 31, 2007,
compared to 2006 due to the refinancing of the Companys corporate debt for the acquisition of
Texas Genco LLC on February 2, 2006. During 2007, NRG did not refinance any debt.
Income Tax Expense
Income tax expense increased by $57 million during the three months ended March 31, 2007,
compared to 2006. The effective tax rate was 46.3% and (7.1%) for the three months ended March 31,
2007 and 2006, respectively. The increase in tax expense was primarily due to increased profits
and an increase in permanent differences:
|
o |
|
Increased profits
income before tax increased by $107 million during the three months
ended March 31, 2007, compared to 2006, with a corresponding increase of approximately $42
million in tax expense. |
|
o |
|
Permanent differences |
|
|
|
Taxable dividends from foreign subsidiaries in January 2007 the Company transferred
the proceeds from the sale of its Flinders assets to the US creating additional tax
expense of approximately $5 million. |
|
|
|
Non-deductible interest interest expense from the stock buybacks from Phase I of
the Companys Capital Allocation Program increased tax expense by approximately $3
million. |
|
|
|
Lower tax rates in foreign jurisdictions lower tax rates at the Companys foreign
locations reduced tax expense by $6 million during the three months ended March 31, 2007
compared to 2006. |
|
|
|
During the first quarter 2006, the Company distributed payments from its disputed
claims reserve that reduced income tax expense by approximately $7 million. |
The effective tax rate may vary from period to period depending on, among other factors, the
geographic and business mix of earnings and losses and the creation of valuation allowances in
accordance with SFAS 109. These factors and others, including the Companys history of pre-tax
earnings and losses, are taken into account in assessing the ability to realize deferred tax
assets.
Income from Discontinued Operations, Net of Income Tax Expense
Income from discontinued operations decreased by $11 million during the three months ended
March 31, 2007, compared to 2006 as all discontinued operations were disposed of in 2006. During
2006 the Company sold its Audrain, Flinders and Resource Recovery operations that were classified as discontinued operations, with $10 million due to the after
tax gain from the sale of Audrain and $1 million due to the aggregated results of their remaining
operations for the three month period ended March 31, 2006.
38
Business Segment Results
The following is a detailed discussion of the results of operations of NRGs major wholesale power
generation business segments.
Texas
For a discussion of the business profile of the Companys Texas operations, see pages 18-22 of
NRG Energy, Incs. 2006 Annual Report on Form 10-K. First quarter 2007 results of operations are
not comparable to the first quarter 2006 results of operations for the Texas region due to the
acquisition of Texas Genco LLC on February 2, 2006.
Selected income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions except otherwise noted) |
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 (a) |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
563 |
|
|
$ |
202 |
|
|
|
179 |
|
Capacity revenue |
|
|
92 |
|
|
|
165 |
|
|
|
(44 |
) |
Risk management activities |
|
|
(20 |
) |
|
|
(2 |
) |
|
|
900 |
|
Contract amortization |
|
|
47 |
|
|
|
41 |
|
|
|
15 |
|
Other revenues |
|
|
13 |
|
|
|
|
|
|
|
NA |
|
|
|
|
|
|
Total operating revenues |
|
|
695 |
|
|
|
406 |
|
|
|
71 |
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
237 |
|
|
|
218 |
|
|
|
9 |
|
Other operating expenses |
|
|
186 |
|
|
|
95 |
|
|
|
96 |
|
Depreciation and amortization |
|
|
114 |
|
|
|
74 |
|
|
|
54 |
|
Operating Income |
|
$ |
159 |
|
|
$ |
18 |
|
|
|
783 |
|
|
|
|
|
|
MWh sold (in thousands) |
|
|
10,978 |
|
|
|
7,313 |
|
|
|
50 |
|
MWh generated (in thousands) |
|
|
10,742 |
|
|
|
6,538 |
|
|
|
64 |
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
56.95 |
|
|
|
55.35 |
|
|
|
3 |
|
Cooling Degree Days, or CDDs (b) |
|
|
102 |
|
|
|
97 |
|
|
|
5 |
|
CDDs 30 year rolling average |
|
|
80 |
|
|
|
66 |
|
|
|
21 |
|
Heating Degree Days, or HDDs (b) |
|
|
1,203 |
|
|
|
607 |
|
|
|
98 |
|
HDDs 30 year rolling average |
|
|
1,270 |
|
|
|
677 |
|
|
|
88 |
|
|
|
(a) |
|
For the period February 2, 2006 to March 31, 2006 only. |
|
(b) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income
For the three months ended March 31, 2007, operating income increased by $141 million as
compared to 2006. Of this increase, $68 million is due to the January 2007 results on 4.2 million
MWh of generation. For the two months ended March 31, 2007, the Hedge Reset increased the regions
revenues by approximately $39 million as compared to 2006 as the average price of the underlying
power contracts increased by $12 per MWh. Offsetting the Hedge Reset impact were increased
development costs and higher maintenance expenses.
Operating Revenues
Total operating revenues from the Texas region increased by $289 million during the three
months ended March 31, 2007, as compared to 2006, due to the following:
o |
|
Energy revenues energy revenues increased by $361 million for the three months ended March
31, 2007, compared to 2006. Of this increase, $217 million was due to the inclusion of three
months activity in 2007 compared to two months in 2006, and $39 million was mainly due to the
Hedge Reset as average forward prices increased by approximately $12 per MWh for 2007 compared
to 2006. The remaining increase was due to a reduction of the Power Utility Commission of
Texas, or PUCT, |
39
|
|
auctioned capacity that is now being sold on the merchant market at higher
prices. Prior to the Acquisition, PUCT regulations required that Texas sell
15% of its capacity by auction at reduced rates. In March 2006, the PUCT
accepted NRGs request to discontinue these auctions and such capacity is now
being sold in the merchant market at higher prices. |
o |
|
Capacity revenues capacity revenues decreased by
$73 million in the first quarter 2007 compared to
2006 due to reduction of auction sales mandated by
the PUCT in prior years. |
o |
|
Contract amortization
revenues from contract
amortization increased by $7 million during the three
months ended March 31, 2007, compared to 2006, as a
result of in-the-market power contracts acquired with
Texas Genco LLC that were fully amortized in 2006.
In-the-market power contracts are amortized as a
reduction to revenues. |
o |
|
Other revenues during the three months ended March
31, 2007, the Companys revenues from ancillary
services increased by approximately $10 million due
to a change in strategy to actively provide ancillary
services in the Texas region in lieu of merchant
revenues. |
Risk Management Activity Total derivative loss for the quarter was $20 million, compared to
a loss of $2 million in the first quarter of 2006, as the Companys derivative activity increased
during the second quarter of 2006. The derivative loss of $20 million is comprised of financial
revenues of $18 million offset by mark-to-market losses of $38 million. Of these mark-to-market
losses, $31 million was due to the roll-off of 2006 mark-to-market gains and $10 million was
related to for open positions on forward hedges a $54 million loss from forward contracted
electric and gas sales offset by a $44 million gain in cash flow hedge ineffectiveness due to a
decline in the correlation between natural gas and power prices.
Cost of Energy
Cost
of energy for the Texas region increased by $19 million during the three months ended
March 31, 2007, compared to 2006. This included an additional months expense of $96 million in
2007, without which cost of energy would have decreased by $77 million. This was due to:
|
o |
|
Purchased power decreased by $35 million during 2007 as compared to 2006 due to forced
outages at the regions Parish and Limestone plants in 2006. |
|
o |
|
Amortized fuel costs
decreased by approximately $15 million during 2007 as compared to
2006 due to changes in purchase price allocations that were finalized in the fourth quarter
of 2006 |
|
o |
|
Coal expense decreased by approximately $6 million due to lower contractual rates for
coal purchases. |
Other Operating Expenses
Other operating expenses for the Texas region increased by $91 million during the three months
ended March 31, 2007 compared to 2006. This was due to:
|
o |
|
Texas acquisition
the inclusion of Texas results for three months in 2007 compared to
only two months in 2006 that resulted in an increase of approximately $53 million, of which
$32 million was related to operating and maintenance costs, $6 million was property taxes
and $15 million was related to general and administrative expenses and corporate
allocations. |
|
o |
|
Planned outages
Operations and maintenance expense increased by $16 million during the
two months ended March 31, 2007, compared to 2006 due to the planned refueling outage at
STP and an acceleration of the W. A. Parish Unit 5 planned outage. |
|
o |
|
Development costs as part of RepoweringNRG, development costs totaled $18 million in
the first quarter 2007. Of this amount, $17 million was incurred for developing nuclear
Units 3 & 4 at STP. |
40
Northeast Region
For a discussion of the business profile of the Northeast region, see pages 22-25 of NRG
Energy, Incs. 2006 Annual Report on Form 10-K.
Selected income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions except otherwise noted) |
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
272 |
|
|
$ |
223 |
|
|
|
22 |
% |
Capacity revenue |
|
|
83 |
|
|
|
58 |
|
|
|
43 |
|
Risk management activities |
|
|
(29 |
) |
|
|
49 |
|
|
|
NA |
|
Other revenues |
|
|
16 |
|
|
|
62 |
|
|
|
(74 |
) |
|
|
|
|
|
Total operating revenues |
|
|
342 |
|
|
|
392 |
|
|
|
(13 |
) |
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
162 |
|
|
|
126 |
|
|
|
29 |
|
Other operating expenses |
|
|
103 |
|
|
|
93 |
|
|
|
11 |
|
Depreciation and amortization |
|
|
25 |
|
|
|
22 |
|
|
|
14 |
|
Operating Income |
|
$ |
52 |
|
|
$ |
150 |
|
|
|
(65 |
) |
|
|
|
|
|
MWh sold (in thousands) |
|
|
3,614 |
|
|
|
3,261 |
|
|
|
11 |
|
MWh generated (in thousands) |
|
|
3,614 |
|
|
|
3,261 |
|
|
|
11 |
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
78.46 |
|
|
|
72.99 |
|
|
|
7 |
|
Cooling Degree Days, or CDDs(a) |
|
|
|
|
|
|
|
|
|
|
|
|
CDDs 30 year rolling average |
|
|
|
|
|
|
|
|
|
|
|
|
Heating Degree Days, or HDDs(a) |
|
|
3,071 |
|
|
|
2,741 |
|
|
|
12 |
|
HDDs 30 year rolling average |
|
|
3,094 |
|
|
|
3,094 |
|
|
|
|
|
|
(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 $98 million for the three months ended March 31, 2007, compared
to 2006. This was due to:
|
o |
|
Lower operating revenues of approximately $50 million primarily related to losses in
risk management activities of $29 million and lower sales of emission allowances of
approximately $61 million. |
|
o |
|
Higher cost of energy
of approximately $36 million due to increased generation at the
regions oil-fired and natural-gas-fired plants in New York City. |
|
o |
|
Higher other operating
expenses of approximately $10 million due to higher wage and
benefit rates as a result of merit increases and rising benefit costs, as well as higher
major maintenance expense due to scheduled outage repairs. |
Operating Revenues
Operating revenues decreased by $50 million for the three months ended March 31, 2007,
compared to 2006, due to:
|
o |
|
Losses related to risk management activities losses of approximately $29 million
during 2007 compared to $49 million in gains in 2006. The $29 million loss includes a $58
million unrealized loss related to the changes in fair value of forward derivative
positions not qualifying for hedge accounting treatment as compared to a $50 million gain
in the same period in 2006 of which $26 million was related to economic hedges. This $58
million loss includes a $35 million loss from the roll-off in the quarter of forward
positions existing at end of fiscal year 2006. Risk management activity results in the
first quarter 2007 included $29 million in realized gains on settled power positions. |
|
o |
|
Reduction in other revenues of $46 million of which approximately $61 million was
due to reduced activity in the trading of emission allowance following both an increase in
generation and a 59% decrease in market prices offset by higher natural gas
sales of approximately $19 million. |
41
These were partially offset by:
|
o |
|
Higher energy revenues
of $49 million of which $24 million was due to an 11%
increase in generation led by the regions oil-fired assets whose generation increased by
176 thousand MWh compared to 2006 and $25 million was due to a 7% increase in average power
prices. These increases were due to a relatively colder winter during 2007 compared to
2006 as demonstrated by a 12% increase in HDDs in the region. |
|
o |
|
Higher capacity revenues
by $25 million - $12 million of the increase is from the
NEPOOL assets and $12 million is from New York Rest of State assets. The NEPOOL assets
benefited from the new LFRM market and transition capacity market, both introduced in the
fourth quarter of 2006. During the three months ended March 31, 2007, capacity revenues
increased by $9 million from the LFRM market and $7 million from transition capacity
payments, offset by a reduction of $4 million due to the expiration of an RMR agreement for
our Devon plant on December 31, 2006. New York Rest of State capacity prices increased by
174% during the first quarter of 2007 compared to 2006 as load requirement growth increased
demand for capacity, coupled with the impact from the new capacity markets in NEPOOL which
reduced exported supply into the New York market that further improved the supply/demand
dynamics. |
Cost of Energy
Cost of energy increased by $36 million for the three months ended March 31, 2007 compared to
2006, primarily due to:
|
o |
|
Higher oil costs
of approximately $33 million due to an 11% increase in generation of
which 176 thousand MWh was at the regions oil-fired plants. |
|
o |
|
Higher natural gas costs
of approximately $15 million due to higher natural
gas prices and transportation costs. |
This was partially offset by:
|
o |
|
Lower emission
amortization of approximately $8 million in amortization expense due to
a reduction in the value of the Companys emission allowances. |
|
o |
|
Lower coal costs
of $4 million due to lower average cost of generation from the
regions coal-fired assets as a result of lower average prices of purchased coal. |
Other Operating Expenses
Other operating expenses increased by $10 million for the three months ended March 31, 2007
compared to 2006, primarily due to:
|
o |
|
Higher wage and benefit
costs of approximately $4 million due to higher wages and
benefit rates as a result of merit increases and rising benefit costs as well as additional
overtime. |
|
o |
|
Higher major maintenance
expense of approximately $2 million due to increased outage repairs. |
|
o |
|
Higher corporate
allocations of approximately $2 million. |
42
South Central Region
For a discussion of the business profile of the South Central region, see pages 26-27 of NRG
Energy, Incs. 2006 Annual Report on Form 10-K.
Selected income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions except otherwise noted) |
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
87 |
|
|
$ |
109 |
|
|
|
(20 |
)% |
Capacity revenue |
|
|
52 |
|
|
|
48 |
|
|
|
(8 |
) |
Risk management activities |
|
|
6 |
|
|
|
5 |
|
|
|
20 |
|
Contract amortization |
|
|
5 |
|
|
|
4 |
|
|
|
25 |
|
Other revenues |
|
|
|
|
|
|
6 |
|
|
|
NA |
|
|
|
|
|
|
Total operating revenues |
|
|
150 |
|
|
|
172 |
|
|
|
(13 |
) |
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
81 |
|
|
|
90 |
|
|
|
(10 |
) |
Other operating expenses |
|
|
30 |
|
|
|
22 |
|
|
|
36 |
|
Depreciation and amortization |
|
|
17 |
|
|
|
16 |
|
|
|
6 |
|
Operating Income |
|
$ |
23 |
|
|
$ |
44 |
|
|
|
(48 |
) |
|
|
|
|
|
MWh sold (in thousands) |
|
|
2,826 |
|
|
|
2,874 |
|
|
|
(2 |
) |
MWh generated (in thousands) |
|
|
2,708 |
|
|
|
2,800 |
|
|
|
(3 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
57.62 |
|
|
|
54.05 |
|
|
|
7 |
|
Cooling Degree Days, or CDDs(a) |
|
|
102 |
|
|
|
114 |
|
|
|
(11 |
) |
CDDs 30 year rolling average |
|
|
80 |
|
|
|
80 |
|
|
|
|
|
Heating Degree Days, or HDDs(a) |
|
|
1,203 |
|
|
|
946 |
|
|
|
27 |
|
HDDs 30 year rolling average |
|
|
1,270 |
|
|
|
1,270 |
|
|
|
|
|
|
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Operating Income
Operating income for the South Central region declined by $21 million for the first quarter
2007 compared to the same period in 2006. Increased demand from the regions load customers
combined with lower availability of the regions Big Cajun II coal plant reduced the MWhs
available for sale to the merchant market.
Operating Revenues
Operating revenues decreased by $22 million for the three months ended March 31, 2007,
compared to 2006, due to:
|
o |
|
Lower merchant energy
revenues of approximately $38 million driven by increased demand
from the regions load customers combined with lower availability of the regions Big Cajun
II coal plant reduced the MWhs available for sale to the merchant market. |
|
o |
|
Lower emission sales
due to generation needs and a 59% reduction in market prices, the region did not
monetize any of the regions bank emission allowances during the first quarter ended 2007. |
This decrease was offset by:
|
o |
|
Higher contract energy
revenues of approximately $17 million, due to higher demand from
the regions contract customers of approximately 343 thousand MWh following cooler weather
during the first quarter 2007 as reflected by a 27% increase in HDDs compared to 2006. |
|
o |
|
Higher capacity revenues
of $4 million due to a new summer peak set in August 2006
which increased cooperative contract rates. |
43
Cost of Energy
Cost of energy decreased by $9 million for the three months ended
March 31, 2007, compared to
2006, due to:
|
o |
|
Lower purchased power
of approximately $19 million due to the increased reliance on
tolling agreements and lower average prices. |
This was offset by:
|
o |
|
Higher coal and
transportation costs of approximately $7 million and higher
transmission costs of approximately $4 million. These increases were due to higher unit and
contractual rate increases. |
Other Operating Expenses
Other operating expenses increased by $8 million for the three months ended March 31, 2007,
compared to 2006. This was due to Louisiana state franchise tax that increased by approximately $6
million. This is because the state of Louisiana franchise tax is assessed based on the Companys
total debt and equity that significantly increased following the acquisition of Texas Genco LLC.
West Region
For a discussion of the business profile of the West region, see pages 28-29 of NRG Energy,
Incs. 2006 Annual Report on Form 10-K.
Selected income statement data
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions except otherwise noted) |
|
|
|
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 (b) |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
1 |
|
|
$ |
|
|
|
|
NA |
|
Capacity revenue |
|
|
26 |
|
|
|
|
|
|
|
NA |
|
Risk management activities |
|
|
|
|
|
|
|
|
|
|
|
|
Other revenues |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
28 |
|
|
|
1 |
|
|
|
NA |
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
1 |
|
|
|
|
|
|
|
NA |
|
Other operating expenses |
|
|
20 |
|
|
|
3 |
|
|
|
567 |
|
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income |
|
$ |
7 |
|
|
$ |
(2 |
) |
|
|
NA |
|
|
|
|
|
|
MWh sold (in thousands) |
|
|
45 |
|
|
|
294 |
|
|
|
(85 |
) |
MWh generated (in thousands) |
|
|
81 |
|
|
|
294 |
|
|
|
(72 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
58.68 |
|
|
|
56.66 |
|
|
|
4 |
|
Cooling Degree Days, or CDDs(a) |
|
|
2 |
|
|
|
|
|
|
|
NA |
|
CDDs 30 year rolling average |
|
|
10 |
|
|
|
7 |
|
|
|
43 |
|
Heating Degree Days, or HDDs(a) |
|
|
1,586 |
|
|
|
1,434 |
|
|
|
11 |
|
HDDs 30 year rolling average |
|
|
1,419 |
|
|
|
1,419 |
|
|
|
|
|
|
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
|
(b) |
|
Does not include WCP results of operations. |
Operating Income
Operating income increased by $9 million for the three months ended March 31, 2007, compared
to 2006. This was due to:
|
o |
|
The acquisition
of WCP on March 31, 2006, operating income during the first
quarter 2007 increased by $6 million from |
|
|
|
|
|
|
A $10 million increase
due to inclusion of WCP results that include the favorable impact
from the new tolling agreements at the Encina and El Segundo
plants. |
|
|
|
|
|
|
Offset by $4 million of
expenses related to development costs for the regions repowering
projects and G&A corporate allocations. |
|
o |
|
The sale of Red
Bluff and Chowchilla II plants on January 3,
2007 during the three months ended March 31, 2006,
these operations generated an operating loss of $2 million. |
44
Liquidity and Capital Resources
Liquidity Position
As of March 31, 2007, NRGs liquidity was approximately $2.1 billion and included
approximately $704 million of unrestricted and restricted cash. NRGs liquidity also included $822
million of borrowing capacity under the Companys revolving line of credit, and $546 million of
availability under the Companys letter of credit facility. As of December 31, 2006, NRGs
liquidity was approximately $2.2 billion and included approximately $839 million of unrestricted
and restricted cash. NRGs liquidity also included $855 million of borrowing capacity under the
Companys revolving credit facility, and $533 million of availability under the Companys letter of
credit facility.
Management believes that these amounts and cash flows from operations will be adequate to
finance 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 steady debt to equity ratio in the range of 45-60%.
Capital Allocation Program
NRG continued Phase II of the Companys Capital Allocation Program during the first quarter
2007 with the repurchase of an additional 1,500,000 shares of the Companys common stock for
approximately $103 million. NRG expects to complete Phase II of the Capital Allocation Program
during 2007 with funds generated from operations of approximately $165 million.
Second Lien Structure
NRG has granted second priority liens to certain counterparties on substantially all of the
Companys assets in the United States in order to secure obligations, which are primarily long-term
in nature under certain power sale agreements and related contracts. NRG uses the second lien
structure to reduce the amount of cash collateral and letters of credit that it may otherwise be
required to post from time to time to support its obligations under these agreements. Within the
second lien structure, the Company can hedge up to 80% of its baseload capacity and 10% of its
non-baseload assets with these counterparties. As of March 31, 2007 and April 27, 2007, the net
discounted exposure on the agreements and hedges that were subject to the second lien structure was
approximately $90 million and $193 million, respectively.
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 second lien
structure as of April 27, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales secured by Second Lien Structure(a) |
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2012 |
|
|
In MW |
|
|
3,518 |
|
|
|
3,400 |
|
|
|
3,651 |
|
|
|
2,949 |
|
|
|
3,201 |
|
|
|
575 |
|
As a percentage of total forecasted baseload capacity |
|
|
57 |
% |
|
|
57 |
% |
|
|
62 |
% |
|
|
50 |
% |
|
|
55 |
% |
|
|
12 |
% |
|
|
|
|
(a) |
|
Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region. |
|
(b) |
|
2007 MW value consists of May through December positions only. |
Capital Expenditures
Capital expenditures were $107 million and $35 million for the three months ending March 31,
2007 and 2006, respectively, due to the following:
|
o |
|
Texas capital expenditures in the Texas region was approximately $64 million due to: |
|
|
|
STP - $38 million related to nuclear fuel and capitalized plant improvements |
|
|
|
Fossil plants the remaining balance spent on low pressure turbine rotor replacement
at the W.A. Parish and Limestone facilities, combustion system replacement at T.H. Wharton
plant and repairs at the Jewett mine |
|
o |
|
Northeast capital expenditures in the Northeast region was approximately $17 million due to: |
|
|
|
Huntley and Dunkirk approximately $8 million was related to bag house emission projects at these two facilities. |
|
|
|
Other Northeast facilities General plant improvements |
45
|
o |
|
West capital expenditures in the West region was approximately $22 million due to the
Long Beach Generating station repowering project. |
The following table summarizes NRGs capital expenditure forecast, by region, for the full
year of 2007 of approximately $450 million, inclusive of the $107 million spend during the first
quarter 2007 capital spend:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
Maintenance |
|
|
Environmental |
|
|
Development |
|
|
Total |
|
|
Northeast |
|
$ |
41 |
|
|
$ |
112 |
|
|
$ |
7 |
|
|
$ |
160 |
|
Texas |
|
|
143 |
|
|
|
4 |
|
|
|
|
|
|
|
147 |
|
South Central |
|
|
28 |
|
|
|
27 |
|
|
|
|
|
|
|
55 |
|
West |
|
|
4 |
|
|
|
1 |
|
|
|
73 |
|
|
|
78 |
|
Other |
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
10 |
|
|
Total |
|
$ |
226 |
|
|
$ |
144 |
|
|
$ |
80 |
|
|
$ |
450 |
|
Capital expenditures through March 31, 2007 |
|
|
74 |
|
|
|
11 |
|
|
|
22 |
|
|
|
107 |
|
|
Remaining capital expenditures for 2007 |
|
$ |
152 |
|
|
$ |
133 |
|
|
$ |
58 |
|
|
$ |
343 |
|
|
NRG anticipates funding these capital project with funds generated from operating activities.
NOLs,
Deferred Tax Assets and Uncertain Tax Benefits
As
of March 31, 2007, the Company has U.S. domestic net operating
loss carryforwards of $70 million. In addition to this amount,
the Company has $712 million of tax effected unrecognized tax
benefits which relate primarily to net operating losses for tax
return purposes which have been classified as capital loss
carryforwards for financial statements purposes for which a full
valuation allowance has been established. As a result of our tax
position and based on current forecasts, future U.S. domestic income
tax payments will be minimal through mid year 2009 as these
unrecognized tax benefits will be utilized for tax return
purposes.
However,
as these positions remain uncertain, the Company may recognize a non current liability of up to
$712 million until resolution with the related taxing
authorities. As we move forward, the Company will continue to accrue
for such uncertain tax benefits and regular income tax payments are
contingent upon their final resolution.
Cash Flow Discussion
NRG obtains cash from operations, proceeds from the sale of certain assets and the proceeds
from the issuance of debt, preferred stock and common stock. NRG uses these funds to finance
operations, make interest payments, repurchase its common stock, service debt obligations, finance
capital expenditures, and meet other cash and liquidity needs.
The following table reflects the changes in cash flows for the comparative years; all cash
flow categories include the cash flows from both continuing operations and discontinued operations:
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
Three months ended March 31, |
|
2007 |
|
|
2006 |
|
|
Net cash provided by operating activities |
|
$ |
106 |
|
|
$ |
342 |
|
Net cash used in investing activities |
|
|
(112 |
) |
|
|
(4,202 |
) |
Net cash provided/(used) by financing activities |
|
$ |
(136 |
) |
|
$ |
4,171 |
|
|
Net Cash Provided By Operating Activities
For the three months ended March 31, 2007, net cash provided by operating activities decreased
by $236 million compared to the three months ended March 31, 2006. This was due to the following
reasons:
|
o |
|
Due to the upward shift of the forward price curves, NRGs cash collateral deposits in
support of derivative contracts increased by $120 million for the three months ended March
31, 2007, compared to a decrease of $230 million for the three months ended March 31, 2006, a
difference of $350 million. As of March 31, 2007, NRG had a net cash collateral on deposit
of $66 million; |
|
o |
|
NRGs activity for the three months ended March 31, 2007, resulted in a decrease of $114
million in working capital compared to an increase in working capital for the three months
ended March 31, 2006, of $15 million, a difference of $129 million. This was due to the
following reasons: |
|
|
|
Capacity revenues related to
PUCT mandated auctions are paid a month in advance, as a result of a
reduction in such auctions, cash receipts decreased by
$52 million during the three months ended March 31, 2007
compared to 2006. |
|
|
|
$32 million related to
payment of property taxes in Texas paid in January 2007. |
|
|
|
$16 million of payments
related to a large vesting of equity compensation compared to 2006. |
|
|
|
$31 million due to the
receipt of trade receivables related to sales prior to the
acquisition of Texas Genco LLC, were excluded from working capital as
they were an increase to the purchase price. |
46
Net Cash Provided By Investing Activities
For the three months ended March 31, 2007, net cash used in investing activities was
approximately $4.1 billion less than the three months ended March 31, 2006. NRGs decrease in use
of cash was due to:
|
o |
|
During the first quarter 2006, NRG acquired Texas Genco LLC for approximately $6.2 billion
that included the issuance of stock of $1.7 billion and a net cash payment of approximately
$4.3 billion (net of cash on hand of $238 million); |
|
o |
|
NRGs capital expenditures increased by $72 million during the three months ended March 31,
2007, as compared to 2006, with the increase due to $38 million
spent on nuclear fuel and capitalized improvements at the
STP plant and $22 million for RepoweringNRG at the Companys Long Beach facility. |
Net Cash Provided/(Used) in Financing Activities
For the three months ended March 31, 2007, net cash from financing activities decreased by
approximately $4.3 billion, as compared to 2006. The decrease
was primarily due to the financing activities
related to the purchase of Texas Genco LLC during 2006:
|
o |
|
During the first quarter 2006, NRG acquired Texas Genco LLC. As part of the acquisition,
NRG refinanced the Companys outstanding debt as well as Texas Genco LLCs outstanding debt,
and also issued new debt, preferred stock and common stock to fund the acquisition: |
|
|
|
Total debt repayments were $4.6 billion $1.9 billion from NRG debt and $2.7 billion
of Texas Genco LLC debt; |
|
|
|
Total proceeds from debt issued was $7.2 billion $3.6 billion of unsecured notes and
$3.6 billion for a senior secured facility, including a $1.0 billion Revolving Credit
Facility, and a $1.0 billion synthetic Letter of Credit Facility; |
|
|
|
Total proceeds from stock issued of approximately $1.5 billion net proceeds of $986
million from issuing approximately 21 million shares of common stock and net proceeds of
$486 million from issuing 2 million shares of the Companys 5.75% Preferred Stock. |
|
o |
|
In 2006, NRG initiated a Capital Allocation Program executed in two phases. As part of
Phase II, NRG repurchased an additional 1,500,000 shares of the Companys common stock for
approximately $103 million during the first quarter 2007. |
47
New and On-going Company Initiatives
Comprehensive Capital Allocation Plan
The Companys capital allocation strategy includes (i) the repayment of debt, (ii) the return
of capital to shareholders, and (iii) the investment of capital into the business. With the
establishment of the Companys longer-dated hedge profile, the variability of gross margins has
been substantially reduced. Accordingly, for each of the planned debt repayment and return of
capital to shareholders, the Company is migrating towards a structure that provides for both a
fixed and a variable component. In November 2006, the Company modified its Senior Credit Facility
to include, among other things, an annual mandatory prepayment based on the current years excess
cash flow the fixed component while retaining the right to voluntarily prepay all or a portion
of the Companys outstanding Term B loan at no penalty the variable component. The Company also
has announced plans for a Comprehensive Capital Allocation Plan that will support a similar fixed
and variable structure for the return of capital to shareholders. If implemented, this plan will
provide the Company with the ability (i) to initiate an annual cash dividend the fixed
component and (ii) to continue the Companys historical program of common share repurchases the
variable component. The Companys total annual targeted return of capital to shareholders is
expected to be approximately 3% of NRGs current market capitalization. Once completed, the
Company expects to commence payment of quarterly cash dividends in
the first quarter 2008, subject
to approval by the Companys Board of Directors and other conditions including availability of cash
resources. In addition, the Company plans to complete Phase II of its Capital Allocation Program
announced in November 2006 with the repurchase of approximately $165 million of common stock
during 2007.
During May 2007, the Company plans to seek several amendments to its Senior Credit Facility.
The amendments include:
|
|
|
Lower pricing for NRGs Term B loan and synthetic Letter of Credit facility; |
|
|
|
|
A provision that enables up to $150 million annually for the payment of a recurring cash
dividend on the Companys common stock; |
|
|
|
|
Reduction in the synthetic Letter of Credit facility from $1.5 billion to $1.3 billion; |
|
|
|
|
Ability to utilize a first lien position to support commercial hedges; |
|
|
|
|
Additional flexibility for RepoweringNRG projects; and |
|
|
|
|
A commitment from lenders that effectively converts one-third of existing Term B debt (approximately $1 billion in the
aggregate) to
a holding company level planned for later this year. |
To improve the efficiency of its capital allocation, the Company is planning to implement a
holding company structure in the second half of 2007. Under the planned structure:
|
|
|
NRG will become a wholly-owned operating subsidiary, or Opco, of a newly created holding
company, or Holdco, and the shareholders of the Company will become
shareholders of Holdco; |
|
|
|
|
Holdco will borrow up to $1 billion in new Term B loan financing from its existing bank
group; and |
|
|
|
|
Holdco will use the net proceeds to make a capital contribution to Opco, which Opco in
turn will use for the prepayment of its Term B debt under the existing Senior Credit Facility. |
Upon completion of the above, the Companys restricted payments capacity under its unsecured
indenture will increase by an amount equal to the capital
contribution from Holdco to Opco, thereby
allowing a more efficient allocation of capital within the Company. On May 1, 2007, the Company
entered into a commitment with certain financial institutions to backstop the $1 billion financing
planned for the Holdco level. Implementation of
the Holdco structure described above is contingent upon a number of conditions being satisfied,
including receiving certain regulatory approvals. While there can be no assurance that all of
these conditions will be satisfied, the Company believes that the Holdco structure will be
implemented by the end of 2007. The Company expects that the consummation of Holdco structure and
amendments to the Senior Credit Facility will result in a non-cash charge to earnings due to the
write-off of unamortized deferred finance costs at NRG, and estimates that this non-cash charge
could range from $15 million to $80 million.
48
RepoweringNRG
Plants under Development
Most of the originally planned RepoweringNRG projects continue in the development phase.
During the first quarter 2007, many RepoweringNRG projects made progress in permitting, site
planning and other critical development activities. Other RepoweringNRG projects, including
projects in Connecticut and in Delaware are less likely to move forward as they have not been
successful to date in winning off-take mandates offered as part of requests for proposals sponsored
by these states.
Plants under Construction
260 MW of repowered gas-fueled capacity at NRGs Long Beach Generating Station remains on
schedule to be online by August 1, 2007 to support the anticipated summer peak on the Southern
California Edison and California Independent System Operator systems. Total capital
expenditures for the project are expected to be approximately $73 million, with $22 million
incurred during the first quarter 2007. In addition to the Long Beach project, the Company is
proceeding with the repowering project at the Cos Cob site in Connecticut. This project will add
40 MW of peaking capacity at a cost of $18 million.
Development Costs
During the first quarter 2007, NRG incurred approximately $23 million in costs associated with
development efforts across all segments of the Company, but predominately in Texas to support the
planned expansion of the STP nuclear generating station as the Company prepares for the submission
of a combined operating license application.
Stock Dividend
On April 25, 2007, NRGs Board of Directors approved a two-for-one stock split of the
Companys outstanding shares of common stock to be effected in the form of a stock dividend. The
stock split will entitle each stockholder of record at the close of business on May 22, 2007 to
receive one additional share for every outstanding share of common stock held. The additional
shares resulting from the stock split are expected to be distributed by the Companys transfer
agent on or about May 31, 2007. Upon the completion of the stock split, NRG will have
approximately 242 million shares of common stock outstanding.
49
Off-Balance Sheet Arrangements
Obligations Under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of
business to facilitate commercial transactions with third parties. These arrangements include
financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications.
Retained or Contingent Interests
NRG does not have any material retained or contingent interests in assets transferred to an
unconsolidated entity.
Derivative Instrument obligations
On August 11, 2005, NRG issued 3.625% Preferred Stock that included a conversion feature which
is considered a derivative per FAS 133, as amended. Although it is considered a derivative, it is
exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of
FAS 133. As of March 31, 2007, based on the Companys stock price, the value of the payment for
this embedded derivative would have been approximately $49 million.
On October 13, 2006, NRG through its unrestricted wholly-owned subsidiaries NRG Common Stock
Fund I, or CSF I, issued notes and preferred interests to a unit of Credit Suisse for the
repurchase of NRGs common stock. Included in the contract was a conversion feature which is
considered a derivative per FAS 133, as amended. Although it is considered a derivative, it is
exempt from derivative accounting as it is excluded from the scope pursuant to paragraph 11(a) of
FAS 133. As of March 31, 2007, based on the Companys stock price, the value of the payment for
this embedded derivative would have been approximately $24 million.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments As of March 31, 2007, NRG had not entered into any
financing structure that was designed to be off-balance sheet that would create liquidity,
financing or incremental market risk or credit risk to the Company. However, NRG has several
investments with an ownership interest percentage of 50% or less in energy and energy related
entities that are accounted for under the equity method of accounting. NRGs pro-rata share of
non-recourse debt held by unconsolidated affiliates was approximately $146 million as of March 31,
2007. This indebtedness may restrict the ability of these subsidiaries to issue dividends or
distributions to NRG.
Synthetic Letter of Credit Facility and Revolver Facility Under NRGs Amended Senior Credit
Facility NRG entered into on November 21, 2006, the Company has a $1.5 billion synthetic Letter of
Credit Facility that is unfunded by NRG, and a $1 billion senior Revolving Credit Facility. The
synthetic Letter of Credit Facility is secured by a $1.5 billion cash collateral deposit, held by
Deutsche Bank AG, New York Branch, as the Issuing Bank. Under the synthetic Letter of Credit
Facility, NRG is allowed to issue letters of credit to support the Companys obligations under
commodity hedging or power purchase arrangements. In addition, NRG can issue up to $300 million in
unfunded letters of credit under the Companys Revolving Credit Facility for ongoing working
capital requirements and for general corporate purposes, including acquisitions that are permitted
under the Senior Credit Facility. In addition, NRG is permitted to issue additional letters of
credit up to $700 million under the Senior Credit Facility through another financial institution.
As of March 31, 2007, the Company had issued $954 million in letters of credit under the
Letter of Credit Facility. In addition, as of March 31, 2007, the Company had issued $178 million
in revolver letters of credit, a portion of which supports non-commercial letter of credit
obligations.
Contractual Obligations and Commercial Commitments
NRG has a variety of contractual obligations and other commercial commitments that represent
prospective cash requirements in addition to the Companys capital expenditure programs, as
disclosed in the Companys Annual Report on Form 10-K for the year ended December 31, 2006. Also
see Note 12 to the condensed consolidated financial statements of this Form 10-Q for a discussion
of new commitments and contingencies that also include contractual obligations and commercial
commitments that occurred during the first quarter 2007.
50
Critical Accounting Policies and Estimates and Changes in Accounting Standards
NRGs discussion and analysis of the financial condition and results of operations are based
upon the consolidated financial statements, which have been prepared in accordance with accounting
principles generally accepted in the United States of America. The preparation of these financial
statements and related disclosures in compliance with generally accepted accounting principles, or
GAAP, requires the application of appropriate technical accounting rules and guidance as well as
the use of estimates and judgments that affect the reported amounts of assets, liabilities,
revenues and expenses, and related disclosures of contingent assets and liabilities. The
application of these policies necessarily involves judgments regarding future events, including the
likelihood of success of particular projects, legal and regulatory challenges. These judgments, in
and of themselves, could materially affect the financial statements and disclosures based on
varying assumptions, which may be appropriate to use. In addition, the financial and operating
environment also may have a significant effect, not only on the operation of the business, but on
the results reported through the application of accounting measures used in preparing the financial
statements and related disclosures, even if the nature of the accounting policies have not changed.
On an ongoing basis, NRG evaluates these estimates, utilizing historic experience,
consultation with experts and other methods the Company considers reasonable. In any event, actual
results may differ substantially from the Companys estimates. Any effects on the Companys
business, financial position or results of operations resulting from revisions to these estimates
are recorded in the period in which the facts that give rise to the revision become known.
51
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NRG is exposed to several market risks in the Companys normal business activities.
Market risk is the potential loss that may result from market changes associated with the Companys
merchant power generation or with an existing or forecasted financial or commodity transaction. The
types of market risks the Company is exposed to are commodity price risk, interest rate risk and
currency exchange risk. In order to manage these risks the Company uses various fixed-price forward
purchase and sales contracts, futures and option contracts traded on the New York Mercantile
Exchange, and swaps and options traded in the over-the-counter financial markets to:
|
|
|
Manage and hedge fixed-price purchase and sales commitments; |
|
|
|
Manage and hedge exposure to variable rate debt obligations; |
|
|
|
Reduce exposure to the volatility of cash market prices; and |
|
|
|
Hedge fuel requirements for the Companys generating facilities. |
Commodity Price Risk
Commodity price risks result from exposures to changes in spot prices, forward prices,
volatility in commodities, and correlations between various commodities, such as natural gas,
electricity, coal and oil. A number of factors influence the level and volatility of prices for
energy commodities and related derivative products. These factors include:
|
|
|
Seasonal, daily and hourly changes in demand; |
|
|
|
Extreme peak demands due to weather conditions; |
|
|
|
Available supply resources; |
|
|
|
Transportation availability and reliability within and between regions; and |
|
|
|
Changes in the nature and extent of federal and state regulations. |
As part of NRGs overall portfolio, NRG manages the commodity price risk of the Companys
merchant generation operations by entering into various derivative or non-derivative instruments to
hedge the variability in future cash flows from forecasted sales of electricity and purchases of
fuel. These instruments include forward purchase and sale contracts, futures and option contracts
traded on the New York Mercantile Exchange, and swaps and options traded in the over-the-counter
financial markets. The portion of forecasted transactions hedged may vary based upon managements
assessment of market, weather, operation and other factors.
While some of the contracts the Company uses to manage risk represent commodities or
instruments for which prices are available from external sources, other commodities and certain
contracts are not actively traded and are valued using other pricing sources and modeling
techniques to determine expected future market prices, contract quantities, or both. NRG uses the
Companys best estimates to determine the fair value of commodity and derivative contracts held and
sold. These estimates consider various factors, including closing exchange and over-the-counter
price quotations, time value, volatility factors and credit exposure. However, it is likely that
future market prices could vary from those used in recording mark-to-market derivative instrument
valuation, and such variations could be material.
NRG measures the sensitivity of the Companys portfolio to potential changes in market prices
using Value at Risk, or VAR. VAR is a statistical model that attempts to predict risk of loss based
on market price volatility. Currently, the company estimates VAR using a Monte Carlo simulation
based methodology. NRGs total portfolio includes mark-to-market and non mark-to-market energy
assets and liabilities.
NRG uses a diversified VAR model to calculate an estimate of the potential loss in the fair
value of the Companys energy assets and liabilities, which includes generation assets, load
obligations, and bilateral physical and financial transactions. The key assumptions for the
Companys diversified model include: (1) a lognormal distribution of price returns, (2) one-day
holding period, (3) a 95% confidence interval, (4) a rolling 24-month forward looking period, and
(5) market implied price volatilities and historical price correlations.
As of March 31, 2007, the VAR for NRGs commodity portfolio, including generation assets, load
obligations and bilateral physical and financial transactions calculated using the diversified VAR
model was $22 million.
52
The following table summarizes average, maximum and minimum VAR for NRG for the three months
ended March 31, 2007 and 2006. VAR for the three months ended March 31, 2006 does not include Texas
since it was not integrated with the consolidated NRG portfolio.
|
|
|
|
|
|
|
|
|
VAR |
|
2007 |
|
|
2006 |
|
|
As of March 31, |
|
$ |
22 |
|
|
$ |
30 |
|
Average |
|
|
26 |
|
|
|
33 |
|
Maximum |
|
|
34 |
|
|
|
38 |
|
Minimum |
|
|
22 |
|
|
|
27 |
|
|
Due to the inherent limitations of statistical measures such as VAR, the relative immaturity
of the competitive markets for electricity and related derivatives, and the seasonality of changes
in market prices, the VAR calculation may not capture the full extent of commodity price exposure.
As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could
differ from the calculated VAR, and such changes could have a material impact on the Companys
financial results.
In order to provide additional information for comparative purposes to NRGs peers, the
Company also uses VAR to estimate of the potential loss of financial derivative 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 financial
derivative instruments calculated using the diversified VAR model as of March 31, 2007 for the
entire term of these instruments entered into for both asset management and trading was
approximately $27 million.
Interest Rate Risk
NRG is exposed to fluctuations in interest rates through the Companys issuance of fixed rate
and variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into
derivative instruments known as interest rate swaps, caps, collars and put or call options. These
contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt
obligations when taking into account the combination of the variable rate debt and the interest
rate derivative instrument. NRGs risk management policies allow the Company to reduce interest
rate exposure from variable rate debt obligations.
In January 2006, the Company entered into a series of new interest rate swaps. These interest
rate swaps became effective on February 15, 2006 and are intended to hedge the risk associated with
floating interest rates. For each of the interest rate swaps, NRG pays its counterparty the
equivalent of a fixed interest payment on a predetermined notional value, and NRG receives the
equivalent of a floating interest payment based on 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 April 27, 2007 was $2.0 billion.
As of March 31, 2007, the Company had various interest rate swap agreements with notional
amounts totaling approximately $2.7 billion. If the swaps had been discontinued on March 31, 2007,
the Company would have owed the counter-parties approximately $18 million. Based on the investment
grade rating of the counter-parties, NRG believes that the Companys exposure to credit risk due to
nonperformance by the counter-parties to the hedging contracts is 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 March 31, 2007, a 100 basis point change
in interest rates would result in a $15 million change in interest expense on a rolling twelve
month basis.
As of March 31, 2007, the fair value and the carrying amount of the Companys long-term debt
was $8.9 billion and $8.8 billion, respectively. NRG estimates that a 1% decrease in market
interest rates would have increased the fair value of the Companys long-term debt by $530 million.
Currency Exchange Risk
NRG expects to continue to be subject to currency risks associated with foreign denominated
distributions from the Companys international investments. In the normal course of business, NRG
may receive distributions denominated in the Euro, Australian Dollar and the Brazilian Real. NRG
has historically engaged in a strategy of hedging foreign denominated cash flows through a program
of matching currency inflows and outflows, and to the extent required, fixing the U.S. Dollar
equivalent of net foreign
53
denominated distributions with currency forward and swap agreements with
highly credit worthy financial institutions. The Company would expect to enter into similar
transactions in the future if management deems it to be appropriate.
Liquidity Risk
Liquidity risk arises from the general funding needs of NRGs activities and in the management
of the Companys assets and liabilities. NRGs liquidity management framework is intended to
maximize liquidity access and minimize funding costs. Through active liquidity management, the
Company seeks to preserve stable, reliable and cost-effective sources of funding. This enables the
Company to replace maturing obligations when due and fund assets at appropriate maturities and
rates. To accomplish this task, management uses a variety of liquidity risk measures that take
into consideration market conditions, prevailing interest rates, liquidity needs, and the desired
maturity profile of liabilities.
Based on a sensitivity analysis, a $1 per MWh increase or increase in electricity prices
across the term of the marginable contracts would cause a change in margin collateral outstanding
of approximately $55 million as of March 31, 2007. This analysis uses simplified assumptions and
is calculated based on portfolio composition and margin-related contract provisions as of March 31,
2007.
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 the credit risk of NRG and its subsidiaries through credit policies which include (i) an
established credit approval process, (ii) a daily monitoring of counter-party credit limits, (iii)
the use of credit mitigation measures such as margin, collateral, credit derivatives or prepayment
arrangements, (iv) the use of payment netting agreements, and (v) the use of master netting
agreements that allow for the netting of positive and negative exposures of various contracts
associated with a single counterparty. Risks surrounding counterparty performance and credit could
ultimately impact the amount and timing of expected cash flows. The Company has credit protection
within various agreements to call on additional collateral support if and when necessary. As of
March 31, 2007, NRG held collateral support of approximately $292 million from counterparties.
A portion of NRGs credit risk is related to transactions that are recorded in the Companys
consolidated Balance Sheet. These transactions primarily consist of open positions from the
Companys marketing and risk management operation that are accounted for using mark-to-market
accounting, as well as amounts owed by counterparties for transactions that settled but have not
yet been paid.
The following table highlights the credit quality and exposures related to these activities as
of March 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure |
|
|
|
|
|
|
|
|
(In millions, except ratios) |
|
Before |
|
|
|
|
|
|
Net |
|
Credit Exposure |
|
Collateral |
|
|
Collateral |
|
|
Exposure |
|
|
Investment grade |
|
$ |
1,200 |
|
|
$ |
347 |
|
|
$ |
853 |
|
Non-investment grade |
|
|
73 |
|
|
|
51 |
|
|
|
22 |
|
Not rated |
|
|
172 |
|
|
|
20 |
|
|
|
152 |
|
|
Total |
|
$ |
1,445 |
|
|
$ |
418 |
|
|
$ |
1,027 |
|
|
Investment grade |
|
|
83 |
% |
|
|
83 |
% |
|
|
83 |
% |
Non-investment grade |
|
|
5 |
|
|
|
12 |
|
|
|
2 |
|
Not rated |
|
|
12 |
% |
|
|
5 |
% |
|
|
15 |
% |
|
Additionally, the Company has concentrations of suppliers and customers among coal suppliers,
electric utilities, energy marketing and trading companies and regional transmission operators.
These concentrations of counterparties may impact NRGs overall exposure to credit risk, either
positively or negatively, in that counterparties may be similarly affected by changes in economic,
regulatory and other conditions.
NRGs exposure to significant counterparties greater than 10% of the net exposure of
approximately $1 billion was approximately $622 million as of March 31, 2007. NRG does not
anticipate any material adverse effect on the Companys financial position or results of operations
as a result of nonperformance by any of NRGs counterparties.
Fair Value of Derivative Instruments
NRG may enter into long-term power sales contracts, fuel purchase contracts and other
energy-related financial instruments to
54
mitigate variability in earnings due to fluctuations in
spot market prices, to hedge fuel requirements at generation facilities and protect fuel
inventories. In addition, in order to mitigate interest rate risk associated with the issuance of
the Companys variable rate and fixed rate debt, NRG enters into interest rate swap agreements.
NRGs trading activities include contracts entered into to profit from market price changes as
opposed to hedging an exposure, and are subject to limits in accordance with the Companys risk
management policy. These contracts are recognized on the balance sheet at fair value and changes
in the fair value of these derivative financial instruments are recognized in earnings. These
trading activities are a complement to NRGs energy marketing portfolio.
The tables below disclose the activities that include non-exchange traded contracts accounted
for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair
value; identify changes in fair value attributable to changes in valuation techniques; disaggregate
estimated fair values at March 31, 2007, based on whether fair values are determined by quoted
market prices or more subjective means; and indicate the maturities of contracts at March 31, 2007:
|
|
|
|
|
Derivative Activity Gains/(Losses) |
|
(In millions) |
|
|
Fair value of contracts at December 31, 2006 |
|
$ |
354 |
|
Contracts realized or otherwise settled during the period |
|
|
(28 |
) |
Changes in fair value |
|
|
(527 |
) |
|
Fair value of contracts at March 31, 2007 |
|
$ |
(201 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of March 31, 2007 |
|
|
|
Maturity |
|
|
|
|
|
|
|
|
|
|
Maturity |
|
|
|
|
|
|
Less than |
|
|
Maturity |
|
|
Maturity |
|
|
in excess |
|
|
Total Fair |
|
Sources of Fair Value Gains/(Losses) (In millions) |
|
1 Year |
|
|
1-3 Years |
|
|
4-5 Years |
|
|
of 5 Years |
|
|
Value |
|
|
Prices actively quoted |
|
$ |
(45 |
) |
|
$ |
2 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
(43 |
) |
Prices provided by other external sources |
|
|
74 |
|
|
|
(51 |
) |
|
|
(144 |
) |
|
|
(37 |
) |
|
|
(158 |
) |
Prices provided by models and other valuation methods |
|
|
1 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
30 |
|
|
$ |
(50 |
) |
|
$ |
(144 |
) |
|
$ |
(37 |
) |
|
$ |
(201 |
) |
|
ITEM 4 CONTROLS AND PROCEDURES
Under the supervision and with the participation of Companys management, including the
principal executive officer, principal financial officer and principal accounting officer, NRG
conducted an evaluation of the Companys disclosure controls and procedures, as such term is
defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended. Based on this evaluation, NRGs principal executive officer, principal financial
officer and principal accounting officer concluded that the Companys disclosure controls and
procedures were effective as of the end of the period covered by this Quarterly Report. There have
been no changes in the Companys internal control over financial reporting during the quarter ended
March 31, 2007 that have materially affected, or are reasonably likely to materially affect, the
Companys internal control over financial reporting.
55
PART II OTHER INFORMATION
ITEM 1 LEGAL PROCEEDINGS
For a discussion of material legal proceedings in which NRG was involved through March 31,
2007, see Note 12 to the condensed consolidated financial statements of this Form 10-Q.
ITEM 1A RISK FACTORS
Information regarding risk factors appears in Part II, Item 1A, Risk Factors in NRG Energy,
Inc.s 2006 Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Due to recent
significant events at NRG, the following risk factor has been identified:
The Company may not have sufficient available cash to pay cash dividends each quarter.
NRG has never paid a cash dividend and has not had a policy with regard to the payment of cash
dividends with respect to its common stock. In April 2007, the Companys Board of Directors
declared its intention to begin paying quarterly cash dividends to holders of NRG common stock,
beginning in the first quarter 2008. The payment of cash dividends in the future will depend on a
number of factors, including, NRGs future financial performance, the Companys available cash
resources and the cash requirements of its business, state corporate law restrictions and, possibly
the consents of third parties, such as the lenders under the Companys Senior Credit
Facility. In addition, the payment of each cash dividend and the amount of such dividends are
subject to approval by the Companys Board of Directors. As a result, there can be no assurance
that NRG will implement its plans with regards to the payment of quarterly cash dividends.
ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Item 2(c) Purchase of Equity securities by NRG
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number of shares |
|
|
Dollar value of |
|
|
|
|
|
|
|
|
|
|
|
purchased as part of |
|
|
shares that may be |
|
|
|
Total number of |
|
|
Average price |
|
|
publicly announced |
|
|
purchased under the |
|
For the period ended April 27, 2007 |
|
shares purchased |
|
|
paid per share |
|
|
plans or programs |
|
|
plans or programs |
|
|
January 1 January 31 |
|
|
|
|
|
$ |
|
|
|
|
|
|
|
$ |
|
|
February 1 February 28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 1 March 31 |
|
|
1,500,000 |
|
|
|
68.74 |
|
|
|
1,500,000 |
|
|
|
165,160,714 |
|
|
First Quarter Total |
|
|
1,500,000 |
|
|
|
68.74 |
|
|
|
1,500,000 |
|
|
|
|
|
|
April 1 April 27, 2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-to-date |
|
|
1,500,000 |
|
|
$ |
68.74 |
|
|
|
1,500,000 |
|
|
$ |
165,160,714 |
|
|
ITEM 3 DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5 OTHER INFORMATION
None.
56
ITEM 6 EXHIBITS
Exhibits
|
|
|
|
|
|
10.1*
|
|
Amended and Restated NRG Energy, Inc. Long-Term Incentive Plan, dated April 25, 2007, filed
herewith. |
|
|
|
10.2*
|
|
NRG Energy, Inc. Executive and Key Management Change-in-Control and General Severance
Agreement, dated April 25, 2007, filed herewith. |
|
|
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
31.3
|
|
Certification of Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
32
|
|
Certification of Chief Executive Officer, Chief Financial Officer and Controller pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith. |
|
|
|
* |
|
Exhibit relates to compensation arrangements. |
57
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
|
|
|
NRG ENERGY, INC.
(Registrant) |
|
|
|
|
|
/s/ DAVID W. CRANE |
|
|
|
|
|
David W. Crane, |
|
|
Chief Executive Officer |
|
|
|
|
|
/s/ ROBERT C. FLEXON |
|
|
|
|
|
Robert C. Flexon, |
|
|
Chief Financial Officer |
|
|
(Principal Financial Officer) |
|
|
|
|
|
/s/ CAROLYN J. BURKE |
|
|
|
|
|
Carolyn J. Burke, |
|
|
Controller |
Date: May 2, 2007
|
|
(Principal Accounting Officer) |
58
EXHIBIT INDEX
Exhibits
|
|
|
|
|
|
10.1*
|
|
Amended and Restated NRG Energy, Inc. Long-Term Incentive Plan, dated April 25, 2007, filed
herewith. |
|
|
|
10.2*
|
|
NRG Energy, Inc. Executive and Key Management Change-in-Control and General Severance
Agreement, dated April 25, 2007, filed herewith. |
|
|
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
31.3
|
|
Certification of Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith. |
|
|
|
32
|
|
Certification of Chief Executive Officer, Chief Financial Officer and Controller pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, filed herewith. |
|
|
|
* |
|
Exhibit relates to compensation arrangements. |
59