FORM 10-Q
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
|
|
|
þ |
|
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
|
|
|
o |
|
Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the quarterly period ended: September 30, 2006
Commission File Number: 001-15891
NRG Energy, Inc.
(Exact name of Registrant as specified in its charter)
|
|
|
Delaware
|
|
41-1724239 |
(State or other jurisdiction
|
|
(I.R.S. Employer |
of incorporation or organization)
|
|
Identification No.) |
|
|
|
211 Carnegie Center |
|
|
Princeton, New Jersey
|
|
08540 |
(Address of principal executive offices)
|
|
(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 November 2, 2006, there were 126,442,942 shares of common stock outstanding, par value
$0.01 per share.
TABLE OF CONTENTS
Index
|
|
|
|
|
|
|
Page No. |
|
|
|
3 |
|
|
|
|
4 |
|
|
|
|
6 |
|
|
|
|
6 |
|
|
|
|
50 |
|
|
|
|
78 |
|
|
|
|
81 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
82 |
|
|
|
|
84 |
|
|
|
|
85 |
|
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 NRG Energy, Inc.s actual results,
performance and achievements, or industry results, to be materially different from any future
results, performance or achievements expressed or implied by such forward-looking statements. These
factors, risks and uncertainties include the factors described under Risks Related to NRG Energy,
Inc. in Item 1A of NRG Energy, Inc.s 2005 Annual Report on Form 10-K and the following:
|
|
|
General economic conditions, changes in the wholesale power markets and fluctuations in
the cost of fuel; |
|
|
|
|
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
Energy, Inc. may not have adequate insurance to cover losses as a result of such hazards; |
|
|
|
|
The effectiveness of NRG Energy, Inc.s risk management policies and procedures, and the
ability of NRG Energy, Inc.s counterparties to satisfy their financial commitments; |
|
|
|
|
Counterparties collateral demands and other factors affecting NRG Energy, Inc.s
liquidity position and financial condition; |
|
|
|
|
NRG Energy, Inc.s 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; |
|
|
|
|
NRG Energy, Inc.s potential inability to enter into contracts to sell power and procure fuel on acceptable terms and prices; |
|
|
|
|
The liquidity and competitiveness of wholesale markets for energy commodities; |
|
|
|
|
Government regulation, including compliance with regulatory requirements and changes in
market rules, rates, tariffs and environmental laws; |
|
|
|
|
Price mitigation strategies and other market structures employed by independent system
operators, or ISO, or regional transmission organizations, or RTOs, that result in a failure
to adequately compensate NRG Energy, Incs generation units for all of its costs; |
|
|
|
|
NRG Energy, Inc.s ability to borrow additional funds and access capital markets, as well
as NRG Energy, Incs substantial indebtedness and the possibility that NRG Energy, Inc. may
incur additional indebtedness going forward; |
|
|
|
|
Operating and financial restrictions placed on NRG Energy, Inc. contained in the
indentures governing NRG Energy, Inc.s 7.25% and 7.375% unsecured senior notes due 2014 and
2016, respectively, in NRG Energy, Inc.s senior secured credit facility and in debt and
other agreements of certain of NRG Energy, Inc. subsidiaries and project affiliates
generally; |
|
|
|
|
Significant operating and financial restrictions which may be placed on NRG Energy, Inc.
as a result of the new financing transaction described in this Form 10-Q and instruments
governing its existing indebtedness; and |
|
|
|
|
NRG Energy, Incs ability to implement its recently-announced strategy of developing and
building new power generation facilities, including new nuclear units and integrated
gasification combined cycle, or IGCC, units. |
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 NRG Energy, Inc.s 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:
|
|
|
Acquisition
|
|
February 2, 2006 acquisition of Texas Genco LLC |
|
|
|
Acquisition Agreement
|
|
Acquisition Agreement dated September 30, 2005 underlying the February 2, 2006 acquisition
of Texas Genco LLC, now referred to as NRG Texas |
|
|
|
APB 18
|
|
Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments
in Common Stock |
|
|
|
BTA
|
|
Best Technology Available |
|
|
|
BTU
|
|
British Thermal Unit |
|
|
|
CAA
|
|
Clean Air Act |
|
|
|
CAIR
|
|
Clean Air Interstate Rule |
|
|
|
CAISO
|
|
California Independent System Operator |
|
|
|
Capital Allocation Program
|
|
Share repurchase program as described in Note 8 to the Condensed Consolidated Financial
Statements |
|
|
|
CDWR
|
|
California Department of Water Resources |
|
|
|
CL&P
|
|
Connecticut Light & Power |
|
|
|
DNREC
|
|
Delaware Department of Natural Resources and Environmental Control |
|
|
|
EFOR
|
|
Equivalent Forced Outage Rates considers the equivalent impact that forced de-ratings
have in addition to full forced outages |
|
|
|
EITF 02-3
|
|
Emerging Issues Task Force 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 |
|
|
|
EPA
|
|
Environmental Protection Agency |
|
|
|
EPC
|
|
Engineering, Procurement and Construction |
|
|
|
ERCOT
|
|
Electric Reliability Council of Texas, the Independent System Operator and the regional
reliability coordinator of the various electricity systems within Texas |
|
|
|
FASB
|
|
Financial Accountings Standards Board |
|
|
|
FERC
|
|
Federal Energy Regulatory Commission |
|
|
|
Fresh Start
|
|
Reporting requirements as defined by SOP 90-7 |
|
|
|
Hedge Reset
|
|
Net settlement of existing hedges and reestablishment of new hedge positions |
|
|
|
IGCC
|
|
Integrated Gasification Combined Cycle |
|
|
|
ISO
|
|
Independent System Operator, also referred to as regional transmission organizations, or RTO |
|
|
|
ISO-NE
|
|
ISO New England, Inc. |
|
|
|
LIBOR
|
|
London Inter-Bank Offered Rate |
|
|
|
MDE
|
|
Maryland Department of the Environment |
|
|
|
MW
|
|
Megawatts |
|
|
|
MWh
|
|
Saleable megawatt hours net of internal/parasitic load megawatt-hours |
|
|
|
NiMo
|
|
Niagara Mohawk Power Corporation |
|
|
|
NOx
|
|
Nitrogen oxides |
|
|
|
NOL
|
|
Net operating loss |
|
|
|
NOV
|
|
Notice of Violation |
|
|
|
NQSO
|
|
Non-qualified stock option |
|
|
|
NYISO
|
|
New York Independent System Operator |
|
|
|
NYSDEC
|
|
New York Department of Environmental Conservation |
|
|
|
OCI
|
|
Other Comprehensive Income |
|
|
|
Phase II 316(b) Rule
|
|
A section of the Clean Water Act regulating cooling water intake structures |
|
|
|
PJM
|
|
PJM Interconnection, LLC |
|
|
|
PJM Market
|
|
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
|
|
Power Marketing Inc. |
|
|
|
PPA
|
|
Power Purchase Agreement |
|
|
|
PRB Coal
|
|
Coal produced in the northeastern Wyoming and southeastern Montana, which has low sulfur
content |
|
|
|
PUCT
|
|
Public Utility Commission of Texas |
|
|
|
RMR
|
|
Reliability must-run |
|
|
|
SEC
|
|
Securities and Exchange Commission |
|
|
|
Sellers
|
|
Former holders of Texas Genco LLC shares |
|
|
|
SERC
|
|
South East Electric Reliability
Commission |
|
|
|
SFAS
|
|
Statement of Financial Accounting Standards issued by the FASB |
|
|
|
SFAS 71
|
|
SFAS No. 71, Accounting for the Effects of Certain Types of Regulation |
|
|
|
SFAS 109
|
|
SFAS No. 109, Accounting for Income Taxes |
|
|
|
SFAS 123 (R)
|
|
SFAS No. 123 (revised 2004), Share-Based Payment |
|
|
|
SFAS 133
|
|
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended |
|
|
|
SFAS 141
|
|
SFAS No. 141, Business Combinations |
|
|
|
SFAS 142
|
|
SFAS No. 142, Goodwill and Other Intangible Assets |
|
|
|
SFAS
143
|
|
SFAS No. 143, Accounting
for Asset Retirement Obligations |
4
|
|
|
GLOSSARY OF TERMS CONTINUED
|
|
|
|
SFAS 143
|
|
SFAS No. 143, Accounting for Asset Retirement Obligations |
|
|
|
SFAS 144
|
|
SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets |
|
|
|
SFAS 150
|
|
SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity |
|
|
|
SO2
|
|
Sulfur dioxide |
|
|
|
SOP 90-7
|
|
Statement of Position 90-7, Financial Reporting by Entities in Reorganization Under the
Bankruptcy Code |
|
|
|
STP
|
|
South Texas Project A nuclear generating facility located in Bay City, Texas in which NRG
has a 44% ownership interest |
|
|
|
NRG Texas
|
|
Formerly Texas Genco LLC, now a subsidiary of NRG Energy, Inc. following the Acquisition |
|
|
|
US
|
|
United States of America |
|
|
|
USEPA
|
|
United States Environmental Protection Agency |
|
|
|
US GAAP
|
|
Generally Accepted Accounting Principles in the U.S. |
|
|
|
WCP
|
|
West Coast Power (Generation) Holdings, Inc. |
5
PART I FINANCIAL INFORMATION
Item 1 Condensed Consolidated Financial Statements and Notes
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions, except for per share amounts) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from majority-owned operations |
|
$ |
2,000 |
|
|
$ |
687 |
|
|
$ |
4,479 |
|
|
$ |
1,723 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
1,055 |
|
|
|
604 |
|
|
|
2,478 |
|
|
|
1,378 |
|
Depreciation and amortization |
|
|
148 |
|
|
|
41 |
|
|
|
443 |
|
|
|
121 |
|
General, administrative and development |
|
|
79 |
|
|
|
42 |
|
|
|
220 |
|
|
|
136 |
|
Impairment charges |
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Corporate relocation charges |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
6 |
|
|
Total operating costs and expenses |
|
|
1,282 |
|
|
|
695 |
|
|
|
3,141 |
|
|
|
1,647 |
|
|
Operating Income/(Loss) |
|
|
718 |
|
|
|
(8 |
) |
|
|
1,338 |
|
|
|
76 |
|
|
Other Income (Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
17 |
|
|
|
29 |
|
|
|
46 |
|
|
|
82 |
|
Write downs and gains/(losses) on sales of equity method
investments |
|
|
(3 |
) |
|
|
4 |
|
|
|
8 |
|
|
|
16 |
|
Other income, net |
|
|
30 |
|
|
|
10 |
|
|
|
118 |
|
|
|
41 |
|
Refinancing expense |
|
|
|
|
|
|
(19 |
) |
|
|
(178 |
) |
|
|
(54 |
) |
Interest expense |
|
|
(154 |
) |
|
|
(43 |
) |
|
|
(420 |
) |
|
|
(141 |
) |
|
Total other expense |
|
|
(110 |
) |
|
|
(19 |
) |
|
|
(426 |
) |
|
|
(56 |
) |
|
Income/(Loss) From Continuing Operations Before Income Taxes |
|
|
608 |
|
|
|
(27 |
) |
|
|
912 |
|
|
|
20 |
|
Income tax expense |
|
|
235 |
|
|
|
10 |
|
|
|
324 |
|
|
|
24 |
|
|
Income/(Loss) From Continuing Operations |
|
|
373 |
|
|
|
(37 |
) |
|
|
588 |
|
|
|
(4 |
) |
Income from discontinued operations, net of income tax expense |
|
|
49 |
|
|
|
10 |
|
|
|
63 |
|
|
|
24 |
|
|
Net Income/(Loss) |
|
|
422 |
|
|
|
(27 |
) |
|
|
651 |
|
|
|
20 |
|
Dividends for Preferred Shares |
|
|
14 |
|
|
|
4 |
|
|
|
37 |
|
|
|
12 |
|
|
Income/(Loss) Available for Common Stockholders |
|
$ |
408 |
|
|
$ |
(31 |
) |
|
$ |
614 |
|
|
$ |
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding Basic |
|
|
136 |
|
|
|
84 |
|
|
|
130 |
|
|
|
86 |
|
Income/(Loss) From Continuing Operations per Weighted Average
Common Share Basic |
|
$ |
2.64 |
|
|
$ |
(0.51 |
) |
|
$ |
4.22 |
|
|
$ |
(0.21 |
) |
Income From Discontinued Operations per Weighted Average
Common Share Basic |
|
|
0.36 |
|
|
|
0.12 |
|
|
|
0.48 |
|
|
|
0.28 |
|
|
Net Income/(Loss) per Weighted Average Common Share Basic |
|
$ |
3.00 |
|
|
$ |
(0.39 |
) |
|
$ |
4.70 |
|
|
$ |
0.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Number of Common Shares Outstanding Diluted |
|
|
159 |
|
|
|
84 |
|
|
|
151 |
|
|
|
86 |
|
Income/(Loss) From Continuing Operations per Weighted Average
Common Share Diluted |
|
$ |
2.34 |
|
|
$ |
(0.51 |
) |
|
$ |
3.85 |
|
|
$ |
(0.21 |
) |
Income From Discontinued Operations per Weighted Average
Common Share Diluted |
|
|
0.31 |
|
|
|
0.12 |
|
|
|
0.41 |
|
|
|
0.28 |
|
|
Net Income/(Loss) per Weighted Average Common Share Diluted |
|
$ |
2.65 |
|
|
$ |
(0.39 |
) |
|
$ |
4.26 |
|
|
$ |
0.07 |
|
|
See notes to condensed consolidated financial statements.
6
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2006 |
|
|
2005 |
|
(in millions, except shares and par value) |
|
(unaudited) |
|
|
|
|
|
|
ASSETS |
Current Assets |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
1,388 |
|
|
$ |
493 |
|
Restricted cash |
|
|
74 |
|
|
|
49 |
|
Accounts receivable, less allowance for doubtful accounts of $3 and $2 |
|
|
433 |
|
|
|
249 |
|
Inventory |
|
|
397 |
|
|
|
240 |
|
Deferred income taxes |
|
|
59 |
|
|
|
|
|
Derivative instruments valuation |
|
|
961 |
|
|
|
387 |
|
Collateral on deposits in support of energy risk management activities |
|
|
132 |
|
|
|
438 |
|
Prepayments and other current assets |
|
|
214 |
|
|
|
187 |
|
Current assets held-for-sale |
|
|
|
|
|
|
43 |
|
Current assets discontinued operations |
|
|
13 |
|
|
|
110 |
|
|
Total current assets |
|
|
3,671 |
|
|
|
2,196 |
|
|
Property, plant and equipment, net of accumulated depreciation of $814 and $332 |
|
|
11,686 |
|
|
|
2,609 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
Equity investments in affiliates |
|
|
319 |
|
|
|
602 |
|
Notes receivable, less current portion |
|
|
468 |
|
|
|
457 |
|
Goodwill |
|
|
1,547 |
|
|
|
|
|
Intangible assets, net of accumulated amortization of $213 and $79 |
|
|
1,001 |
|
|
|
257 |
|
Intangible assets held-for-sale |
|
|
53 |
|
|
|
|
|
Nuclear decommissioning trust fund |
|
|
331 |
|
|
|
|
|
Derivative instruments valuation |
|
|
360 |
|
|
|
18 |
|
Funded letter of credit |
|
|
|
|
|
|
350 |
|
Deferred income taxes |
|
|
27 |
|
|
|
26 |
|
Other non-current assets |
|
|
244 |
|
|
|
124 |
|
Non-current assets discontinued operations |
|
|
14 |
|
|
|
827 |
|
|
Total other assets |
|
|
4,364 |
|
|
|
2,661 |
|
|
Total Assets |
|
$ |
19,721 |
|
|
$ |
7,466 |
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
Current Liabilities |
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases |
|
$ |
123 |
|
|
$ |
95 |
|
Accounts payable |
|
|
278 |
|
|
|
241 |
|
Derivative instruments valuation |
|
|
901 |
|
|
|
679 |
|
Accrued expenses and other current liabilities |
|
|
485 |
|
|
|
172 |
|
Current liabilities discontinued operations |
|
|
8 |
|
|
|
170 |
|
|
Total current liabilities |
|
|
1,795 |
|
|
|
1,357 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
7,826 |
|
|
|
2,410 |
|
Nuclear decommissioning reserve |
|
|
278 |
|
|
|
|
|
Nuclear decommissioning trust liability |
|
|
319 |
|
|
|
|
|
Deferred income taxes |
|
|
362 |
|
|
|
128 |
|
Derivative instruments valuation |
|
|
369 |
|
|
|
56 |
|
Out-of-market contracts |
|
|
2,128 |
|
|
|
298 |
|
Other non-current liabilities |
|
|
386 |
|
|
|
170 |
|
Non-current liabilities discontinued operations |
|
|
5 |
|
|
|
569 |
|
|
Total non-current liabilities |
|
|
11,673 |
|
|
|
3,631 |
|
|
Total Liabilities |
|
|
13,468 |
|
|
|
4,988 |
|
|
Minority Interest |
|
|
1 |
|
|
|
1 |
|
3.625% Convertible perpetual preferred stock (at liquidation value, net of issuance costs) |
|
|
247 |
|
|
|
246 |
|
Commitments and Contingencies |
|
|
|
|
|
|
|
|
Stockholders Equity |
|
|
|
|
|
|
|
|
Preferred stock (at liquidation value, net of issuance costs) |
|
|
892 |
|
|
|
406 |
|
Common Stock; $.01 par value; 500,000,000 shares authorized; 137,030,642 and 80,701,888 outstanding |
|
|
1 |
|
|
|
1 |
|
Additional paid-in capital |
|
|
4,458 |
|
|
|
2,431 |
|
Retained earnings |
|
|
782 |
|
|
|
261 |
|
Less treasury stock, at cost 6,113,000 and 19,346,788 shares |
|
|
(297 |
) |
|
|
(663 |
) |
Accumulated other comprehensive income/(loss) |
|
|
169 |
|
|
|
(205 |
) |
|
Total stockholders equity |
|
|
6,005 |
|
|
|
2,231 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
19,721 |
|
|
$ |
7,466 |
|
|
See notes to condensed consolidated financial statements.
7
NRG ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
651 |
|
|
$ |
20 |
|
Adjustments to reconcile net income to net cash provided/(used) by operating activities |
|
|
|
|
|
|
|
|
Distributions in excess/(less than) equity in earnings of unconsolidated affiliates |
|
|
(27 |
) |
|
|
1 |
|
Depreciation and amortization of nuclear fuel |
|
|
490 |
|
|
|
145 |
|
Amortization of financing costs and debt discount |
|
|
24 |
|
|
|
8 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(393 |
) |
|
|
16 |
|
Amortization of unearned equity compensation |
|
|
13 |
|
|
|
8 |
|
Write-off of deferred financing costs and debt premium |
|
|
47 |
|
|
|
(7 |
) |
Write down and (gains) on sale of equity method investments |
|
|
(8 |
) |
|
|
(16 |
) |
Asset impairment |
|
|
|
|
|
|
6 |
|
Changes in deferred income taxes |
|
|
309 |
|
|
|
(54 |
) |
Nuclear decommissioning trust liability |
|
|
9 |
|
|
|
|
|
Minority interest |
|
|
|
|
|
|
1 |
|
Loss on sale of equipment |
|
|
3 |
|
|
|
|
|
Changes in derivatives |
|
|
(301 |
) |
|
|
252 |
|
Gain on legal settlement |
|
|
(67 |
) |
|
|
(14 |
) |
Gain on sale of discontinued operations |
|
|
(71 |
) |
|
|
(11 |
) |
Gain on sale of emission allowances |
|
|
(68 |
) |
|
|
|
|
Changes in collateral deposits supporting energy risk management activities |
|
|
349 |
|
|
|
(598 |
) |
Cash provided by changes in other working capital, net of acquisition and disposition affects |
|
|
88 |
|
|
|
129 |
|
|
Net Cash Provided/(Used) by Operating Activities |
|
|
1,048 |
|
|
|
(114 |
) |
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
Acquisition of Texas Genco LLC, net of cash acquired |
|
|
(4,304 |
) |
|
|
|
|
Acquisition of WCP and Padoma, net of cash acquired |
|
|
(32 |
) |
|
|
|
|
Capital expenditures |
|
|
(159 |
) |
|
|
(46 |
) |
Decrease/(Increase) in restricted cash , net |
|
|
(24 |
) |
|
|
18 |
|
Decrease in notes receivable |
|
|
22 |
|
|
|
100 |
|
Purchases of emission allowances |
|
|
(76 |
) |
|
|
|
|
Proceeds from sale of emission allowances |
|
|
97 |
|
|
|
|
|
Investments in nuclear decommissioning trust fund securities |
|
|
(158 |
) |
|
|
|
|
Proceeds from sales of nuclear decommissioning trust fund securities |
|
|
149 |
|
|
|
|
|
Proceeds from sale of equipment |
|
|
1 |
|
|
|
|
|
Proceeds from sale of investments |
|
|
86 |
|
|
|
70 |
|
Proceeds from sale of discontinued operations |
|
|
239 |
|
|
|
36 |
|
Return of capital from equity method investments and projects |
|
|
|
|
|
|
1 |
|
|
Net Cash Provided/(Used) by Investing Activities |
|
|
(4,159 |
) |
|
|
179 |
|
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
(37 |
) |
|
|
(12 |
) |
Payment for treasury stock |
|
|
(297 |
) |
|
|
(251 |
) |
Payment of minority interest obligations |
|
|
|
|
|
|
(4 |
) |
Borrowing under revolving credit facility, net |
|
|
|
|
|
|
80 |
|
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 |
|
|
|
246 |
|
Proceeds from issuance of long-term debt, net |
|
|
7,373 |
|
|
|
249 |
|
Payment of deferred debt issuance costs |
|
|
(174 |
) |
|
|
(2 |
) |
Payments for short and long-term debt |
|
|
(4,697 |
) |
|
|
(979 |
) |
|
Net Cash Provided/(Used) by Financing Activities |
|
|
3,990 |
|
|
|
(673 |
) |
|
Change in Cash from Discontinued Operations |
|
|
14 |
|
|
|
17 |
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
|
|
2 |
|
|
|
(1 |
) |
|
Net Increase in Cash and Cash Equivalents |
|
|
895 |
|
|
|
592 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
493 |
|
|
|
1,069 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
1,388 |
|
|
$ |
477 |
|
|
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., NRG, or the Company, is a wholesale power generation company, primarily
engaged in the ownership and operation of power generation facilities, the transacting in and
trading of fuel and transportation services, and the marketing and trading of energy, capacity and
related products in the United States.
The accompanying unaudited interim condensed 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, Summary of
Significant Accounting Policies, to the Companys financial statements in its Annual Report on Form
10-K for the fiscal year ended December 31, 2005. The following notes should be read in conjunction with
such policies and other disclosures in the Form 10-K for the fiscal year ended December 31, 2005.
Interim results are not necessarily indicative of results for a full
fiscal year.
In the opinion of management, the accompanying unaudited interim condensed consolidated
financial statements contain all material adjustments (consisting of normal, recurring accruals)
necessary to fairly present NRGs consolidated financial position as of September 30, 2006, the
results of NRGs operations for the three months and nine months ended September 30, 2006 and 2005,
and NRGs cash flows for the nine months ended September 30, 2006 and 2005. 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.
Emission Allowances
NRG actively manages its SO2 and NOX emission allowances, as well as
fuels, and accounts for this asset optimization activity related to emission allowances and other
fuel commodities under EITF Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. As such, revenues and costs for these activities are reflected on a net
basis in the consolidated statement of operations. Emission allowances allocated for trading are
considered to be intangible assets held-for-sale and are valued at the lower of their weighted
average cost or fair value. In accordance with their classification as intangible assets,
purchases and sales of emissions allowances are classified as an investing activity with the
corresponding gains and/or losses on the sales recorded as an adjustment to operating activity in
the consolidated statement of cash flows.
Goodwill and Intangible Assets
Goodwill is the excess of the purchase price of an acquired business over the fair value of
the net assets acquired. NRG accounts for goodwill and other intangibles under the provisions of
SFAS 142, Goodwill and Other Intangible Assets, and consequently NRG does not amortize goodwill.
SFAS 142 requires us to evaluate goodwill and other intangibles not subject to amortization for
impairment at least annually or more often if events and circumstances such as adverse changes in
the business climate, indicate there may be impairment. Goodwill is impaired if the carrying value
of the business exceeds its fair value. Annually, NRG estimates the fair value of the businesses
the Company has acquired using estimated future cash flows or other methods to assess fair value.
If the estimated fair value of the business is less than its carrying value, an impairment loss is
required to be recognized to the extent that the carrying value of goodwill is greater than its
fair value. SFAS 142 also requires the amortization of intangible assets with finite lives.
New Accounting Pronouncements
NRG adopted SFAS 123(R) and Staff Accounting Bulletin 107, or SAB 107, on January 1, 2006
under a modified version of prospective application, or the modified prospective method. Under the
modified prospective method, NRG applied the provisions of SFAS 123(R) to new awards of stock-based
compensation and to awards modified, repurchased, or cancelled after the required effective date.
SFAS 123(R) requires that NRG apply a forfeiture rate to existing awards and to calculate the
retroactive impact of such application. If material, NRG must recognize in income the cumulative
effect of this as a change in accounting principle as of the required effective date. Upon adoption
of SFAS 123(R) on January 1, 2006, NRG applied a forfeiture rate to the Companys existing awards
and recognized in income approximately $1.1 million, or $0.8 million, net of tax, as a reduction to
compensation expense for
9
the nine months ended September 30, 2006. This amount did not materially affect the Companys
consolidated financial position, results of operations or statement of cash flows for the nine
months ended September 30, 2006.
On
January 1, 2006, NRG adopted EITF Issue No. 04-6, Accounting for Stripping Costs Incurred
during Production in the Mining Industry, or EITF 04-6. EITF 04-6 provides that costs incurred to
remove overburden and waste material to access coal seams, or stripping costs , during the
production phase of a mine are variable production costs that should be included in the costs of
the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is
effective for the first reporting period in fiscal years beginning after December 15, 2005. MIBRA
GmbH, or MIBRAG, in which NRG holds a 50% equity investment, has mining operations which were
negatively affected by this pronouncement. MIBRAG had capitalized costs
totaling approximately $185 million (157 million), representing the stripping costs incurred
during production as of December 31, 2005. As a result of the Adoption of EITF 04-6, such costs are
no longer allowed to be capitalized and in accordance with the new pronouncement, were written off
to retained earnings. The adoption of EITF 04-6 did not have a material impact on NRGs
consolidated results of operations, but did have a material impact on NRGs consolidated financial
position. Upon adoption of EITF 04-6 on January 1, 2006, NRGs investment in MIBRAG was reduced by 50% of
the above mentioned asset, approximately $93 million after-tax, with an offsetting charge to
retained earnings.
On January 1, 2006, NRG adopted EITF Issue No. 05-5, Accounting for Early Retirement or
Post-employment Programs with Specific Features (such as terms specified in Altersteilzeit Early
Retirement Arrangements), or EITF 05-5. EITF 05-5 provides guidance on the accounting for early
retirement or post-employment programs with specific features, and specifically the terms of
Altersteilzeit early retirement arrangements. The Altersteilzeit, or ATZ, arrangement is a
voluntary early retirement program in Germany designed to create an incentive for employees, within
a certain age group, to transition from employment into retirement before their legal retirement
age. If certain criteria are met by the employer, the German government provides to the employer a
subsidy for bonuses paid to the employee and the additional contributions paid by the employer into
the German government pension scheme under an ATZ arrangement for a maximum of six years. The Task
Force reached a consensus that the employer should recognize the government subsidy when it meets
the necessary criteria and is entitled to the subsidy. The Task Force also reached a consensus that
payments made by the employer relative to the bonus feature and the additional contributions into
the German government pension scheme, or the additional compensation, should be accounted for as a
post-employment benefit under SFAS No. 112, Employers Accounting for Post-employment Benefits,
which prescribes that an entity should recognize the additional compensation over the period from
the point at which the employee signs the ATZ contract until the end of the active service period.
Upon adoption of EITF 05-5 on January 1, 2006, NRG recognized additional equity in earnings of
unconsolidated affiliates of approximately $2.1 million, after-tax, from the Companys MIBRAG
interest. This amount reflects the cumulative effect of the adoption of EITF 05-5, and did not
materially affect NRGs consolidated financial position, results of operations or statement of cash
flows for the period ending September 30, 2006.
During
the first quarter 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid
Financial Instruments an amendment of FASB Statements Nos. 133 and 140, or SFAS 155. This
statement allows for fair value measurement of certain financial instruments, and eliminates certain
exemptions from fair value measurement found within SFAS 133. The fair value election would not be
available for hybrid instruments with embedded derivative features that are not required to be
bifurcated, such as those that are clearly and closely related to the host instrument, or hybrid
instruments with an embedded derivative that is eligible for one of FAS 133s scope exceptions.
This statement is effective for all financial instruments acquired, issued, or subject to a
re-measurement, or new basis, event occurring after the beginning of the first fiscal year that
begins after September 15, 2006. NRG does not expect this guidance to materially affect the
Companys consolidated financial position, results of operations or statement of cash flows.
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. FIN 48 prescribes a
comprehensive model for recognizing, measuring, presenting and disclosing in the financial
statements tax positions taken or expected to be taken on a tax return, including a decision as to
whether to file or not to file in a particular jurisdiction. FIN 48 is effective for fiscal years
beginning after December 15, 2006. Changes in net assets as a result of the adoption of FIN 48, if
any, are to be accounted for as an adjustment to retained earnings. NRG is currently assessing the
impact of FIN 48 on its consolidated financial position.
In
September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, or SFAS 157. This
statement defines fair value, establishes a framework for measuring fair value and expands
disclosures about fair value measurements. This statement is effective for financial statements
issued for fiscal years beginning after November 15, 2007, and interim periods within those years.
NRG is currently assessing the impact of SFAS 157 on its consolidated financial position, results
of operations and cash flows.
In
September 2006, the FASB issued 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), or SFAS 158. This statement requires an employer that sponsors one or more single-employer
defined benefit plans to recognize the funded status of a benefit plan in its statement of
financial position with an offset to other comprehensive income, and recognize as a component of
other comprehensive income, net of tax, the gains or losses and prior service costs or credits that
arise during the period but are not recognized as components of net periodic benefit cost. This
statement is effective for financial statements of issuers of publicly traded equity securities for
the end of the first fiscal year ending after December 15, 2006. NRG does not expect this guidance to
materially affect the Companys consolidated financial position.
10
Note 2 Comprehensive Income/(Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Net Income/(Loss) |
|
$ |
422 |
|
|
$ |
(27 |
) |
|
$ |
651 |
|
|
$ |
20 |
|
Changes in pension liability, net of tax |
|
|
7 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
Unrealized gain/(loss) from derivative activity, net of tax |
|
|
28 |
|
|
|
(296 |
) |
|
|
332 |
|
|
|
(382 |
) |
Foreign currency translation adjustment |
|
|
(2 |
) |
|
|
|
|
|
|
35 |
|
|
|
(50 |
) |
|
Other comprehensive income/(loss), net of tax |
|
$ |
33 |
|
|
$ |
(296 |
) |
|
$ |
374 |
|
|
$ |
(432 |
) |
|
Comprehensive income/(loss) |
|
$ |
455 |
|
|
$ |
(323 |
) |
|
$ |
1,025 |
|
|
$ |
(412 |
) |
|
Accumulated other comprehensive income/(loss) for the nine months ended September 30, 2006 was
as follows:
|
|
|
|
|
(In millions) As of September 30 |
|
2006 |
|
|
Accumulated other comprehensive loss as of December 31, 2005 |
|
$ |
(205 |
) |
Changes in pension liability, net of tax |
|
|
7 |
|
Unrealized gain from derivative activity, net of tax |
|
|
332 |
|
Foreign currency translation adjustments |
|
|
35 |
|
|
Accumulated other comprehensive income as of September 30, 2006 |
|
$ |
169 |
|
|
Note 3 Business Acquisitions and Dispositions
Acquisition of Texas Genco LLC and Related Financing
On February 2, 2006, NRG acquired Texas Genco LLC pursuant to an Acquisition Agreement dated
September 30, 2005. As such, the results of Texas Genco LLC have
been included in NRGs consolidated
financial statements since February 2, 2006. The purchase price of approximately $6.2 billion
consisted of approximately $4.4 billion in cash, the issuance of approximately 35.4 million shares
of NRGs common stock valued at approximately $1.7 billion and acquisition costs of approximately
$0.1 billion. The value of NRGs common stock issued to the Sellers was based on NRGs average
stock price immediately before and after the closing date of February 2, 2006. The acquisition also
included the assumption of approximately $2.7 billion of Texas Genco LLC debt. Texas Genco LLC is
now a wholly-owned subsidiary of NRG, and is being managed and accounted for as a separate business
segment referred to as NRG Texas.
The acquisition of Texas Genco LLC and related financing activities were funded at closing
with a combination of (i) cash proceeds received upon the issuance and sale in a public offering of
20,855,057 shares of NRGs common stock at a price of $48.75 per share; (ii) cash proceeds received
upon the issuance and sale of $1.2 billion aggregate principal amount of 7.25% Senior Notes due
2014 and $2.4 billion aggregate principal amount of 7.375% Senior Notes due 2016; (iii) cash
proceeds received upon the issuance and sale in a public offering of 2,000,000 shares of mandatory
convertible preferred stock at a price of $250 per share; (iv) funds borrowed under a new senior
secured credit facility consisting of a $3.6 billion term loan facility, a $1.0 billion revolving
credit facility and a $1.0 billion synthetic letter of credit facility; and (v) cash on hand.
Like the rest of NRG, NRG Texas is a wholesale power generator whose principal business is
selling electric wholesale power produced by power plants to wholesale purchasers such as retail
electric providers, power trading organizations and other power generation companies. NRG Texas is
the second-largest generation company in the ERCOT market and the largest owner of power plants in
the Houston area. As of September 30, 2006, NRG Texas operated 52 generating units at nine power
generation plants, including an undivided 44% interest in two nuclear generation units at STP. The
aggregate net generation capacity at NRG Texas is approximately 10,800 MW, which includes
approximately 5,300 MW of low marginal cost solid fuel and nuclear powered baseload plants.
The acquisition of Texas Genco LLC was accounted for using the purchase method of accounting
and, accordingly, the purchase price was allocated to the assets acquired and liabilities assumed
based on the estimated fair value of such assets and liabilities as of February 2, 2006. The excess
of the purchase price over the fair value of the net tangible and identified intangible assets
acquired was recorded as goodwill. The allocation of the purchase price may be adjusted if
additional information on known contingencies existing at the date of acquisition becomes available
within one year after the acquisition, and longer for certain income tax items. Changes in the
allocation between the assessed goodwill and plant or other intangibles would result in a change in
non-cash amortization expense.
11
The following table summarizes the fair value of the assets acquired and liabilities assumed
at the date of the acquisition.
|
|
|
|
|
(In millions) |
|
As of February 2, 2006 |
|
|
Assets |
|
|
|
|
Current and non-current assets |
|
$ |
832 |
|
Coal inventory |
|
|
33 |
|
In-market contracts |
|
|
|
|
Power contracts |
|
|
39 |
|
Water contracts |
|
|
64 |
|
Coal contracts |
|
|
100 |
|
Nuclear fuel contracts |
|
|
48 |
|
SO2 emission allowances |
|
|
530 |
|
NOx emission allowances |
|
|
320 |
|
Property, plant and equipment |
|
|
9,318 |
|
Deferred tax asset |
|
|
1,560 |
|
Goodwill |
|
|
1,555 |
|
|
Total assets acquired |
|
|
14,399 |
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
Current and non-current liabilities |
|
|
937 |
|
Pension and post-retirement liability |
|
|
213 |
|
Out-of-market contracts: |
|
|
|
|
Coal |
|
|
150 |
|
Gas swaps |
|
|
472 |
|
Power contracts |
|
|
2,100 |
|
Deferred tax liability |
|
|
1,560 |
|
Long term debt |
|
|
2,735 |
|
|
Total liabilities assumed |
|
|
8,167 |
|
|
Net assets acquired |
|
$ |
6,232 |
|
|
NRG is still in the process of finalizing the value of the tax basis of the assets and
liabilities acquired which may affect the deferred tax balances with any changes to the tax basis
values affecting the final balance of goodwill. NRG is also in the process of reviewing the
estimated remaining useful lives for NRG Texass fixed assets, and when finalized, this may affect
the amount of depreciation expense NRG will recognize.
The following table summarizes the change in the value of goodwill during the six month period
ended September 30, 2006:
|
|
|
|
|
(In millions) |
|
|
|
|
|
Goodwill balance at March 31, 2006 |
|
$ |
2,748 |
|
Increase in fixed assets per valuation |
|
|
(888 |
) |
Net decrease in intangibles and other contracts per valuation |
|
|
319 |
|
Adjustment to deferred tax assets and liabilities |
|
|
(624 |
) |
|
Impact to goodwill due to changes in valuation |
|
|
(1,193 |
) |
|
Goodwill balance at September 30, 2006 |
|
$ |
1,555 |
|
|
The changes in the fair value for fixed assets, identifiable intangibles and deferred taxes
are due to several factors, including the following:
|
|
|
Adjustments to the forecasted projected price of electricity, coal and emission allowances; |
|
|
|
|
The tax basis of the assets and liabilities acquired are more accurate, although still subject to revision; and |
|
|
|
|
More precise information with respect to identifiable tangible and intangibles assets. |
Currently, NRG has valued goodwill at approximately $1.6 billion, with the appraisal of
Property, Plant and Equipment increasing its fair value, compared to Texas Genco LLCs historical
cost, by approximately $5.8 billion. If the remaining goodwill balance is indicative of a further
increase in value of depreciable property plant and equipment, depreciation expense for the three
months and nine months ended September 30, 2006 would increase by approximately $20 million and $55
million, respectively, reducing income from continuing operations before tax for the three and nine
month period ended September 30, 2006 to approximately $588 million and $857 million, respectively.
12
Acquisition of Remaining 50% interest in WCP
On December 27, 2005, NRG entered into purchase and sale agreements for projects co-owned with
Dynegy, Inc, or Dynegy, with these agreements consummated March 31, 2006. Under the agreements NRG acquired
Dynegys 50% ownership interest in WCP (Generation) Holdings, Inc., or WCP, for $205 million and
NRG became the sole owner of WCPs 1,808 MW of generation capacity in Southern California. In
addition, NRG sold to Dynegy its 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 sale price of $45 million, thus 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 unconsolidated 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
book 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 its book value of
approximately $159 million at the date of the New Investment.
The value of the New Investment was allocated based on the estimated fair value of assets
acquired and liabilities assumed as of March 31, 2006. The preliminary purchase price allocation
reflected an excess of fair value of the net assets acquired over the purchase price of the New
Investment, which resulted in negative goodwill of approximately $63 million. The negative goodwill
was subsequently allocated as a reduction to the fair value of WCPs fixed assets. Once the WCP
asset appraisals are final, the purchase price allocation may change from the amounts included
herein based on the results of appraisal, changes in forecasted prices and an analysis of the
income tax effect on the acquisition.
The following summarizes the preliminary purchase price and allocation impact of the WCP
acquisition as of March 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
New Investment |
|
|
|
|
|
|
|
|
|
|
Fair Value before |
|
|
|
|
|
|
Fair Value after |
|
|
Preliminary |
|
|
|
Original |
|
|
Negative Goodwill |
|
|
Allocation of |
|
|
Negative Goodwill |
|
|
Purchase Price |
|
(In millions) |
|
Investment |
|
|
Allocation |
|
|
Negative Goodwill |
|
|
Allocation |
|
|
Allocation |
|
|
Current assets |
|
$ |
148 |
|
|
$ |
152 |
|
|
$ |
|
|
|
$ |
152 |
|
|
$ |
300 |
|
Property, plant and equipment |
|
|
24 |
|
|
|
127 |
|
|
|
(57 |
) |
|
|
70 |
|
|
|
94 |
|
Intangible assets |
|
|
2 |
|
|
|
14 |
|
|
|
(6 |
) |
|
|
8 |
|
|
|
10 |
|
Other non-current assets |
|
|
|
|
|
|
8 |
|
|
|
|
|
|
|
8 |
|
|
|
8 |
|
Current liabilities |
|
|
(12 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
(12 |
) |
|
|
(24 |
) |
Non-current liabilities |
|
|
(3 |
) |
|
|
(21 |
) |
|
|
|
|
|
|
(21 |
) |
|
|
(24 |
) |
Negative goodwill |
|
|
|
|
|
|
(63 |
) |
|
|
63 |
|
|
|
|
|
|
|
|
|
|
Total Equity |
|
$ |
159 |
|
|
$ |
205 |
|
|
$ |
|
|
|
$ |
205 |
|
|
$ |
364 |
|
|
Supplemental Pro Forma Information
The following unaudited pro forma information represents the results of operations as if NRG,
NRG Texas and WCP had combined at the beginning of the respective reporting periods. The unaudited
pro forma information is not indicative of what the combined companys result of operations would
have been had the companies been combined prior to the respective reporting periods or of future
results of the combined operations.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Operating revenues |
|
$ |
1,625 |
|
|
$ |
4,738 |
|
|
$ |
3,942 |
|
Net income |
|
|
175 |
|
|
|
325 |
|
|
|
363 |
|
Earnings per share Basic |
|
|
1.43 |
|
|
|
2.14 |
|
|
|
2.88 |
|
Earnings per share Diluted |
|
|
1.31 |
|
|
|
1.85 |
|
|
|
2.65 |
|
Weighted average number of shares outstanding Basic |
|
|
118.9 |
|
|
|
134.4 |
|
|
|
121.3 |
|
Weighted average number of shares outstanding Diluted |
|
|
129.4 |
|
|
|
155.4 |
|
|
|
131.8 |
|
The pro forma net income for the nine months ended September 30, 2006 reflects the following
nonrecurring expenses incurred by Texas Genco LLC before February 2, 2006:
|
|
|
|
|
(In millions) |
|
|
|
|
|
Equity compensation costs incurred due to immediate vesting of
equity compensation awards under change of control provisions |
|
$ |
271 |
|
Professional fees and other acquisition-related costs |
|
|
61 |
|
|
Total |
|
$ |
332 |
|
|
13
Other Business Events
Resource Recovery On August 31, 2006, NRG signed an agreement to sell its Newport and Elk
River Resource Recovery facilities, its Becker Ash Disposal facility, and its ownership interest in
NRG Processing Solutions LLC, to Resource Recovery Technologies, LLC for total proceeds of
approximately $26 million, subject to customary purchase price adjustments. The transaction is
expected to close in the fourth quarter 2006, and is subject to customary approvals by the
Minnesota Pollution Control Agency and other contractual partners.
Flinders On August 30, 2006, NRG announced the completion of the sale of its 100% owned
Flinders power station and related assets or Flinders, located near Port Augusta, Australia, which
consists of two coal-fueled plants Northern and Playford totaling 760 gross MW, to Babcock &
Brown Power Pty, a subsidiary of Babcock & Brown, a global investment and advisory firm. Proceeds
from the sale were approximately $242 million (AU$317 million). The sale resulted in the
elimination of approximately of approximately $370 million (AU$485 million) of consolidated
liabilities including approximately $183 million (AU$240 million) of non-recourse debt obligations
and approximately $92 million (AU$121 million) in non-current liabilities related to the
obligations for the purchase of electricity and the supply of fuel to the Osborne power station
that were guaranteed by NRG. NRG recognized an after-tax gain of approximately $61 million from the
sale, which is included in the other international segment results.
Padoma On July 14, 2006, NRG announced the completion of the acquisition of privately-held
Padoma Wind Power, LLC, or Padoma, a wind farm developer, whose principals have developed, financed,
built and operated wind farms in the U.S. and Europe. Padoma will maintain its headquarters in La
Jolla, California and will operate as a subsidiary of NRG. The initial purchase price of $7 million
was completely allocated to goodwill and is included as part of NRGs non-generation segments assets.
Gladstone On June 8, 2006, NRG announced the sale of the Companys 37.5% equity interest in
the Gladstone power station, or Gladstone, and its associated 100% owned NRG Gladstone Operating
Services to Transfield Services, an Australia-based provider of operations, maintenance, ownership
and asset management services for a purchase price of approximately $178 million (AU$239 million)
subject to customary purchase price adjustments, plus assumption of NRGs share of Gladstones
unconsolidated debt and cash of approximately $58 million (AU$ 77 million) and approximately $26
million (AU$35 million), respectively. After-tax cash proceeds are expected to be in excess of $175
million (AU$ 234 million). The sale is pending until NRG satisfies certain conditions, particularly
the securing of certain consents and waivers from the other owners of the project, or agrees to
complete the sale on alternative terms. NRG is seeking to close the transaction in 2007.
Audrain On March 29, 2006, NRG completed the sale of Audrain generating station, a gas-fired
peaking facility in Vandalia, Missouri, to AmerenUE, a subsidiary of Ameren Corporation. The
proceeds from the sale were $115 million, plus AmerenUEs assumption of $240 million of
non-recourse capital lease obligations and assignment of a $240 million note receivable. NRG
recorded a pre-tax gain of $15 million.
As discussed in Note 4 below, the activities of Resource Recovery, Flinders and Audrain have
been classified as discontinued operations.
Note 4 Discontinued Operations
NRG has classified certain business operations, and gains/losses recognized on sale, as
discontinued operations for businesses that were sold or have met the required criteria for such
classification. The financial results for all of these businesses have been accounted for as
discontinued operations. Accordingly, current period operating results and prior periods have been
restated to report the operations as discontinued.
SFAS 144, requires that discontinued operations be valued on an asset-by-asset basis at the
lower of carrying amount or fair value less costs to sell. In applying those provisions, NRGs
management considered cash flow analysis and offers related to the assets and businesses. This
amount is included in income/loss from discontinued operations, net of income taxes in the
accompanying condensed consolidated statements of operations. In accordance with SFAS 144, assets
held for sale will not be depreciated commencing with their classification as such.
The assets and liabilities reported in the balance sheet as of December 31, 2005 as
discontinued operations represent disposed operations of entities discussed in Note 3. For the
three and nine months ended September 30, 2006 the after-tax gains recognized on the sale of
discontinued operations were approximately $61 million and $71 million, respectively, and
approximately $11 million was recognized for the three and nine months ended September 30, 2005.
For the three and nine months ended September 30, 2006, discontinued operations consisted of
activity related to Resource Recovery, Flinders and Audrain. For the three and nine months ended
September 30, 2005, discontinued operations consisted of activity related to Resource Recovery,
Flinders, Audrain, NRG McClain, Northbrook New York, LLC, and Northbrook Energy, LLC.
14
Summarized results of operations of discontinued operations are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Operating revenues |
|
$ |
39 |
|
|
$ |
79 |
|
|
$ |
184 |
|
|
$ |
228 |
|
Pre-tax income/(loss) from operations of discontinued operations |
|
|
(13 |
) |
|
|
(1 |
) |
|
|
(9 |
) |
|
|
11 |
|
Income from discontinued operations, net of income taxes |
|
|
49 |
|
|
|
10 |
|
|
|
63 |
|
|
|
24 |
|
|
Note 5 Write Downs and Gains/(Losses) on Sales of Equity Method Investments
Write downs and gains/(losses) on sales of equity method investments recorded in the condensed
consolidated statement of operations include the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Latin American funds, or SLAP |
|
$ |
|
|
|
$ |
|
|
|
$ |
3 |
|
|
$ |
|
|
James River |
|
|
(3 |
) |
|
|
|
|
|
|
(6 |
) |
|
|
|
|
Cadillac |
|
|
|
|
|
|
|
|
|
|
11 |
|
|
|
|
|
Enfield |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12 |
|
Kendall |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
4 |
|
|
Total write downs and gains/(loss) on sales of equity method investments |
|
$ |
(3 |
) |
|
$ |
4 |
|
|
$ |
8 |
|
|
$ |
16 |
|
|
SLAP On June 30, 2006, NRG, through its wholly-owned entities NRG Caymans-C and NRG
Caymans-P completed the sale of its remaining interests in various Latin American power funds to a
subsidiary of Australia Post. Total proceeds received were approximately $23 million and a pre-tax
gain of approximately $3 million was recognized in the second quarter 2006.
James River On May 15, 2006, NRG completed the sale of Capistrano Cogeneration Company, a
subsidiary of NRG which owned a 50% interest in James River, to Cogentrix. The proceeds from the
sale were approximately $8 million. As a result of the sale, NRG recorded a pre-tax loss of
approximately $6 million.
Cadillac On January 1, 2006, NRG sold its 49.5% of its 50% interest in a 38MW biomass fuel
generation facility located in Cadillac, Michigan, along with its right to receive Production Tax
Credits, or PTCs, through 2009 to Lakes Renewable LLC. In consideration, NRG received an up-front
payment of $0.3 million, approximately $4 million in a note receivable and a promissory note equal
to the value of its share in future PTCs earned through 2009. The sale was contingent upon the
receipt of a favorable private letter ruling from the Internal Revenue Service, or IRS, and
accordingly, all consideration was held in escrow. On April 13, 2006, NRG sold its remaining 0.5%
share in Cadillac along with its interest in the notes receivable and promissory note to Delta
Power for approximately $11 million, resulting in a pre-tax gain of approximately $11 million.
Note 6 Investments Accounted for by the Equity Method
As of December 31, 2005, NRG had a 50% interest in both MIBRAG and WCP, which were considered
significant as defined by applicable SEC regulations. As discussed in Note 3, NRG acquired the
remaining 50% interest in WCP on March 31, 2006 and, as such, WCP is no longer accounted for under
the equity method of accounting. As of September 30, 2006, the only equity method investment which
was considered significant was NRGs 50% interest in MIBRAG.
MIBRAG Summarized Financial Information
For the three and nine months ended September 30, 2006, NRG recorded equity earnings for
MIBRAG of $9.3 million and $23.5 million, respectively compared to the three and nine months ended
September 30, 2005 equity earnings from MIBRAG of $8.9 million and $16.8 million, respectively.
The following table summarizes the results of operations for MIBRAG, including interests owned
by NRG and other parties for the periods shown below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
Results of Operations (in millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Operating revenues |
|
$ |
126 |
|
|
$ |
114 |
|
|
$ |
340 |
|
|
$ |
318 |
|
Operating income |
|
|
22 |
|
|
|
24 |
|
|
|
61 |
|
|
|
50 |
|
Net income |
|
|
18 |
|
|
|
18 |
|
|
|
47 |
|
|
|
34 |
|
|
As discussed in Note 1, NRG adopted EITF 04-6 as of January 1, 2006, which negatively affected
NRGs equity investment in MIBRAG. As of December 31, 2005, MIBRAG had an asset valued at
approximately $185 million (157 million), representing
15
stripping costs incurred during mining operations, net of depreciation. Per the guidance of
EITF 04-6, the value of such stripping cost is to be eliminated with an offsetting charge to
retained earnings. As such, NRGs investment in MIBRAG has been reduced by 50% of the above
mentioned asset, approximately $93 million after-tax, with an offsetting charge to retained
earnings.
Note 7 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. 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 in OCI and subsequently
recognize in earnings when the hedged item impacts income. The ineffective portion of a cash flow
hedge is immediately recognized in income.
For derivatives designated as hedges of the fair value of assets or liabilities, the changes
in fair value of both the derivative and the hedged item are recorded in current earnings, thus the
ineffective portion of a hedging derivative instruments change in fair value is captured and is
immediately recognized into earnings.
For derivatives that are not designated as cash flow hedges or do not qualify for hedge
accounting treatment, the changes in the fair value will be immediately recognized in earnings.
Under the guidelines established per SFAS 133, certain derivative instruments may qualify for the
normal purchase and sale exception and are therefore exempt from fair value accounting treatment.
SFAS 133 applies to NRGs energy-related commodity contracts, interest rate swaps and foreign
exchange contracts.
As the Company engages principally in the trading and marketing of its generation assets, most
of NRGs commercial activities qualify for hedge accounting under the requirements of SFAS 133. In
order to so qualify, the physical generation and sale of electricity should be highly probable at
inception of the trade and throughout the period it is held, as is the case with the Companys
baseload plants. For this reason, trades in support of NRGs peaking units will generally not
qualify for hedge accounting treatment with any changes in fair value likely to be reflected on a
mark-to-market basis in the statement of operations. The majority of trades in support of NRGs
baseload units normally qualify for hedge accounting treatment with any change in fair value
reflected in the balance sheets as part of OCI.
Derivative Impact to 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 September 30, 2006, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
|
Rate |
|
|
Total |
|
|
Accumulated OCI balance at June 30, 2006 |
|
$ |
29 |
|
|
$ |
79 |
|
|
$ |
108 |
|
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Mark-to-market of hedge contracts |
|
|
92 |
|
|
|
(65 |
) |
|
|
27 |
|
|
Accumulated OCI balance at September 30, 2006 |
|
$ |
121 |
|
|
$ |
15 |
|
|
$ |
136 |
|
|
Gains expected to be realized from OCI during the next 12 months |
|
$ |
26 |
|
|
$ |
|
|
|
$ |
26 |
|
The following table summarizes the effects of SFAS 133 on NRGs OCI balance attributable to
hedged derivatives for the nine months ended September 30, 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 |
|
|
11 |
|
|
|
(2 |
) |
|
|
9 |
|
Mark-to-market of hedge contracts |
|
|
314 |
|
|
|
9 |
|
|
|
323 |
|
|
Accumulated OCI balance at September 30, 2006 |
|
$ |
121 |
|
|
$ |
15 |
|
|
$ |
136 |
|
|
The following table summarizes the effects of SFAS 133 on NRGs OCI balance attributable to
hedged derivatives for the three months ended September 30, 2005, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
|
Rate |
|
|
Total |
|
|
Accumulated OCI balance at June 30, 2005 |
|
$ |
(77 |
) |
|
$ |
(2 |
) |
|
$ |
(79 |
) |
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
55 |
|
|
|
(2 |
) |
|
|
53 |
|
Mark-to-market of hedge contracts |
|
|
(359 |
) |
|
|
10 |
|
|
|
(349 |
) |
|
Accumulated OCI balance at September 30, 2005 |
|
$ |
(381 |
) |
|
$ |
6 |
|
|
$ |
(375 |
) |
|
16
The following table summarizes the effects of SFAS 133 on NRGs OCI balance attributable to
hedged derivatives for the nine months ended September 30, 2005, net of tax:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
Interest |
|
|
|
|
(In millions) |
|
Commodities |
|
|
Rate |
|
|
Total |
|
|
Accumulated OCI balance at December 31, 2004 |
|
$ |
5 |
|
|
$ |
2 |
|
|
$ |
7 |
|
Realized from OCI during the period: |
|
|
|
|
|
|
|
|
|
|
|
|
Due to realization of previously deferred amounts |
|
|
53 |
|
|
|
(1 |
) |
|
|
52 |
|
Mark-to-market of hedge contracts |
|
|
(439 |
) |
|
|
5 |
|
|
|
(434 |
) |
|
Accumulated OCI balance at September 30, 2005 |
|
$ |
(381 |
) |
|
$ |
6 |
|
|
$ |
(375 |
) |
|
Losses of $1 million and $9 million were reclassified from OCI to current period earnings for
the three and nine months ended September 30, 2006, respectively, compared to losses of $53 million
and $52 million for the three and nine months ended September 30, 2005, respectively, due to the
unwinding of previously deferred amounts. These amounts are recorded on the same line in the
statement of operations in which the hedged items were recorded. In addition, for the three and
nine months ended September 30, 2006, NRG recorded gains in OCI of approximately $27 million and
$323 million, respectively, compared to losses of $349 million and $434 million for the three and
nine months ended September 30, 2005, respectively, related to changes in the fair values of
derivatives accounted for as cash flow hedges. The balance in OCI relating to SFAS 133 as of
September 30, 2006 was an unrecognized gain of approximately $136 million. Over the next 12 months,
the Company expects that $26 million of net gains recorded in
OCI as of September 30, 2006, will be
recognized in earnings.
Derivative Impact to the Statement of Operations
The following table summarizes the pre-tax effects of non-hedge derivatives and derivative
activities that do not qualify as hedges on NRGs statement of operations for the three months
ended September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Revenue from majority-owned subsidiaries |
|
$ |
183 |
|
|
$ |
|
|
|
$ |
183 |
|
Equity in earnings of unconsolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total statement of operations impact before tax |
|
$ |
183 |
|
|
$ |
|
|
|
$ |
183 |
|
|
The following table summarizes the pre-tax effects of non-hedge derivatives and derivative
activities that do not qualify as hedges on NRGs statement of operations for the nine months ended
September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Revenue from majority-owned subsidiaries |
|
$ |
300 |
|
|
$ |
|
|
|
$ |
300 |
|
Equity in earnings of unconsolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
|
|
|
|
|
3 |
|
|
|
3 |
|
Total statement of operations impact before tax |
|
$ |
300 |
|
|
$ |
(3 |
) |
|
$ |
297 |
|
|
With the reclassification of Flinders as a discontinued operation in the second quarter 2006,
previously designated cash flow hedges were no longer effective beyond the expected date of the
sale and thus the deferred gain previously recorded in OCI of approximately $11 million was
recognized as a derivative gain and was included in income from discontinued operations.
The following table summarizes the pre-tax effects of non-hedge derivatives and derivative
activities that do not qualify as hedges on NRGs statement of operations for the three months
ended September 30, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Revenue from majority-owned subsidiaries |
|
$ |
(166 |
) |
|
$ |
|
|
|
$ |
(166 |
) |
Equity in earnings of unconsolidated subsidiaries |
|
|
|
|
|
|
|
|
|
|
|
|
Cost of operations |
|
|
6 |
|
|
|
|
|
|
|
6 |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total statement of operations impact before tax |
|
$ |
(172 |
) |
|
$ |
|
|
|
$ |
(172 |
) |
|
The following table summarizes the pre-tax effects of non-hedge derivatives and derivative
activities that do not qualify as hedges on NRGs statement of operations for the nine months ended
September 30, 2005:
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy |
|
|
|
|
|
|
|
(In millions) |
|
Commodities |
|
|
Interest Rate |
|
|
Total |
|
|
Revenue from majority-owned subsidiaries |
|
$ |
(252 |
) |
|
$ |
|
|
|
$ |
(252 |
) |
Equity in earnings of unconsolidated subsidiaries |
|
|
12 |
|
|
|
|
|
|
|
12 |
|
Cost of operations |
|
|
5 |
|
|
|
|
|
|
|
5 |
|
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total statement of operations impact before tax |
|
$ |
(245 |
) |
|
$ |
|
|
|
$ |
(245 |
) |
|
Energy-Related Commodities
As part of NRGs risk management activities, NRG manages its commodity price risk associated
with the Companys competitive supply activities and the price risk associated with power sales
from NRGs electric generation facilities. In doing so, the Company may enter into a variety of
derivative and non-derivative instruments, including the following:
|
|
|
Forward contracts, which commit NRG to purchase or sell energy commodities in the future. |
|
|
|
|
Futures contracts, which are exchange-traded standardized commitments to purchase or sell
a commodity or financial instrument. |
|
|
|
|
Swap agreements, which require payments to or from counter-parties based upon the
differential between two prices for a predetermined contractual (notional) quantity. |
|
|
|
|
Option contracts, which convey the right to buy or sell a commodity, financial
instrument, or index at a predetermined price. |
The objectives for entering into such hedges include:
|
|
|
Fixing the price for a portion of anticipated future electricity sales through the use of
various derivative instruments including gas swaps at a level that provides an acceptable
return on the Companys electric generation operations. |
|
|
|
|
Fixing the price of a portion of anticipated fuel purchases for the operation of NRGs power plants. |
|
|
|
|
Fixing the price of a portion of anticipated energy purchases to supply NRGs load-serving customers. |
Ineffectiveness Ineffectiveness will result from a difference in the relative price
movements between a financial instrument and the underlying physical pricing point. If this
difference is large enough, it may cause an entity to discontinue the use of hedge accounting. For
the three and nine months ended September 30, 2006, NRGs pre-tax earnings were affected by
unrealized gains of approximately $78 million and $122 million, respectively, due to the
ineffectiveness associated with financial forward contracted electric and gas sales.
Discontinued Hedge Accounting During the third quarter 2006, due to a relatively mild summer
season and expected lower power generation for the remainder of 2006, NRG discontinued cash flow
hedge accounting for certain contracts related to commodity price risk previously accounted for as
cash flow hedges. These contracts were originally entered into as hedges of forecasted sales by
baseload plants. The decision not to deliver against these contracts was driven by the decline in
natural gas and associated power prices making it uneconomical to dispatch the units into the
marketplace. As a result, approximately $5 million of previously deferred revenue in OCI was
recognized in earnings for the three and nine months ended September 30, 2006.
At
September 30, 2006, NRG had hedge and non-hedge energy-related commodity contracts
extending through December 31, 2026.
Interest Rates
NRG is exposed to changes in interest rates through the Companys issuance of variable rate
and fixed rate debt. In order to manage its interest rate risk, NRG enters into interest-rate swap
agreements. In January 2006, in anticipation of the New Senior Credit Facility, NRG entered into a
series of forward starting interest rate swaps intended to hedge the variability in cash flows
associated with this debt issuance. These transactions were designated as cash flow hedges with any
gains/losses deferred on the balance sheet in OCI. In February 2006, with the completion of the
sale of the Senior Notes, the Company designated a fixed-to-floating interest rate swap as a hedge
of fair value changes in the Senior Notes. This interest rate swap was previously designated as a
hedge of NRGs 8% Second Priority Notes which were effectively replaced by the Senior Notes. For
the three months ended September 30, 2006, NRG did not recognize any ineffectiveness associated
with this hedging relationship. For the nine months ended September 30, 2006, NRG recognized $3
million in ineffectiveness associated with this hedging relationship. NRG does not foresee any
ineffectiveness of this hedging relationship in the future.
As of September 30, 2006, all of NRGs interest rate swap arrangements had been designated as
either cash flow or fair value hedges. At September 30, 2006, NRG had interest rate derivative
instruments extending through June 2019.
18
Foreign Currency Exchange Rates
To preserve the U.S. dollar value of projected foreign currency cash flows, NRG may hedge, or
protect those cash flows using available foreign currency hedging instruments. On August 15, 2006,
NRG entered into a forward foreign exchange contract to sell AU$300 million in exchange for $229
million and designated it as a fair value hedge. Due to changes in the exchange rate, NRG
recognized a loss as of September 30, 2006 of approximately $5 million on its cash balance, with an
offsetting gain from derivative income on the related contract. The contract settled on October 16,
2006.
Note 8 Long-Term Debt
Cash Tender Offer and Consent Solicitation
On December 15, 2005, NRG commenced a cash tender offer and consent solicitation for any and
all outstanding $1.1 billion aggregate principal amount of the Companys 8% Second Priority Notes.
On that date, NRG also commenced a cash tender offer and consent solicitation for any and all
outstanding $1.1 billion aggregate principal amount of Texas Genco LLC and Texas Genco Financing
Corp.s 6.875% senior notes due 2014, or the Texas Genco Notes. The offers to purchase the 8%
Second Priority Notes and the Texas Genco Notes were part of NRGs previously announced financing
plan in connection with the acquisition of Texas Genco LLC. As of February 2, 2006, NRG had
received valid tenders from holders in aggregate principal amount of the 8% Second Priority Notes,
representing approximately 99.96% of the outstanding 8% Second Priority Notes, and had received
valid tenders from holders of the $1.1 billion in aggregate principal amount of the Texas Genco
Notes, representing 100% of the outstanding Texas Genco Notes. The purchase price for the 8% Second
Priority Notes of approximately $1.2 billion was paid by NRG on February 2, 2006 and included $0.1
billion prepayment penalty which was recorded in debt refinancing
expense in NRGs consolidated
income statement. The purchase price for the Texas Genco Notes of approximately $1.2 billion was
paid by NRG on February 3, 2006 and included $0.1 billion prepayment penalty which was recorded as
an acquisition cost for the acquisition of NRG Texas.
New Senior Credit Facility
On January 31, 2006, NRG used proceeds from the issuance of common stock and cash on hand to
repay the $446 million outstanding principal balance of NRGs senior secured term loan facility,
along with accrued but unpaid interest of approximately $2 million, and terminated the facility. On
February 2, 2006, NRG used proceeds from the new debt financing to pay accrued but unpaid fees on
the Companys revolving credit facility and funded letter of credit, and terminated those
facilities as well.
On February 2, 2006, NRG entered into a new senior secured credit facility, or the New Senior
Credit Facility, with a syndicate of financial institutions, including Morgan Stanley Senior
Funding, Inc., as administrative agent, Morgan Stanley & Co., Inc., as collateral agent, and Morgan
Stanley Senior Funding, Inc. and Citigroup Global Markets Inc. as joint lead book-runners, joint
lead arrangers and co-documentation agents providing for up to an aggregate amount of $5.575
billion. The New Senior Credit Facility consisted of a $3.575 billion senior first priority secured
term loan facility, or the Term Loan Facility, a $1.0 billion senior first priority secured
revolving credit facility, or the Revolving Credit Facility, and a $1.0 billion senior first
priority secured synthetic letter of credit facility, or the Letter of Credit Facility. The New
Senior Credit Facility replaced NRGs then existing senior secured credit facility. The Term Loan
Facility matures on February 1, 2013 and will amortize in 27 consecutive equal quarterly
installments of 0.25% of the original principal amount of the Term Loan Facility, beginning June
30, 2006, with the balance payable on the seventh anniversary thereof. The full amount of the
Revolving Credit Facility will mature on February 2, 2011. The Letter of Credit Facility will
mature on February 1, 2013 and no amortization will be required in respect thereof. As of September
30, 2006, NRG had approximately $3.557 billion outstanding under the Companys Term Loan Facility.
As of September 30, 2006, NRG had issued $858 million under the Companys Letter of Credit Facility
and $157 million in letters of credit under the Companys Revolving Credit Facility.
The New Senior Credit Facility is guaranteed by substantially all of NRGs existing and future
direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted
foreign subsidiaries, project subsidiaries and certain other subsidiaries. The capital stock of
substantially all of NRGs subsidiaries, with certain exceptions for unrestricted subsidiaries,
foreign subsidiaries and project subsidiaries has been pledged for the benefit of the New Senior
Credit Facility lenders.
The New Senior Credit Facility is also secured by first-priority perfected security interests
in substantially all of the property and assets owned or acquired by NRG and its subsidiaries,
other than certain limited exceptions. These exceptions include assets of certain unrestricted
subsidiaries, equity interests in certain of NRGs project affiliates that have non-recourse debt
financing, and voting equity interests in excess of 66% of the total outstanding voting equity
interest of certain of NRGs foreign subsidiaries.
The New Senior Credit Facility contains customary covenants, which among other things require
NRG to meet certain financial tests, including minimum interest coverage ratio and a maximum
leverage ratio on a consolidated basis, and limit NRGs ability to:
|
|
|
incur indebtedness and liens and enter into sale and lease-back transactions; |
|
|
|
|
make investments, loans and advances; and |
|
|
|
|
pay dividends and/or other payments of subsidiaries. |
19
NRG has the option to prepay the New Senior Credit Facility in whole or in part at any time.
Interest Rate Swaps In anticipation of the New Senior Credit Facility, in January 2006, NRG
entered into a series of forward-setting interest rate swaps. These interest rate swaps became
effective on February 15, 2006 and are intended to hedge the risks associated with floating
interest rates. For each of the interest rate swaps, the Company pays its counterparty the
equivalent of a fixed interest payment on a predetermined notional value, and NRG receives
quarterly the equivalent of a floating interest payment based on a 3-month LIBOR calculated on the
same notional value. All interest rate swap payments by NRG and its counterparties are made
quarterly, and the LIBOR is determined in advance of each interest period. While the 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 is $2.15 billion.
The notional amounts and maturities of each tranche of these swaps are as follows:
|
|
|
|
|
|
|
|
|
|
|
Period of swap |
|
Notional Value |
|
|
Maturity |
|
|
1 year |
|
$120 million |
|
March 31, 2007 |
2 year |
|
$140 million |
|
March 31, 2008 |
3 year |
|
$150 million |
|
March 31, 2009 |
4 year |
|
$190 million |
|
March 31, 2010 |
5 year |
|
$1.55 billion |
|
March 31, 2011 |
|
Senior Notes
On February 2, 2006, NRG completed the sale of (i) $1.2 billion aggregate principal amount of
7.25% senior notes due 2014, or 7.25% Senior Notes, and (ii) $2.4 billion aggregate principal
amount of 7.375% senior notes due 2016, or 7.375% Senior Notes, collectively referred to as the
Senior Notes. The Senior Notes were issued under an Indenture, dated February 2, 2006, or the
Indenture, between NRG and Law Debenture Trust Company of New York, as trustee, or the Trustee, as
supplemented by a First Supplemental Indenture, dated February 2, 2006, between NRG, the Guarantors
named therein and the Trustee, relating to the 7.25% Senior Notes, and as supplemented by a Second
Supplemental Indenture, dated February 2, 2006, between NRG, the Guarantors named therein and the
Trustee, relating to the 7.375% Senior Notes. On March 14, 2006, NRG executed a Third Supplemental
Indenture and a Fourth Supplemental Indenture, whereby the recently acquired NRG Texas subsidiaries
were added as Guarantors. On April 28, 2006, NRG executed a Fifth Supplemental Indenture and a
Sixth Supplemental Indenture, whereby the recently acquired WCP subsidiaries were added as
Guarantors. The Indentures and the form of notes provide, among other things, that the Senior Notes
will be senior unsecured obligations of NRG.
Interest is payable on the Senior Notes on February 1 and August 1 of each year beginning on
August 1, 2006 until their maturity dates February 1, 2014 for the 7.25% Senior Notes and
February 1, 2016 for the 7.375% Senior Notes. As of September 30, 2006, NRG had $3.6 billion in
principal outstanding under the Companys Senior Notes.
At any time prior to February 1, 2009, NRG may redeem up to 35% of the aggregate principal
amount of the series of Senior Notes with the net proceeds of certain equity offerings, at a
redemption price of 107.25% of the principal amount, in the case of the 7.25% Senior Notes, and
107.375% of the principal amount, in the case of the 7.375% Senior Notes. In addition, NRG may
redeem the 7.25% Senior Notes and 7.375% Senior Notes at the redemption prices expressed as a
percentage of the principal amount redeemed set forth below, plus accrued and unpaid interest on
the notes redeemed.
Prior to February 1, 2010 for the 7.25% Senior Notes, or the First Applicable 7.25% Redemption
Date, NRG may redeem all or a portion of the 7.25% Senior Notes at a price equal to 100% of the
principal amount plus a premium and accrued interest. The premium is the greater of (i) 1% of the
principal amount of the note, or (ii) the excess of the principal amount of the note over the
following: the present value of 103.625% of the note, plus interest payments due on the note from
the date of redemption through the First Applicable 7.25% Redemption Date, discounted at a treasury
rate plus 0.50%.
The following table sets forth the premium upon redemption for the 7.25% Senior Notes.
|
|
|
|
|
Redemption Period |
|
Premium as defined above |
|
|
Prior to February 1, 2010 |
|
|
|
|
February 1, 2010 to February 1, 2011 |
|
|
103.625 |
% |
February 1, 2011 to February 1, 2012 |
|
|
101.813 |
% |
February 1, 2012 and thereafter |
|
|
100.000 |
% |
|
Prior to February 1, 2011 for the 7.375% Senior Notes, or the First Applicable 7.375%
Redemption Date, NRG may redeem all or a portion of the 7.375% Notes at a price equal to 100% of
the principal amount plus a premium and accrued interest. The premium is the greater of (i) 1% of
the principal amount of the note, or (ii) the excess of the principal amount of the note over the
following: the present value of 103.688% of the note, plus interest payments due on the note from the date of
redemption through the First Applicable 7.375% Redemption Date, discounted at a Treasury rate plus
0.50%.
20
The following table sets forth the premium upon redemption for the 7.375% Senior Notes.
|
|
|
|
|
Redemption Period |
|
Premium as defined above |
|
|
Prior to February 1, 2011 |
|
|
|
|
February 1, 2011 to February 1, 2012 |
|
|
103.688 |
% |
February 1, 2012 to February 1, 2013 |
|
|
102.458 |
% |
February 1, 2013 to February 1, 2014 |
|
|
101.229 |
% |
February 1, 2014 and thereafter |
|
|
100.000 |
% |
|
The Indentures provide for customary events of default which include, among others, nonpayment
of principal or interest; breach of other agreements in the Indentures; defaults in failure to pay
certain other indebtedness; the rendering of judgments to pay certain amounts of money against NRG
and its subsidiaries; the failure of certain guarantees to be enforceable; and certain events of
bankruptcy or insolvency. Generally, if an event of default occurs, the Trustee or the Holders of
at least 25% in principal amount of the then outstanding series of Senior Notes may declare all of
the Senior Notes of such series to be due and payable immediately.
The terms of the Indentures, among other things, limit NRGs ability and certain of its
subsidiaries ability to:
|
|
|
pay dividends or other payments of subsidiaries; |
|
|
|
|
incur additional debt; and |
|
|
|
|
engage in sale and leaseback transactions. |
Debt of Discontinued Operations
As discussed in Note 3, on August 30, 2006, NRG announced the completion of the sale of
Flinders to Babcock and Brown of Australia. The sale resulted in the elimination of approximately
$183 million (AU$240 million) of non-recourse debt.
On March 29, 2006, NRG completed the sale of the Audrain Generating Station to AmerenUE, a
subsidiary of Ameren Corporation. Included in the purchase was Amerens assumption of $240 million
of non-recourse capital lease obligations and the assignment of a $240 million note receivable.
NRG Promissory Note
On June 5, 2006, NRG, repaid the principal and interest at maturity on its outstanding $10
million note payable to Xcel Energy.
Debt Related to Capital Allocation Program
During the third quarter 2006, NRG initiated a plan, known as the Capital Allocation Program,
to repurchase approximately $750 million of its common stock. Phase I was a $500 million stock repurchase program,
which was completed on October 13, 2006. Phase II, as originally announced, was to be an additional
$250 million common stock buyback anticipated to commence during the first quarter 2007. NRG has
upsized Phase II to $500 million and has accelerated the start to the fourth quarter 2006 and is
expected to be completed by the end of the second quarter 2007.
As part of Phase I, the Company formed two wholly-owned unrestricted subsidiaries, NRG Common
Stock Finance I, LLC and NRG Common Stock Finance II, LLC, during the third quarter 2006 to
repurchase shares of NRGs common stock in the public markets or in privately negotiated
transactions. These subsidiaries were funded with a combination of approximately $166 million in
cash from NRG and a mix of notes and preferred interests issued to Credit Suisse of approximately
$334 million for a total of $500 million. Both the notes and the preferred interests are
non-recourse debt to NRG or any of its restricted subsidiaries, with the notes collateralized by
the NRG common stock purchased by the subsidiaries. In addition, the assets of these two
subsidiaries are not available to the creditors of NRG and its other subsidiaries.
Notes As of September 30, 2006, total notes issued and outstanding by these two wholly-owned
unrestricted subsidiaries were approximately $147 million to Credit Suisse. NRG issued a total of
$250 million in notes in Phase I of the Capital Allocation Program that will mature in two
tranches: $137.5 million in October 2008 plus accrued interest at an annual rate of 5.45%, and the
balance of $112.5 million in October 2009 plus accrued interest at an annual rate of 6.11%.
Preferred
Interests These two wholly-owned unrestricted subsidiaries expect to issue
approximately $84 million in preferred interests in connection
with Phase I of the Capital Allocation
Program. As of September 30, 2006, total preferred interests issued and outstanding was
approximately $50 million to Credit Suisse. These preferred interests are classified as a liability
per SFAS No. 150, because they embody a fixed unconditional obligation that these two unrestricted
subsidiaries must settle. The preferred interests also
mature in two tranches: $53 million in October 2008 plus accrued interest at an annual rate of
12.65%, and $31 million in October 2009 plus accrued interest at an annual rate of 13.23%.
21
Note 9 Changes in Capital Structure
As of September 30, 2006, NRG had 10,000,000 authorized preferred shares, 2,670,000 of which
have been issued and were outstanding. The outstanding preferred shares are comprised of: 420,000
of 4% Preferred Stock, 250,000 of 3.625% Preferred Stock and 2,000,000 of 5.75% Preferred Stock.
Treasury Stock Purchased through Capital Allocation Program
During the third quarter 2006, NRG purchased 6,113,000 of its common stock at a
volume-weighted average price of $48.61 per share for a total amount of approximately $297 million
through its Capital Allocation Program. At maturity, should NRGs stock price exceed a compound
annual growth rate of 20%, beyond a volume-weight average share price determined at the time of
repurchase, or the Reference Price, NRG will pay to Credit Suisse the market value of NRGs stock
price over the Reference Price in either cash or stock. This difference will be recorded as an
increase to the cost of the treasury shares repurchased.
On October 13, 2006, NRG completed the first phase of the Capital Allocation Program,
resulting in the repurchase of 10,587,700 of its common stock for approximately $500 million.
5.75% Preferred Stock
On February 2, 2006, NRG completed the issuance of 2,000,000 shares of 5.75% mandatory
convertible preferred stock, or the 5.75% Preferred Stock, for net proceeds of $486 million,
reflecting an offering price of $250 per share and the deduction of offering expenses and discounts
of approximately $14 million. Dividends on the 5.75% Preferred Stock are $14.375 per share per
year, and are due and payable on a quarterly basis beginning on March 15, 2006. The 5.75% Preferred
Stock will automatically convert into common stock on March 16, 2009, or the Conversion Date, at a
rate that is dependent upon the applicable market value of NRGs common stock.
The following table illustrates the conversion rate per share of the 5.75% Preferred Stock:
|
|
|
|
|
Applicable Market Value on Conversion Date |
|
Conversion Rate |
|
|
equal to or greater than $60.45 |
|
|
4.1356 |
|
less than $60.45 but greater than $48.75 |
|
|
4.1356 to 5.1282 |
|
less than or equal to $48.75 |
|
|
5.1282 |
|
|
Stock issued to the Sellers pursuant to the Acquisition Agreement
On February 2, 2006, pursuant to the Acquisition Agreement, NRG issued 35,406,292 shares of
common stock to the Sellers. Of this amount, 19,346,788 shares were issued from treasury and
16,059,504 were newly issued shares. See Note 3 for a further discussion. On August 1, 2006, the
lock-up period on the 35,406,292 shares was lifted pursuant to the Investor Rights Agreement
between the Sellers and NRG.
Common Stock issued to the public
On January 31, 2006, NRG completed the issuance of 20,855,057 shares of NRGs common stock, for net proceeds of $986 million, reflecting an offering price of $48.75 per
share after the deduction of offering expenses and discounts of approximately $31 million.
Second Lien Structure
Before the Acquisition, Texas Genco LLCs capital structure permitted the grant of second
priority liens on its assets as security for its obligations under certain long-term power sales
agreements and related hedges. The New Senior Credit Facility and the Indentures, which
became effective as of February 2, 2006, allow these arrangements to remain in place. In addition,
the new debt instruments also permit NRG to grant second priority liens on NRGs other assets in
the United States in order to secure obligations under power sales agreements and related hedges,
with certain limitations. 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 long-term power sales agreements and related hedges. As of September
30, 2006, the net discounted exposure on the hedges that were subject to the second lien structure was
approximately $897 million.
22
Note 10 Equity Compensation
Incentive Compensation Plans
In December 2004, the FASB issued SFAS No. 123(R) Share-Based Payment, a revision to SFAS 123,
or SFAS 123(R), which requires NRG to modify the recognition of expense for stock-based
compensation in the statement of income. NRG adopted the requirements of SFAS 123(R) effective
January 1, 2006 using the modified prospective method. The provisions of SFAS 123(R) did not result
in a significant change in NRGs compensation expense because the Company previously recognized
compensation expense in the statements of income under SFAS 123. In accordance with SFAS 123(R),
NRG estimated a forfeiture rate for each of the Companys awards based on the number of instruments
expected to vest rather than recording the actual forfeitures as they occur. The elimination of
unearned compensation and amounts previously recognized in income related to the application of the
new forfeiture rate to outstanding instruments as of January 1, 2006 were immaterial to NRGs
consolidated results of operations.
Long-Term Incentive Plan, or LTIP
As of September 30, 2006, a total of 8,000,000 shares of NRG common stock were authorized for
issuance under the LTIP, subject to adjustments in the event of a reorganization, recapitalization,
stock split, reverse stock split, stock dividend, and combination of shares, merger or similar
change in NRGs structure or outstanding shares of common stock. It is NRGs policy to issue
treasury shares upon exercise of a LTIP award. If there are no treasury shares available, unissued
shares of common stock will be issued. There were 4,300,489 shares of common stock remaining
available for grants under NRGs LTIP as of September 30, 2006.
Non-Qualified Stock Options, or NQSOs
NQSOs granted under the LTIP have a three-year graded vesting schedule beginning on the grant
date and become exercisable at the end of this requisite service period. As provided for by SFAS
123(R), for share options with graded vesting issued after January 1, 2006, NRG recognizes
compensation costs on a straight-line basis over the requisite service period for the entire award.
The maximum contractual term is ten years for approximately 600,000 of NRGs outstanding NQSOs,
and six years for the remaining 1.1 million NQSOs. The aggregate intrinsic value for stock options
outstanding as of September 30, 2006 and 2005 was approximately $57 million and $19 million,
respectively. The aggregate intrinsic value for stock options exercisable as of September 30, 2006
and 2005 was approximately $15 million and $6 million, respectively. The weighted average remaining
contractual term for stock options outstanding as of September 30, 2006 and 2005 was approximately
six and seven years, respectively. The weighted average remaining contractual term for stock
options exercisable as of September 30, 2006 and 2005 was approximately seven and eight years,
respectively. Cash received from the exercise of NQSOs and the intrinsic value of exercised NQSOs
for the nine months ended September 30, 2006 was $1.1 million and $1.3 million, respectively.
The fair value of stock option grants is estimated on the date of grant using the
Black-Scholes option-pricing model. The following table shows the change in the outstanding NQSO
balance for the nine months ended September 30, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
Weighted Average |
|
|
|
|
|
|
|
Average |
|
|
Grant-Date Fair |
|
(In whole, except weighted average data) |
|
Shares |
|
|
Exercise Price |
|
|
Value Per Share |
|
|
Outstanding as of December 31, 2004 |
|
|
962,751 |
|
|
$ |
23.15 |
|
|
$ |
12.15 |
|
Granted |
|
|
134,000 |
|
|
|
38.80 |
|
|
|
13.23 |
|
Canceled or Expired |
|
|
|
|
|
|
N/A |
|
|
|
N/A |
|
Exercised |
|
|
|
|
|
|
N/A |
|
|
|
N/A |
|
|
Outstanding at September 30, 2005 |
|
|
1,096,751 |
|
|
|
25.06 |
|
|
|
12.29 |
|
Exercisable at September 30, 2005 |
|
|
318,248 |
|
|
|
23.08 |
|
|
|
12.13 |
|
|
Outstanding as of December 31, 2005 |
|
|
1,095,251 |
|
|
|
25.04 |
|
|
|
12.29 |
|
Granted |
|
|
711,785 |
|
|
|
47.51 |
|
|
|
14.18 |
|
Canceled or Expired |
|
|
(92,968 |
) |
|
|
34.64 |
|
|
|
12.06 |
|
Exercised |
|
|
(49,832 |
) |
|
|
21.48 |
|
|
|
9.77 |
|
|
Outstanding at September 30, 2006 |
|
|
1,664,236 |
|
|
|
34.22 |
|
|
|
13.18 |
|
Exercisable at September 30, 2006 |
|
|
618,327 |
|
|
|
24.26 |
|
|
|
12.44 |
|
|
The fair value of NQSOs issued during the nine months ended September 30, 2006 was based on
the following assumptions:
|
|
|
|
|
Nine Months Ended September 30, |
|
2006 |
|
|
Weighted average annualized valuation assumptions |
|
|
|
|
Expected Volatility |
|
|
27.95% 29.64 |
% |
Weighted Average Volatility |
|
|
28.37 |
% |
Expected Dividends |
|
|
|
|
Expected Term (in years) |
|
|
4 6 |
|
Risk Free Rate |
|
|
4.30% 5.05 |
% |
Forfeiture Rate |
|
|
8 |
% |
|
23
NRG uses an expected term of four years for NQSOs based on the simple average of the
contractual term and vesting term. Volatility is calculated based on a blended average of NRG and
NRGs industry peers historical two-year stock price volatility data. A forfeiture rate of 8% was
calculated for NQSOs based on an analysis of NRGs historical forfeitures, employment turnover,
and expected future behavior.
Restricted Stock Units, or RSUs
RSUs granted under the LTIP fully vest three years from the date of issuance. Compensation
expense is based on the fair value of the RSUs which is based on the closing price of NRG common
stock on the date of grant multiplied by the number of RSUs granted. Such compensation expense,
net of forfeitures, is amortized over the requisite service period. In determining NRGs forfeiture
rate, two separate forfeiture rates that best represented the employment termination behavior
related to issued RSUs were used, 8% for senior management and 25% for all other employees. The
forfeiture rates were based on an analysis of NRGs historical forfeitures, employment turnover,
and expected future behavior. The aggregate intrinsic values for non-vested RSUs on September 30,
2006 and 2005 were approximately $61 million and $55 million, respectively.
The following table shows the change in the outstanding RSU balance for the nine months ended
September 30, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
Average Grant- |
|
|
|
|
|
|
|
Date Fair Value |
|
(In whole except weighted average data) |
|
Shares |
|
|
Per Share |
|
|
Non-vested as of December 31, 2004 |
|
|
880,994 |
|
|
$ |
21.59 |
|
Granted |
|
|
473,850 |
|
|
|
38.70 |
|
Canceled |
|
|
(56,600 |
) |
|
|
22.78 |
|
Exercised |
|
|
(1,500 |
) |
|
|
19.90 |
|
|
Non-vested at September 30, 2005 |
|
|
1,296,744 |
|
|
|
27.80 |
|
|
Non-vested as of December 31, 2005 |
|
|
1,285,944 |
|
|
|
27.14 |
|
Granted |
|
|
201,093 |
|
|
|
47.24 |
|
Canceled |
|
|
(118,500 |
) |
|
|
28.86 |
|
Exercised |
|
|
(20,000 |
) |
|
|
38.80 |
|
|
Non-vested at September 30, 2006 |
|
|
1,348,537 |
|
|
$ |
30.43 |
|
|
Deferred Stock Units, or DSUs
DSUs granted under the LTIP are fully vested at the date of issuance. Compensation expense
recorded is the fair value of the DSU based on the closing price of NRG common stock on the date of
grant. For DSUs, compensation expense is fully recognized in the period of grant. The aggregate
intrinsic values for DSUs outstanding at September 30, 2006 and September 30, 2005 were
approximately $6 million and $5 million, respectively. The aggregate intrinsic values for DSUs
converted for the nine months ended September 30, 2006 and 2005 was $0.4 million and $0.3 million,
respectively. None of the DSUs issued were either canceled or had expired as of September 30, 2006
and 2005.
The following table shows the change in the outstanding DSU balance for the nine months ended
September 30, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
|
|
|
|
Grant-Date Fair |
|
(In whole, except weighted average data) |
|
Shares |
|
|
Value Per Share |
|
|
Outstanding as of December 31, 2004 |
|
|
60,281 |
|
|
$ |
20.31 |
|
Granted |
|
|
68,201 |
|
|
|
37.54 |
|
Conversions |
|
|
(6,298 |
) |
|
|
28.20 |
|
|
Outstanding at September 30, 2005 |
|
|
122,184 |
|
|
|
29.21 |
|
|
Outstanding as of December 31, 2005 |
|
|
122,184 |
|
|
|
29.21 |
|
Granted |
|
|
25,830 |
|
|
|
49.22 |
|
Conversions |
|
|
(7,594 |
) |
|
|
38.75 |
|
|
Outstanding at September 30, 2006 |
|
|
140,420 |
|
|
$ |
32.38 |
|
|
Performance Units, or PUs
NRGs outstanding PUs will be paid out after vesting if the average closing price of NRGs
common stock for the ten trading days prior to the vesting date, or the Measurement Price, is equal
to or greater than the Target Price. The payout for each performance
unit will be equal to: (i) one share of common stock, if the Measurement Price equals the
Target Price; (ii) a pro-rata amount between one and two shares of common stock, if the Measurement
Price is greater than the Target Price but less than the Maximum Price and (iii) two shares of
common stock, if the Measurement Price is equal to, or greater than, the Maximum Price.
24
The Target Price, Maximum Price and vesting period for each PU granted are presented in the
following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding |
|
|
|
|
|
|
|
Grant Date |
|
Vesting Period |
|
|
Shares |
|
|
Target Price |
|
|
Maximum Price |
|
|
August 1, 2005 |
|
|
3 |
|
|
|
36,300 |
|
|
$ |
54.50 |
|
|
$ |
63.75 |
|
January 3, 2006 |
|
|
3 |
|
|
|
84,500 |
|
|
$ |
67.37 |
|
|
|
79.49 |
|
February 3, 2006 |
|
|
3 |
|
|
|
52,632 |
|
|
$ |
66.41 |
|
|
|
77.67 |
|
March 1, 2006 |
|
|
3 |
|
|
|
25,000 |
|
|
$ |
61.82 |
|
|
|
72.29 |
|
May 31, 2006 |
|
|
5 |
|
|
|
4,400 |
|
|
$ |
69.90 |
|
|
|
81.74 |
|
May 31, 2006 |
|
|
3 |
|
|
|
4,400 |
|
|
$ |
69.90 |
|
|
|
81.74 |
|
August 1, 2006 |
|
|
3 |
|
|
|
1,400 |
|
|
$ |
68.27 |
|
|
|
79.83 |
|
|
The following table shows the change in the outstanding PU balance for the nine months ended
September 30, 2005 and 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average |
|
|
|
Outstanding |
|
|
Grant-Date Fair |
|
(In whole, except weighted average data) |
|
Shares |
|
|
Value Per Share |
|
|
Non-vested as of December 31, 2004 |
|
|
|
|
|
|
|
|
Granted |
|
|
45,900 |
|
|
$ |
29.87 |
|
Canceled |
|
|
|
|
|
|
|
|
|
Non-vested at September 30, 2005 |
|
|
45,900 |
|
|
|
29.87 |
|
|
Non-vested as of December 31, 2005 |
|
|
44,900 |
|
|
$ |
29.87 |
|
Granted |
|
|
180,132 |
|
|
|
35.02 |
|
Canceled |
|
|
(16,400 |
) |
|
|
32.19 |
|
|
Non-vested at September 30, 2006 |
|
|
208,632 |
|
|
$ |
34.13 |
|
|
The fair value of PUs are estimated on the date of grant using a Monte Carlo simulation
model. Volatility is calculated based on a blended average of NRG and NRGs industry peers
two-year historical stock price volatility data. The aggregate intrinsic value for PUs outstanding
as of September 30, 2005 and 2006 were approximately $2 million and $9 million, respectively.
Significant assumptions used in the fair value model during the period with respect to PUs
are summarized below:
|
|
|
|
|
Nine months ended September 30, |
|
2006 |
|
|
Weighted average annualized valuation assumptions |
|
|
|
|
Expected Volatility |
|
|
27.95% 29.64 |
% |
Weighted Average Volatility |
|
|
28.38 |
% |
Expected Dividends |
|
|
|
|
Expected Term (in years) |
|
|
3 5 |
|
Risk Free Rate |
|
|
4.30% 5.04 |
% |
Forfeiture Rate |
|
|
8 |
% |
|
Supplemental Information
The following table summarizes total compensation expense recognized in accordance with SFAS
123(R) for the nine months ended September 30, 2006 and 2005 for each of the four types of awards
issued under the LTIP including total non-vested compensation cost not yet recognized is also
presented as of September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total non-vested |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
compensation cost |
|
|
Weighted average |
|
|
|
Compensation expense |
|
|
not yet recognized |
|
|
life remaining |
|
(In millions, except weighted average data) |
|
Nine months ended September 30 |
|
|
As of September 30 |
|
Award |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2006 |
|
|
NQSOs |
|
$ |
3 |
|
|
$ |
3 |
|
|
$ |
9 |
|
|
|
1.2 |
|
DSUs |
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
RSUs |
|
|
7 |
|
|
|
5 |
|
|
|
19 |
|
|
|
1.2 |
|
PUs |
|
|
2 |
|
|
|
|
|
|
|
5 |
|
|
|
2.3 |
|
|
Total |
|
$ |
13 |
|
|
$ |
10 |
|
|
$ |
33 |
|
|
|
|
|
|
25
Note 11 Earnings Per Share
Basic earnings per common share is computed by dividing net income less accumulated preferred
stock dividends by the weighted average number of common shares outstanding. Shares issued and
treasury shares repurchased during the year are weighted for the portion of the year that they were
outstanding. Diluted earnings per share is computed in a manner consistent with that of basic
earnings per share while giving effect to all potentially dilutive common shares that were
outstanding during the period.
Dilutive effect for equity compensation The outstanding NQSOs, non-vested RSUs, DSUs and
PUs are not considered outstanding for purposes of computing basic earnings per share. However,
these instruments are included in the denominator for purposes of computing diluted earnings per
share under the treasury stock method or the if-converted method. The dilutive effect of the
potential exercise of outstanding NQSOs, non-vested RSUs and PUs are calculated using the
treasury stock method. The dilutive effects of the DSUs are included in the denominator for
purposes of computing diluted earnings per share under the if-converted method.
Dilutive effect for equity instruments NRGs outstanding 4% Preferred Stock, 3.625%
Preferred Stock and 5.75% Preferred Stock are not considered outstanding for purposes of computing
basic earnings per share. However, these instruments are considered for inclusion in the
denominator for purposes of computing diluted earnings per share under the if-converted method.
26
The reconciliation of basic earnings per common share to diluted earnings per share is shown
in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions, except per share data) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Basic earnings per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from continuing operations |
|
$ |
373 |
|
|
$ |
(37 |
) |
|
$ |
588 |
|
|
$ |
(4 |
) |
Preferred stock dividends |
|
|
(14 |
) |
|
|
(5 |
) |
|
|
(38 |
) |
|
|
(14 |
) |
|
Net income/(loss) available to common stockholders from
continuing operations |
|
|
359 |
|
|
|
(42 |
) |
|
|
550 |
|
|
|
(18 |
) |
Discontinued operations, net of income tax expense |
|
|
49 |
|
|
|
10 |
|
|
|
63 |
|
|
|
24 |
|
|
Net income/(loss) available to common stockholders |
|
$ |
408 |
|
|
$ |
(32 |
) |
|
$ |
613 |
|
|
$ |
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
136.2 |
|
|
|
83.5 |
|
|
|
130.3 |
|
|
|
85.9 |
|
Basic earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from continuing operations |
|
$ |
2.64 |
|
|
$ |
(0.51 |
) |
|
$ |
4.22 |
|
|
$ |
(0.21 |
) |
Discontinued operations, net of income tax expense |
|
|
0.36 |
|
|
|
0.12 |
|
|
|
0.48 |
|
|
|
0.28 |
|
|
Net income/(loss) |
|
$ |
3.00 |
|
|
$ |
(0.39 |
) |
|
$ |
4.70 |
|
|
$ |
0.07 |
|
|
Diluted earnings per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income/(loss) available to common stockholders from
continuing operations |
|
$ |
359 |
|
|
$ |
(42 |
) |
|
$ |
550 |
|
|
$ |
(18 |
) |
Add preferred stock dividends for dilutive preferred stock |
|
|
11 |
|
|
|
|
|
|
|
32 |
|
|
|
|
|
|
Adjusted income/(loss) from continuing operations |
|
|
370 |
|
|
|
(42 |
) |
|
|
582 |
|
|
|
(18 |
) |
Discontinued operations, net of tax |
|
|
49 |
|
|
|
10 |
|
|
|
63 |
|
|
|
24 |
|
|
Net income/(loss) available to common stockholders |
|
$ |
419 |
|
|
$ |
(32 |
) |
|
$ |
645 |
|
|
$ |
6 |
|
|
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding |
|
|
136.2 |
|
|
|
83.5 |
|
|
|
130.3 |
|
|
|
85.9 |
|
Incremental shares attributable to the issuance of
non-vested RSUs (treasury stock method) |
|
|
0.9 |
|
|
|
|
|
|
|
0.8 |
|
|
|
|
|
Incremental shares attributable to the assumed conversion
of DSUs (if-converted method) |
|
|
0.1 |
|
|
|
|
|
|
|
0.1 |
|
|
|
|
|
Incremental shares attributable to the issuance of
non-vested NQSOs (treasury stock method) |
|
|
0.5 |
|
|
|
|
|
|
|
0.5 |
|
|
|
|
|
Incremental shares attributable to the assumed conversion
of convertible preferred stock (if-converted method) |
|
|
20.8 |
|
|
|
|
|
|
|
19.6 |
|
|
|
|
|
|
Total dilutive shares |
|
|
158.5 |
|
|
|
83.5 |
|
|
|
151.3 |
|
|
|
85.9 |
|
Diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from continuing operations |
|
$ |
2.34 |
|
|
$ |
(0.51 |
) |
|
$ |
3.85 |
|
|
$ |
(0.21 |
) |
Discontinued operations, net of tax |
|
|
0.31 |
|
|
|
0.12 |
|
|
|
0.41 |
|
|
|
0.28 |
|
|
Net income/(loss) |
|
$ |
2.65 |
|
|
$ |
(0.39 |
) |
|
$ |
4.26 |
|
|
$ |
0.07 |
|
|
For the three and nine months ended September 30, 2006, options to purchase 40,364 and
620,985, respectively, of shares of common stock were not included in the computation because the
effect would have been anti-dilutive.
For the three and nine months ended September 30, 2005, none of NRGs outstanding convertible
preferred shares were included in the computation of diluted earnings per share because the effect
would have been anti-dilutive.
Note 12 Segment Reporting
NRGs identified reportable segments are primarily based on geographic areas, both domestic
and foreign. On February 2, 2006 NRG acquired Texas Genco LLC now referred to as NRG Texas creating
a new segment of operations Wholesale Power Generation Texas.
As of December 31, 2005, interest bearing intercompany debt was issued to certain subsidiaries
in the Northeast and South Central segments that resulted in increased interest expense. This
reduced the segments net income for the three and nine months ended September 30, 2006, by $15
million and $49 million for the Northeast segment and $7 million and $23 million for the South
Central segment, respectively. During the third quarter 2005, such interest expense was immaterial
to both segments.
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2006 |
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Other North |
|
|
|
|
|
|
Other |
|
|
Alternative |
|
|
Non- |
|
|
|
|
|
|
|
(In millions) |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
West |
|
|
America |
|
|
Australia |
|
|
International |
|
|
Energy |
|
|
Generation |
|
|
Other |
|
|
Total |
|
|
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
1,151 |
|
|
$ |
501 |
|
|
$ |
165 |
|
|
$ |
59 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
45 |
|
|
$ |
|
|
|
$ |
38 |
|
|
$ |
35 |
|
|
$ |
2,000 |
|
Depreciation and
amortization |
|
|
104 |
|
|
|
22 |
|
|
|
15 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
148 |
|
Equity in earnings of
unconsolidated
affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
5 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Income/(Loss) from
continuing operations
before income taxes |
|
|
480 |
|
|
|
150 |
|
|
|
24 |
|
|
|
13 |
|
|
|
(7 |
) |
|
|
6 |
|
|
|
21 |
|
|
|
(1 |
) |
|
|
2 |
|
|
|
(80 |
) |
|
|
608 |
|
Net income/(loss) from
continuing operations |
|
|
445 |
|
|
|
150 |
|
|
|
24 |
|
|
|
13 |
|
|
|
(6 |
) |
|
|
5 |
|
|
|
17 |
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
(273 |
) |
|
|
373 |
|
Net income/(loss) from
discontinued
operations, net of
income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(10 |
) |
|
|
61 |
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
49 |
|
Net income/(loss) |
|
$ |
445 |
|
|
$ |
150 |
|
|
$ |
24 |
|
|
$ |
13 |
|
|
$ |
(6 |
) |
|
$ |
(5 |
) |
|
$ |
78 |
|
|
$ |
(3 |
) |
|
$ |
(1 |
) |
|
$ |
(273 |
) |
|
$ |
422 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
12,717 |
|
|
$ |
1,583 |
|
|
$ |
895 |
|
|
$ |
201 |
|
|
$ |
222 |
|
|
$ |
180 |
|
|
$ |
1,058 |
|
|
$ |
28 |
|
|
$ |
1,591 |
|
|
$ |
1,246 |
|
|
$ |
19,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2005 |
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Other North |
|
|
|
|
|
|
Other |
|
|
Alternative |
|
|
Non- |
|
|
|
|
|
|
|
(In millions) |
|
Northeast |
|
|
Central |
|
|
West |
|
|
America |
|
|
Australia |
|
|
International |
|
|
Energy |
|
|
Generation |
|
|
Other |
|
|
Total |
|
|
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
439 |
|
|
$ |
175 |
|
|
$ |
1 |
|
|
$ |
6 |
|
|
$ |
|
|
|
$ |
41 |
|
|
$ |
|
|
|
$ |
42 |
|
|
$ |
(17 |
) |
|
$ |
687 |
|
Depreciation and amortization |
|
|
19 |
|
|
|
16 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
|
|
1 |
|
|
|
41 |
|
Equity in earnings of
unconsolidated affiliates |
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
7 |
|
|
|
6 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
29 |
|
Income/(Loss) from
continuing operations before
income taxes |
|
|
4 |
|
|
|
(8 |
) |
|
|
6 |
|
|
|
(2 |
) |
|
|
6 |
|
|
|
22 |
|
|
|
|
|
|
|
13 |
|
|
|
(68) |
|
|
|
(27 |
) |
Net income/(loss) from
continuing operations |
|
|
4 |
|
|
|
(8 |
) |
|
|
6 |
|
|
|
(2 |
) |
|
|
5 |
|
|
|
17 |
|
|
|
(1 |
) |
|
|
11 |
|
|
|
(69) |
|
|
|
(37 |
) |
Net income/(loss) from
discontinued operations, net
of income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
10 |
|
Net income/(loss) |
|
$ |
4 |
|
|
$ |
(8 |
) |
|
$ |
6 |
|
|
$ |
(3 |
) |
|
$ |
4 |
|
|
$ |
17 |
|
|
$ |
11 |
|
|
$ |
11 |
|
|
$ |
(69) |
|
|
$ |
(27 |
) |
|
28
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2006 |
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Other North |
|
|
|
|
|
|
Other |
|
|
Alternative |
|
|
Non- |
|
|
|
|
|
|
|
(In millions) |
|
Texas (a) |
|
|
Northeast |
|
|
Central |
|
|
West (b) |
|
|
America |
|
|
Australia |
|
|
International |
|
|
Energy |
|
|
Generation |
|
|
Other |
|
|
Total |
|
|
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
2,498 |
|
|
$ |
1,196 |
|
|
$ |
431 |
|
|
$ |
108 |
|
|
$ |
7 |
|
|
$ |
|
|
|
$ |
131 |
|
|
$ |
|
|
|
$ |
126 |
|
|
$ |
(18 |
) |
|
$ |
4,479 |
|
Depreciation and
amortization |
|
|
309 |
|
|
|
66 |
|
|
|
45 |
|
|
|
1 |
|
|
|
7 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
9 |
|
|
|
4 |
|
|
|
443 |
|
Equity in earnings of
unconsolidated
affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
2 |
|
|
|
17 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
46 |
|
Income/(Loss) from
continuing operations
before income taxes |
|
|
765 |
|
|
|
333 |
|
|
|
53 |
|
|
|
17 |
|
|
|
53 |
|
|
|
17 |
|
|
|
61 |
|
|
|
(1 |
) |
|
|
19 |
|
|
|
(405 |
) |
|
|
912 |
|
Net income/(loss) from
continuing operations |
|
|
719 |
|
|
|
333 |
|
|
|
53 |
|
|
|
19 |
|
|
|
53 |
|
|
|
14 |
|
|
|
47 |
|
|
|
(1 |
) |
|
|
13 |
|
|
|
(662 |
) |
|
|
588 |
|
Net income/(loss) from
discontinued
operations, net of
income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
(11 |
) |
|
|
61 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
63 |
|
Net income/(loss) |
|
$ |
719 |
|
|
$ |
333 |
|
|
$ |
53 |
|
|
$ |
19 |
|
|
$ |
62 |
|
|
$ |
3 |
|
|
$ |
108 |
|
|
$ |
3 |
|
|
$ |
13 |
|
|
$ |
(662 |
) |
|
$ |
651 |
|
|
|
|
(a) |
For the period February 2, 2006 to September 30, 2006. |
|
(b) |
Includes results of WCP for the period April 1, 2006 to September 30, 2006. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2005 |
|
|
|
Wholesale Power Generation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
Other North |
|
|
|
|
|
|
Other |
|
|
Alternative |
|
|
Non- |
|
|
|
|
|
|
|
(In millions) |
|
Northeast |
|
|
Central |
|
|
West |
|
|
America |
|
|
Australia |
|
|
International |
|
|
Energy |
|
|
Generation |
|
|
Other |
|
|
Total |
|
|
Operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
1,087 |
|
|
$ |
401 |
|
|
$ |
1 |
|
|
$ |
12 |
|
|
$ |
|
|
|
$ |
123 |
|
|
$ |
|
|
|
$ |
119 |
|
|
$ |
(20 |
) |
|
$ |
1,723 |
|
Depreciation and amortization |
|
|
56 |
|
|
|
46 |
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
8 |
|
|
|
3 |
|
|
|
121 |
|
Equity in earnings of
unconsolidated affiliates |
|
|
|
|
|
|
|
|
|
|
19 |
|
|
|
10 |
|
|
|
18 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
82 |
|
Income/(Loss) from
continuing operations before
income taxes |
|
|
76 |
|
|
|
(6 |
) |
|
|
15 |
|
|
|
(14 |
) |
|
|
18 |
|
|
|
91 |
|
|
|
(2 |
) |
|
|
21 |
|
|
|
(179 |
) |
|
|
20 |
|
Net income/(loss) from
continuing operations |
|
|
76 |
|
|
|
(6 |
) |
|
|
15 |
|
|
|
(16 |
) |
|
|
14 |
|
|
|
78 |
|
|
|
(3 |
) |
|
|
18 |
|
|
|
(180 |
) |
|
|
(4 |
) |
Net income from discontinued
operations, net of income
taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
24 |
|
Net income/(loss) |
|
$ |
76 |
|
|
$ |
(6 |
) |
|
$ |
15 |
|
|
$ |
(14 |
) |
|
$ |
18 |
|
|
$ |
78 |
|
|
$ |
15 |
|
|
$ |
18 |
|
|
$ |
(180 |
) |
|
$ |
20 |
|
|
29
Note 13 Income Taxes
Income tax expense for the three and nine months ended September 30, 2006 was $235 million and
$324 million, respectively, compared to income tax expense of $10 million and $24 million,
respectively, for the corresponding periods in 2005. The income tax expense for the nine months
ended September 30, 2006 included domestic tax expense of $307 million and foreign tax expense of
$17 million. The income tax expense for the nine months ended September 30, 2005 included domestic
tax expense of $6 million and foreign tax expense of $18 million.
A reconciliation of the U.S. statutory rate to NRGs effective tax rate from continuing
operations for the nine months ended September 30, 2006 and 2005 is as follows:
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30 |
|
(In millions except rate data) |
|
2006 |
|
|
2005 |
|
|
Income From Continuing Operations Before Income Taxes |
|
$ |
912 |
|
|
$ |
20 |
|
Tax at 35% |
|
|
319 |
|
|
|
7 |
|
State taxes |
|
|
47 |
|
|
|
(4 |
) |
Valuation allowance |
|
|
2 |
|
|
|
20 |
|
Disputed claims reserve |
|
|
(29 |
) |
|
|
|
|
Foreign operations |
|
|
(23 |
) |
|
|
(11 |
) |
Permanent differences including subpart F income |
|
|
8 |
|
|
|
12 |
|
|
Income Tax Expense |
|
$ |
324 |
|
|
$ |
24 |
|
|
Effective income tax rate |
|
|
35.5 |
% |
|
|
120.0 |
% |
|
The effective income tax rate for the nine months ended September 30, 2006 and 2005 differs
from the U.S. statutory rate of 35% due to a current tax benefit, a property basis difference
relating to disbursements from the disputed claims reserve, subpart F income and dividends, and
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 For the nine months ended September 30, 2006, NRGs domestic net
deferred tax asset decreased by $476 million resulting in a domestic net deferred tax asset of $280
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 $432 million of domestic tax assets, thus a valuation
allowance has remained, resulting in a domestic net deferred tax liability of $152 million.
As a result of the reduction in NRGs domestic net deferred tax assets, the Companys domestic
valuation allowance was also reduced. In accordance with SOP 90-7, this movement reduced
intangibles by $219 million and reduced NRGs tax expense
by $8 million for the nine months ended
September 30, 2006. As a result of losses incurred at some of NRGs foreign locations, the Company
established approximately $10 million of additional foreign valuation allowances. Therefore, as
of September 30, 2006, a valuation allowance of $508 million remained against NRGs total
domestic and foreign net deferred tax assets.
Acquisition
of NRG Texas On a preliminary basis, NRG established a deferred tax asset of
$1.575 billion and $1.560 billion of deferred tax liabilities in purchase accounting as a result of
the acquisition of NRG Texas.
NOL
carryforwards As of September 30, 2006, the Company had NOL carryforwards available for
federal income tax purposes of $271 million that will expire through 2026, including $15 million of
NOL which is eligible for carryback to prior periods.. In addition, NRG has cumulative foreign NOL
carryforwards of $270 million that do not have an expiration date.
Note 14 Benefit Plans and Other Postretirement Benefits, or OPEB
Substantially all employees hired prior to December 5, 2003 were eligible to participate in
NRGs defined benefit pension plans. NRG initiated a noncontributory, defined benefit pension plan
effective January 1, 2004, with credit for service from December 5, 2003. In addition, NRG provides
postretirement health and welfare benefits (health care and death benefits) for certain groups of
employees. Generally, these are groups that were acquired in recent years and for whom prior
benefits are being continued (at least for a certain period of time or as required by union
contracts). Cost sharing provisions vary by acquisition group and terms of any applicable
collective bargaining agreements. As of September 30, 2006, NRG had contributed $39 million of the
estimated $58 million expected to be contributed to NRGs pension plans in 2006.
30
As a result of the acquisition of NRG Texas, NRG assumed responsibility for the assets and
liabilities of the NRG Texas pension and retiree welfare plans. This pension plan is a
noncontributory defined benefit pension plan that provides cash balance benefits based on all years
of service to employees who were employed prior to January 1, 2005. In addition, employees who were
hired prior to 1999 are also eligible for grandfathered benefits under a final average pay formula.
In most cases, the benefits under the grandfathered formula will be frozen by December 31, 2008.
The NRG Texas employees are also covered under an unfunded postretirement health and welfare
plan. Each year, employees receive a fixed credit of $750 to their account plus interest. Certain
grandfathered employees will receive additional credits through 2008. At retirement, the employees
may use their accounts to purchase retiree medical and dental benefits from NRG. NRGs costs are
limited to the amounts earned in the employees account; all other costs are paid by the
participant. The net periodic pension cost relating to the NRG Texas defined benefit plan for the
three and nine months ended September 30, 2006 was $3 million and $8 million, respectively and $1
million for the nine months ended September 30, 2006 for its other postretirement benefits plans.
The net periodic expense related to NRG Texass other postretirement benefit plans for the three
months ended September 30, 2006 was immaterial. These amounts are included in the tables below.
Components of Net Periodic Benefit Cost
The components of net pension and postretirement benefit costs were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit Pension Plans |
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Service cost benefits earned |
|
$ |
4 |
|
|
$ |
2 |
|
|
$ |
13 |
|
|
$ |
8 |
|
Interest cost on benefit obligation |
|
|
4 |
|
|
|
1 |
|
|
|
12 |
|
|
|
3 |
|
Expected return on plan assets |
|
|
(2 |
) |
|
|
|
|
|
|
(5 |
) |
|
|
|
|
|
Net periodic benefit cost |
|
$ |
6 |
|
|
$ |
3 |
|
|
$ |
20 |
|
|
$ |
11 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Postretirement Benefits Plans |
|
|
|
Three months ended September 30 |
|
|
Nine months ended September 30 |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
2006 |
|
|
2005 |
|
|
Service cost benefits earned |
|
$ |
1 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
1 |
|
Interest cost on benefit obligation |
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
2 |
|
|
Net periodic benefit cost |
|
$ |
2 |
|
|
$ |
1 |
|
|
$ |
5 |
|
|
$ |
3 |
|
|
Note 15 Commitments and Contingencies
Lease Commitments
With the acquisition of Texas Genco LLC, NRGs operating lease commitments increased
significantly. This increase was primarily due to the anticipated commencement of leases for 2,695
railcars over the next two years. As of September 30, 2006, approximately 810 of the railcars had
been delivered and were under lease for future commitments of approximately $91 million, all
relating to NRG Texas.
Coal, Gas and Transportation Commitments
As a result of the acquisition of Texas Genco LLC, NRGs coal, lignite, and gas purchase and
transportation commitments have increased significantly. Future minimum payments under these
agreements relating to NRG Texas for the following years are as follows:
|
|
|
|
|
Year |
|
(In millions) |
|
|
October 1, 2006 December 31, 2006 |
|
$ |
185 |
|
2007 |
|
|
730 |
|
2008 |
|
|
715 |
|
2009 |
|
|
719 |
|
2010 |
|
|
440 |
|
Thereafter |
|
|
2,152 |
|
|
Total |
|
$ |
4,941 |
|
|
Legal Issues
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
31
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 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 affect
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. In December
2002, the district court found that federal jurisdiction was absent and remanded the cases back to
state court. On June 22, 2002, the case was again removed to Federal Court and plaintiffs filed a
motion to remand which was granted. Defendants appealed to the U.S. Court of Appeals for the Ninth
Circuit and it stayed the remand order pending its decision. On December 8, 2004, the Ninth
Circuit affirmed the district court in most respects, and on March 3, 2005, the Ninth Circuit
denied a motion for rehearing. 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. Briefs were filed by the plaintiffs on June 16,
2006, and by the defendants on August 30, 2006. 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.
On June 28, 2006, Dynegy executed a term sheet agreeing in principle to settle the class
action claims in the natural gas anti-trust cases consolidated and pending in state court in San
Diego, California. WCP and some of its subsidiaries are named defendants and Dynegys settlement
would include 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. The settlement was finalized in September
2006 and preliminarily approved by the court. It however 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.
On September 26, 2006, the plaintiffs in Jerry Egger, et all versus Dynegy Inc., et al, Case
No. 809822, Superior Court of California (filed May 1, 2003) filed a voluntary notice of dismissal.
Neither WCP and its subsidiaries nor NRG paid any defense costs as Dynegy owed and provided a
complete defense and indemnification.
32
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 by the end of 2006. Neither WCP,
it 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.
On May 17, 2006, the U.S. Bankruptcy Court for the Southern District of New York granted NRGs
motion to disallow all pre-bankruptcy claims filed against NRG related to the California energy
crisis in 2000 and 2001.
On August 2, 2006, the U.S. Court of Appeals for the Ninth Circuit in the case of Public
Utilities Commission of the State of California v. FERC, No. 01-71051 upheld in part and reversed
in part several FERC orders and remanded the case back to FERC for further proceedings consistent
with the decision. The case arose on a petition for review of a series of FERC orders wherein
California sought certain refunds for prices paid for power by consumers and businesses. NRG does
not believe it will be impacted by this decision.
FERC Proceedings
There are proceedings in which WCP and WCP subsidiaries are parties, which either are pending
before FERC or on appeal from FERC to various U.S. Courts of Appeal. These cases involve, among
other things, allegations of physical withholding, a FERC-established price mitigation plan
determining maximum rates for wholesale power transactions in certain spot markets, and the
enforceability of, and obligations under, various contracts with, among others, the CAISO, CDWR,
and the State of California. The CDWR claim involves a February 2002 complaint filed by the State
of California demanding that FERC abrogate the CDWR contract between the State and subsidiaries of
WCP and seeks refunds associated with revenues collected from CDWR by WCP. In 2003, FERC rejected
this demand and subsequently denied rehearing. The case was appealed to the U.S. Court of Appeals
for the Ninth Circuit where all briefs were filed and oral argument was held December 8, 2004.
Dynegy is indemnified by WCP and WCP is responsible for any loss associated with this CDWR
litigation unless any such loss is deemed to have resulted from Dynegys gross negligence or
willful misconduct, in which case any such loss would be shared by the parties equally.
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.
New York Public Interest Research Group
On October 24, 2005, the U.S. Court of Appeals for the Second Circuit issued its opinion in
New York Public Interest Research Group or NYPIRG v. Stephen L. Johnson; Administrator; U.S.
Environmental Protection Agency. In 2000, the NYSDEC issued a NOV to the prior owner of the Huntley
and Dunkirk stations. After an unsuccessful administrative challenge to the stations Title V air
quality permits by NYPIRG, it appealed on October 31, 2003. The Second Circuit held that, during
the Title V permitting process for the two stations, the 2000 NOV should have been sufficient for
the NYSDEC to have made a finding that the stations were out of compliance. Accordingly, the court
stated that the EPA should have objected to the Title V permits on that basis and the permits
should have included compliance schedules. All petitions for rehearing before the court were
denied. On June 3, 2005, the consent decree among NYSDEC, Niagara Mohawk Power Corporation, or
NiMo, and NRG was entered in federal court, settling the substantive issues discussed by the Second
Circuit in its decision. NYSDEC is now in the process of incorporating the consent decree
obligations into the Huntley and Dunkirk Title V permits so as to make them permit conditions, an
action NRG believes is supported by the Second Circuits decision.
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
33
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
some or all of the disputes in the action. In a companion 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. As a result, during the second quarter 2006, NRG reduced by $18 million its
reserve related to the matter. On October 23, 2006, the D.C. Circuit denied NiMos petition for
rehearing. NRG believes it is adequately reserved.
On December 14, 1999, NRG acquired certain generating facilities from CL&P. A dispute arose
over station service power and delivery services provided to the facilities. On December 20, 2002,
as a result of a petition filed at FERC by Northeast Utilities Services Company on behalf of itself
and CL&P, FERC issued an order finding that, at times when NRG is not able to self-supply its
station power needs, there is a sale of station power from a third-party and retail charges apply.
In August 2003, the parties agreed to submit the dispute to binding arbitration. In July and August
2006, the parties submitted their respective statements of the case to their appointed arbitrators.
The neutral arbitrator has yet to be selected. NRG believes it is adequately reserved.
Itiquira Energetica, S.A.
NRGs Brazilian project company, Itiquira Energetica S.A., or Itiquira, the owner of a 156 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 Itiquira in September 2002 and pertains to certain matters
arising under the EPC contract between the parties. Itiquira sought Real 140 million and asserted
that Inepar breached the contract. Inepar sought Real 39 million and alleged that Itiquira breached
the contract. On September 2, 2005, the arbitration panel ruled in favor of Itiquira, 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, Itiquiras award was increased to approximately Real 227 million
(approximately $97 million as of December 31, 2005). Itiquira 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.
CFTC Trading Litigation
On July 1, 2004, the Commodities Futures Trading Commission, or CFTC, filed a civil complaint
against NRG in Minnesota federal district court, alleging false reporting of natural gas trades
from August 2001 to May 2002, and seeking an injunction against future violations of the Commodity
Exchange Act. In May 2004, the U.S. Bankruptcy Court presiding over NRGs chapter 11 bankruptcy
reorganization expunged the CFTCs proof of claim. On March 15, 2005, NRGs motion to dismiss was
granted by the federal district court. On May 13, 2005, the CFTC filed a notice of appeal with the
U.S. Court of Appeals for the Eighth Circuit. On August 2, 2006, the court reversed the district
courts dismissal of the CFTCs action against NRG seeking a permanent injunction against future
violations of the Commodities Exchange Act. The case was remanded back to the district court for
further proceedings consistent with the decision. On November 17, 2004, a bankruptcy court hearing
was held on the CFTCs motion to reinstate its expunged bankruptcy claim, and on NRGs motion to
enforce the provisions of the NRG plan of reorganization, thereby precluding the CFTC from
continuing its federal court action. The bankruptcy court has yet to schedule a hearing or rule on
the CFTCs pending motion to reinstate its expunged claim.
Texas Asbestos Litigation
Several of NRGs plants are the subject of lawsuits, primarily commenced in 2001, against
numerous defendants by a large number of individuals who claimed personal injury due to alleged
exposure to asbestos while working at plant sites in Texas. These are premise-based claims as
distinguished from product-based claims. The overwhelming majority of these claimants are third
party contractors or sub-contractors who participated in the construction, renovation, and/or
repair of various industrial plants, including power plants. As of September 30, 2006, there were
3,386 pending claims. During the third quarter 2006, there were two claims filed, three claims
settled, and 33 claims dismissed or otherwise resolved with no payment. For the nine months ended
September 30, 2006, there were three claims filed, seven claims settled, and 222 claims dismissed
or otherwise resolved with no payment. While ultimate financial responsibility for uninsured losses
relating to asbestos claims has been assumed by NRG, CenterPoint Energy has agreed to continue to
indemnify such claims to the extent they are covered by insurance maintained by CenterPoint Energy,
subject to reimbursement of the costs of such defense from NRG. To date, costs of settlement and
defense have not been material and a portion of the payments in respect of these claims has been
offset by insurance recoveries.
34
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
October 11, 2006, the reserve held approximately $10 million in cash and approximately 692,000
shares of common stock. NRG believes the cash and stock together represent sufficient funds to
satisfy all remaining disputed claims.
Bourbonnais Agreements
On January 31, 2006, NRG finalized a stipulation and settlement agreement with an equipment
manufacturer related to turbine purchase agreements entered into in 1999 and 2001. The stipulation
fixes the amount and provides for the allowance of the equipment manufacturers proof of claim
previously filed during NRGs bankruptcy proceeding. The settlement agreement provides for a $6
million payment by NRG to the equipment manufacturer, and the release of all claims NRG Bourbonnais
and NRG have for the return of payments made under the 1999 and 2001 turbine purchase agreements.
Under the settlement agreement, NRG received certain equipment valued at $55 million as well as a
one-year option to purchase new-build equipment for a fixed price. During the first quarter 2006,
NRG recorded approximately $67 million of other income associated with the settlement due to
reversal of accounts payable totaling $35 million resulting from the discharge of the previously
recorded liability, and an adjustment to write up the value of the equipment received to its fair
value, resulting in income of approximately $32 million.
Note 16 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 level and in the regions in which NRG operates.
Texas Region
As a result of the Acquisition, NRG has become the beneficiary of decommissioning trusts that
have been established to provide funding for decontamination and decommissioning of STP in which
NRG owns a 44% interest. CenterPoint Energy Houston Electric, LLC, or CenterPoint, and American
Electric Power, or AEP, collect, through rates or other authorized charges to their electric
utility customers, amounts designated for funding NRGs portion of the decommissioning of the
facility. In the event funds from the trusts are inadequate to fund NRGs ownership portion of the
actual decommissioning costs, CenterPoint and AEP or their successors will be required to collect
through rates or other authorized charges to customers as contemplated by the Texas Utility Code
all additional amounts required to fund NRGs obligations relating to the decommissioning of the
facility. Following the completion of the decommissioning, if surplus funds remain in the
decommissioning trust, the excess will be refunded to the ratepayers of CenterPoint, AEP, or their
successors. The fair value of the trust assets are reflected as a non-current asset with an
associated long-term liability to reflect the future obligation to fund the decommissioning of the
facility from the trust assets or to refund or collect additional amounts from the ratepayers of
CenterPoint, AEP or their successors.
In addition to the nuclear decommissioning trusts, NRG has recorded asset retirement
obligations and liabilities in accordance with SFAS 143. The assets and liabilities were recorded
on the respective acquisition dates based on the estimated future costs of decontamination and
decommissioning of NRGs 44% interest in STP. The asset is being amortized over the remaining
licensing period for STP and is reflected as a component of property, plant and equipment. The
Asset Retirement Obligation, or ARO, accretion is being recognized with the associated liability.
As of September 30, 2006, the trust assets had a market value of $331 million. The unamortized
portion of the retirement obligation asset was $266 million. The decommission liability was $319
million, and the reserve to fund the decommissioning from the trust assets and payments to or from
ratepayers was $278 million. In accordance with SFAS 71, and due to the fact that NRG does not
have any economic exposure for these decommissioning responsibilities, changes in the related
assets and liabilities are not
35
reflected in the statement of operations. As such, the total carrying value of all assets and
all liabilities associated with the decommissioning and the trusts will always be equal.
Northeast Region
New
England On March 7, 2006, a broad group of New England market participants filed a
proposed settlement that 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. The FCM to be established by the
settlement will operate on an annual descending clock forward capacity auction, by which ISO-NE
will obtain the installed capacity requirement of New England, which is normally three years in
advance. For the Companys Connecticut units subject to RMR Agreements, any transition payment will
be credited against the monthly availability payment for those units, resulting in no additional
revenues for those units. NRGs other New England generation units are expected to be eligible for
the transition payments. On June 16, 2006, FERC issued an order accepting the proposed settlement.
FERC accepted revised RMR agreements for the Devon, Middleton and Montville stations on
February 1, 2006, establishing them effective January 1, 2006, and providing for the continued
operation of the stations as RMR facilities. The Devon RMR Agreement will terminate ninety days
after the commencement of the Locational Forward Reserve Market, or LFRM, but no earlier than
January 1, 2007. On May 12, 2006, FERC accepted ISO-NEs Ancillary Service Market Phase II package
that includes the LFRM, granting the requested effective date of October 1, 2006, and thus
triggering the termination of the Devon RMR Agreement effective January 1, 2007. On October 5,
2006, FERC accepted proposed revisions to the Devon RMR Agreement
clarifying that, should the Devon
units participate in the LFRM; the units will have to comply with the requirements of that market.
Unless terminated earlier, the Middletown and Montville RMR agreements are expected to terminate
upon the commencement of the FCM.
On February 15, 2006, NRG reported to FERC and to ISO-NE that for two days in January 2006,
after unit 12 at the Devon station had been removed from service for needed maintenance, it was
erroneously reported to ISO-NE as available. NRG further reported that when ISO-NE dispatched the
Devon units on January 25, 2006, and unit 12 was unable to respond, inaccurate information was
provided to ISO-NE. On March 28, 2006, NRG was advised by FERC that it had commenced a preliminary,
non-public, informal investigation into the January 25, 2006, ISO-NE dispatch. That same day, FERC
also issued to NRG a data request. On April 24, 2006, NRG submitted to FERC an initial response to
the data request and made additional submissions during the second and third quarters of 2006. On
June 21, 2006, and on October 5, 2006, NRG received supplemental data requests from FERC to which
NRG has responded. NRG continues to investigate the matter and is cooperating with FERC and ISO-NE.
The outcome of this investigation cannot be predicted at this time.
On October 11, 2006, FERC denied the complaint filed on September 12, 2005 by Richard
Blumenthal, Attorney General for the State of Connecticut against ISO-NE that sought to amend the
ISO-NEs market rules to require all electric generation facilities not currently operating under
an RMR agreement in Connecticut to be placed under cost-of-service rates.
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 on November 17, 2005. These orders have subsequently been
appealed to the D.C. Circuit which has already issued a briefing order. Resettlement of the market,
while viewed as unlikely could have a material financial impact.
On April 19, 2006, a settlement was reached with respect to high prices in the NYISO energy
market on May 8 and 9, 2000. At issue were material amounts paid to NRG for power delivered on
those dates. As a result of the settlement, NRG will retain the amounts paid to it in 2005 and
received additional non-material amounts. The settlement was filed with FERC on May 25, 2006 and on
July 12, 2006, FERC issued an order accepting the proposed settlement.
On March 15, 2006, NRG received the results from NYISO Market Monitoring Units review of
NRGs Astoria plants 2004 Generating Availability Data System reporting. This audit may result in
the resettlement of NRGs capacity revenues from the Astoria facility due to a redetermination of
the amount of available capacity. NRG is currently in settlement discussions with the NYISO, and
has established a reserve.
West Region
On October 11, 2006, the Nevada Public Utilities Commission, or NPUC, dismissed the Petition
for Declaratory Order filed on August 18, 2006, by Nevada Power Company, or NPC, regarding its
contract with Saguaro Power, which owns a cogeneration facility
36
in Henderson, Nevada. The Saguaro facility is a Qualifying Facility and sells energy and
capacity to NPC pursuant to a long-term contract in accordance with the Public Utility Regulatory
Policy Act of 1978. In the petition, NPC sought, among other things, to modify certain provisions
of the contract, or in the alternative, terminate the contract which would have harmed the
materially affected project financially.
Note 17 Environmental Matters
The construction and operation of power projects are subject to stringent environmental,
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 extensive modifications to further
reduce potential environmental impacts. In general, the effect of future laws or regulations is
expected to require the addition of pollution control equipment or the imposition of restrictions
on the Companys operations.
Environmental Capital Expenditures
NRG has estimated that approximately $1.3 billion of environmental capital expenditures will
be incurred during the period 2007 through 2012 in order to keep NRGs facilities in compliance
with environmental laws, primarily related to installation of particulate, SO2,
NOX, and mercury controls to comply with CAIR and Clean Air Mercury rules, as
well as installation of BTA under the Phase II 316(b) Rule. NRG updates its expected environmental
retrofit plan and associated 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.
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 the 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 joint and several liabilities. The cost
of investigation, remediation or removal of any hazardous or toxic substances or petroleum products
could be substantial.
Northeast Region
Remedial obligations at the Arthur Kill generating station have been established in
discussions between NRG and the NYSDEC and are estimated to be approximately $2 million. Remedial
investigations continue at the Astoria generating station with long-term clean-up liability
expected to be also approximately $2 million. NRG may be required to remediate historical coal tar
contamination and record a deed restriction on the Astoria property if significant contamination is
to remain in place. NRG will implement a remedial action plan over the next eight years to address
historical ash contamination at other facilities in the Northeast region. The total estimated cost
at these facilities is not expected to exceed $2 million.
As a result of a small 2001 underground fuel line leak at the Companys Vienna Generating
Station, NRG submitted a plan for remediation to the Maryland Department of the Environment, or
MDE. The MDE has not formally responded. The remediation in connection with this matter is not
expected to materially impact NRGs financial results.
In January 2006, NRG Indian River Operations, Inc. received a letter of informal notification
from Delaware Department of Natural Resources and Environmental Control, or DNREC, stating that it
may be a potentially responsible party with respect to a historic captive landfill. NRG is working
with the DNREC, through the Voluntary Clean-up Program, to investigate the site. The Company is
unable to predict the financial impact at this time.
South Central Region
On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request under
Section 114 of the CAA from USEPA seeking information primarily related to physical changes made at
Big Cajun II and subsequently received a notice of violation, or NOV, based on alleged NSR
violations. NRG submitted multiple responses commencing on February 27, 2004 through 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 Louisiana Generating, LLCs offices by the DOJ during the week of August 14, 2006.
Following the review, Louisiana Generating, LLC has forwarded requested copies of certain documents to
the DOJ.
37
West Region
The Asset Purchase Agreements under which NRG acquired the Long Beach, El Segundo, Encina, and
San Diego gas turbine generating facilities provide that Southern California Edison, or SCE, and
San Diego Gas & Electric, or SDG&E, as sellers retain liability, and indemnify NRG for existing
soil and groundwater contamination that exceeds remedial thresholds in place at the time of
closing. Having identified existing contamination, SDG&E has agreed to address contamination and is
undertaking corrective action at the Encina and San Diego plant sites.
NRG remediated contamination from a 2002 oil leak at the El Segundo Generating Station.
Contaminated soils beneath the foundation were left in place, with approval from the Los Angeles
Regional Water Quality Control Board, for removal when the building is demolished.
As part of decommissioning the 32nd Street Naval Station combustion turbine facility in San
Diego, investigation and remediation of contaminated soils in inaccessible areas may be required in
the future. Although NRG is unable to predict the exact financial impact at this time, NRG believes
the cost to remediate will not be material.
Note 18 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 purchase and sale agreements, commodity sale and purchase agreements, joint
venture agreements, operations 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 many cases, NRGs maximum potential liability cannot be estimated, since some of the
underlying agreements contain no limits on potential liability.
Below are the descriptions of material guarantees and should be read in conjunction with the
complete descriptions under Note 29 Guarantees and Other Contingent Liabilities in NRGs Form 10-K
for the fiscal year ended December 31, 2005.
On August 30, 2006, with the completion of the sale of Flinders, NRG guaranteed the payment
and performance of the Flinders subsidiaries obligations under the sale and purchase agreement.
Maximum liability of NRG is limited to the sale price of AU$317 million. In addition, with the
completion of the sale, existing guarantees and indemnities of NRG related to Flinders were
released.
With the acquisition of Texas Genco LLC, NRG assumed several guarantee obligations relating to
Texas Genco LLCs entities. Under these guarantees, NRG has guaranteed the payment obligations of
NRG Texas LP, formerly known as Texas Genco II LP, under commercial agreements to various parties.
Maximum obligations under these guarantees as of September 30,
2006 were approximately $35 million.
On June 1, 2006, NRG, through its wholly-owned entities NRG Caymans C and NRG Caymans P
entered into an agreement to sell its investments in Latin America Power entities to a subsidiary
of Australia Post. The agreement includes an indemnity from the companies relating to costs
incurred by the buyer for breach of representations, warranties or covenants contained in the sale
agreement. Liability for these companies is capped at approximately $23 million. No claim for a
breach of representations or warranties can be brought after March 31, 2007.
On March 31, 2006, NRG purchased the remaining 50% interest in WCP from Dynegy. In conjunction
with the purchase, NRG agreed to indemnify Dynegy, subject to certain caps and limitations, for
breach of representations, warranties, covenants, and losses incurred under the CDWR litigation and
certain California electricity-related litigation. For further information about the litigation,
see Note 15.
On March 28, 2006, NRG executed a guarantee to the benefit of AmerenUE, the purchaser of NRGs
Audrain generating assets. Pursuant to this agreement, NRG guaranteed the payment and performance
of the Company and its subsidiaries obligations pursuant to the sale agreement. This guarantee
extends to certain claims made within five years of the sale and the Companys maximum exposure
under this guarantee is $10 million. In addition to this guarantee, NRG received a $2.75 million
payment from the project lenders in consideration for retaining certain pre-closing tax liabilities
related to the Audrain project. This payment was recorded within other non-current liabilities on
NRGs consolidated balance sheet. In consideration for this payment, NRG agreed to indemnify the
project lenders, subject to a $10 million cap for liabilities related to the pre-closing taxes
applicable to the Audrain project.
In 2006, NRG executed a guarantee to the benefit each of two counterparties under the railcar
lease described in Note 15. These guarantees cover payment and performance
obligations of the Companys wholly-owned subsidiary, NRG Texas LP, under the relevant lease
documents. NRG does not believe that it will be required to perform under this indemnity.
For the nine months ended September 30, 2006, NRG had net increases to its guarantee
obligations under other commercial arrangements of approximately $463 million. These pertain to
payment obligations of NRG Power Marketing Inc., or PMI.
38
Because many of the guarantees and indemnities NRG issues to third parties do not limit the
amount or duration of the Companys obligations to perform under them, there exists a risk that NRG
may have obligations in excess of the amounts described above. For those guarantees and indemnities
that do not limit NRGs liability exposure, NRG may not be able to estimate what the Companys
liability would be until a claim is made for payment or performance, due to the contingent nature
of these contracts.
Note 19 Subsequent Event
On November 3, 2006, NRG announced its intention to enter into a series of transactions that
includes (i) the reset of existing out-of-the-money hedges for years 2006 through 2010 to market, (ii)
substantial new baseload hedges for the years 2010 and 2011 and, possibly, later years, (iii) the
issuance of $1.1 billion of new high yield notes, and (iv) amendments to NRGs Senior
Credit Facility, including the increase of the synthetic letter of credit facility by $500 million.
Resetting of Existing Hedges, or Hedge Reset NRG has entered into amendments of certain
existing hedge agreements for the years 2006 through 2010, including
hedge agreements with J.Aron
& Company. These hedges were gas swaps and power contracts that were acquired as part of the
acquisition of Texas Genco LLC, which closed on February 2, 2006. These hedges were entered into by
Texas Genco at a time when power and natural gas prices were lower than they are today, and as
a result, the hedges obligate NRG to sell power or natural gas at prices significantly below
current market prices. Under the amended agreements, NRG has reset the pricing of these hedges to
reflect current market prices, and has agreed to pay cash to the hedge counterparties in amounts
that reflect a negotiated present value of the difference between the original prices in the hedges
and the amended prices. The total amount to be paid to the counterparties is expected to be
approximately $1.35 billion.
The
Hedge Reset will provide the flexibility through NRGs
second lien structure to expand its hedges on baseload generation for an
extended period, and will improve the Companys cash flows and credit profile which will contribute to the
Companys ability to amend its existing senior credit facility.
New
Hedges NRG has entered into, and will continue to enter
into, new forward natural gas
swaps contracts for the years 2010 and 2011, in order to hedge future power prices with respect to
NRGs baseload power generation facilities in those years. As appropriate market opportunities
arise, NRG will extend the hedging program to later years. As a result of these transactions, NRG
will be significantly more hedged with respect to its baseload power
generation through 2011. NRGs obligations under the New Hedges
and Hedge Reset are or will be
secured by second liens on substantially all of the assets of NRG and its subsidiaries, pursuant to
NRGs existing second lien structure.
Issuance of New High Yield Notes NRG plans to finance the payments required in order to
reset the existing hedges with cash on hand and with proceeds from the issuance of $1.1 billion of
new high yield notes.
Amendment of Senior Credit Facility
NRG plans to amend its existing Senior Credit Facility
to accomplish, among other things, the following objectives:
|
|
|
to permit the incurrence of the new debt represented by the new high yield notes; |
|
|
|
|
to increase the amount of the synthetic letter of credit facility by $500 million, from $1.0 billion to $1.5 billion; |
|
|
|
|
to increase the Available Amount, and effect a corresponding increase in NRG's restricted payments capacity, by $250 million; and |
|
|
|
|
to provide additional flexibility to NRG with respect to certain covenants governing or
restricting the use of excess cash flow, new investments, new indebtedness and permitted
liens. |
The amendments to the existing hedges, the issuance of the new high yield notes, and the
amendments to the Senior Credit Facility are expected to close by November 21, 2006. NRG has
entered into bridge agreements with Merrill Lynch & Co. to assure that it has adequate financing to
fund the amounts owed to the hedge counterparties, and Merrill Lynch & Co. has issued a commitment
to NRG to refinance its Senior Secured Credit Facility if the desired amendments to the existing
facilities cannot be procured.
Impact
to Results of Operations NRG will account for the Hedge Reset as a net settlement of
its current hedge positions and a subsequent reestablishment of new hedge positions. The impact of
the net settlement will be recorded as a decrease to NRGs consolidated revenues with an offsetting
increase in revenues from a reduction in the associated derivative liability and the associated
out-of-market power contract balance established upon the Acquisition of NRG Texas.
39
Note 20 Condensed Consolidating Financial Information
As of September 30, 2006, the Company had $1.2 billion of 7.25% Senior Notes and $2.4 billion
of 7.375% Senior Notes outstanding. These notes are guaranteed by certain of NRGs current and
future wholly-owned domestic subsidiaries, or guarantor subsidiaries. Each of the following
guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of September 30,
2006.
|
|
|
Arthur Kill Power LLC
|
|
NRG California Peaker Operations LLC |
Astoria Gas Turbine Power LLC
|
|
NRG Texas LP |
Berrians I Gas Turbine Power LLC
|
|
NRG Texas LLC |
Big Cajun II Unit 4 LLC
|
|
NRG Connecticut Affiliate Services Inc. |
Cabrillo Power I LLC
|
|
NRG Devon Operations Inc. |
Cabrillo Power II LLC
|
|
NRG Dunkirk Operations Inc. |
Chickahominy River Energy Corp.
|
|
NRG El Segundo Operations Inc. |
Commonwealth Atlantic Power LLC
|
|
NRG Huntley Operations Inc. |
Conemaugh Power LLC
|
|
NRG International LLC |
Connecticut Jet Power LLC
|
|
NRG Kaufman LLC |
Devon Power LLC
|
|
NRG Mid Atlantic Affiliate Services Inc. |
Dunkirk Power LLC
|
|
NRG Mesquite LLC |
Eastern Sierra Energy Company
|
|
NRG Middletown Operations Inc. |
El Segundo Power LLC
|
|
NRG Montville Operations Inc. |
El Segundo Power II LLC
|
|
NRG New Jersey Energy Sales LLC |
GCP Funding Company, LLC
|
|
NRG New Roads Holdings LLC |
Hanover Energy Company
|
|
NRG North Central Operations Inc. |
Huntley Power LLC
|
|
NRG Northeast Affiliate Services Inc. |
Indian River Operations Inc.
|
|
NRG Norwalk Harbor Operations Inc. |
Indian River Power LLC
|
|
NRG Operating Services, Inc. |
James River Power LLC
|
|
NRG Oswego Harbor Power Operations Inc. |
Kaufman Cogen LP
|
|
NRG Power Marketing Inc |
Keystone Power LLC
|
|
NRG Rocky Road LLC |
Long Beach Generation LLC
|
|
NRG Saguaro Operations Inc. |
Louisiana Generating LLC
|
|
NRG South Central Affiliate Services Inc. |
Middletown Power LLC
|
|
NRG South Central Generating LLC |
Montville Power LLC
|
|
NRG South Central Operations Inc. |
NEO California Power LLC
|
|
NRG South Texas LP |
NEO Chester-Gen LLC
|
|
NRG West Coast LLC |
NEO Corporation
|
|
NRG Western Affiliate Services Inc. |
NEO Freehold-Gen LLC
|
|
Oswego Harbor Power LLC |
NEO Landfill Gas Holdings Inc.
|
|
Saguaro Power LLC |
NEO Power Services Inc.
|
|
Somerset Operations Inc. |
New Genco GP, LLC
|
|
Somerset Power LLC |
New Genco LP, LLC
|
|
Texas Genco Financing Corp. |
Norwalk Power LLC
|
|
Texas Genco GP, LLC |
NRG Affiliate Services Inc.
|
|
Texas Genco Holdings, Inc. |
NRG Arthur Kill Operations Inc.
|
|
Texas Genco LP, LLC |
NRG Asia-Pacific, Ltd.
|
|
Texas Genco Operating Services, LLC |
NRG Astoria Gas Turbine Operations Inc.
|
|
Texas Genco Services, LP |
NRG Bayou Cove LLC
|
|
Vienna Operations Inc. |
NRG Generation Holdings, Inc.
|
|
Vienna Power LLC |
NRG Cabrillo Power Operations Inc.
|
|
WCP (Generation) Holdings LLC |
NRG Cadillac Operations Inc.
|
|
West Coast Power LLC |
The non-guarantor subsidiaries include all of NRGs foreign subsidiaries and certain domestic
subsidiaries. NRG conducts much of its business through and derives much of its income from its
subsidiaries. Therefore, the Companys ability to make required payments with respect to its
indebtedness and other obligations depends on the financial results and condition of its
subsidiaries and NRGs ability to receive funds from its subsidiaries. Except for NRG Bayou Cove,
LLC, which is subject to certain restrictions under the
40
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.
41
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Three Months Ended September 30, 2006
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from majority-owned operations |
|
$ |
1,903 |
|
|
$ |
96 |
|
|
$ |
1 |
|
|
$ |
|
|
|
$ |
2,000 |
|
|
Operating Costs and Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
995 |
|
|
|
63 |
|
|
|
(3 |
) |
|
|
|
|
|
|
1,055 |
|
Depreciation and amortization |
|
|
141 |
|
|
|
6 |
|
|
|
1 |
|
|
|
|
|
|
|
148 |
|
General, administrative and development |
|
|
26 |
|
|
|
4 |
|
|
|
49 |
|
|
|
|
|
|
|
79 |
|
|
Total operating costs and expenses |
|
|
1,162 |
|
|
|
73 |
|
|
|
47 |
|
|
|
|
|
|
|
1,282 |
|
|
Operating Income/(Loss) |
|
|
741 |
|
|
|
23 |
|
|
|
(46 |
) |
|
|
|
|
|
|
718 |
|
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
94 |
|
|
|
|
|
|
|
480 |
|
|
|
(574 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
2 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Write downs and losses on sales of equity method
investments |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Other income, net |
|
|
(12 |
) |
|
|
17 |
|
|
|
36 |
|
|
|
(11 |
) |
|
|
30 |
|
Interest expense |
|
|
(33 |
) |
|
|
(22 |
) |
|
|
(110 |
) |
|
|
11 |
|
|
|
(154 |
) |
|
Total other income/(expense) |
|
|
49 |
|
|
|
9 |
|
|
|
406 |
|
|
|
(574 |
) |
|
|
(110 |
) |
|
Income/(Loss) From Continuing Operations Before Income
Taxes |
|
|
790 |
|
|
|
32 |
|
|
|
360 |
|
|
|
(574 |
) |
|
|
608 |
|
Income tax expense/(benefit) |
|
|
289 |
|
|
|
10 |
|
|
|
(64 |
) |
|
|
|
|
|
|
235 |
|
|
Income From Continuing Operations |
|
|
501 |
|
|
|
22 |
|
|
|
424 |
|
|
|
(574 |
) |
|
|
373 |
|
Income/(losses) from discontinued operations, net of
income tax expense (benefit) |
|
|
|
|
|
|
51 |
|
|
|
(2 |
) |
|
|
|
|
|
|
49 |
|
|
Net Income |
|
$ |
501 |
|
|
$ |
73 |
|
|
$ |
422 |
|
|
$ |
(574 |
) |
|
$ |
422 |
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
42
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Nine Months Ended September 30, 2006
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from majority-owned operations |
|
$ |
4,218 |
|
|
$ |
261 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
4,479 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
2,298 |
|
|
|
178 |
|
|
|
2 |
|
|
|
|
|
|
|
2,478 |
|
Depreciation and amortization |
|
|
420 |
|
|
|
19 |
|
|
|
4 |
|
|
|
|
|
|
|
443 |
|
General, administrative and development |
|
|
73 |
|
|
|
11 |
|
|
|
136 |
|
|
|
|
|
|
|
220 |
|
|
Total operating costs and expenses |
|
|
2,791 |
|
|
|
208 |
|
|
|
142 |
|
|
|
|
|
|
|
3,141 |
|
|
Operating Income/(Loss) |
|
|
1,427 |
|
|
|
53 |
|
|
|
(142 |
) |
|
|
|
|
|
|
1,338 |
|
|
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
130 |
|
|
|
|
|
|
|
911 |
|
|
|
(1,041 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
3 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
46 |
|
Write downs and gains/(losses) on sales of equity
method investments |
|
|
(5 |
) |
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
8 |
|
Other income, net |
|
|
14 |
|
|
|
93 |
|
|
|
26 |
|
|
|
(15 |
) |
|
|
118 |
|
Refinancing expense |
|
|
|
|
|
|
|
|
|
|
(178 |
) |
|
|
|
|
|
|
(178 |
) |
Interest expense |
|
|
(170 |
) |
|
|
(47 |
) |
|
|
(218 |
) |
|
|
15 |
|
|
|
(420 |
) |
|
Total other income/(expense) |
|
|
(28 |
) |
|
|
102 |
|
|
|
541 |
|
|
|
(1,041 |
) |
|
|
(426 |
) |
|
Income/(Loss) From Continuing Operations Before Income
Taxes |
|
|
1,399 |
|
|
|
155 |
|
|
|
399 |
|
|
|
(1,041 |
) |
|
|
912 |
|
Income tax
expense/(benefit) |
|
|
530 |
|
|
|
44 |
|
|
|
(250 |
) |
|
|
|
|
|
|
324 |
|
|
Income From Continuing Operations |
|
|
869 |
|
|
|
111 |
|
|
|
649 |
|
|
|
(1,041 |
) |
|
|
588 |
|
Income from discontinued operations, net of
income tax expense |
|
|
|
|
|
|
61 |
|
|
|
2 |
|
|
|
|
|
|
|
63 |
|
|
Net Income |
|
$ |
869 |
|
|
$ |
172 |
|
|
$ |
651 |
|
|
$ |
(1,041 |
) |
|
$ |
651 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
43
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet
September 30, 2006
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy Inc. |
|
|
Eliminations(a) |
|
|
Balance |
|
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
36 |
|
|
$ |
388 |
|
|
$ |
964 |
|
|
$ |
|
|
|
$ |
1,388 |
|
Restricted cash |
|
|
1 |
|
|
|
73 |
|
|
|
|
|
|
|
|
|
|
|
74 |
|
Accounts receivable-trade, net |
|
|
398 |
|
|
|
37 |
|
|
|
(2 |
) |
|
|
|
|
|
|
433 |
|
Inventory |
|
|
385 |
|
|
|
12 |
|
|
|
|
|
|
|
|
|
|
|
397 |
|
Deferred income taxes |
|
|
183 |
|
|
|
(20 |
) |
|
|
(104 |
) |
|
|
|
|
|
|
59 |
|
Derivative instruments valuation |
|
|
956 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
961 |
|
Collateral on deposit in support of energy
risk management activities |
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132 |
|
Prepayments and other current assets |
|
|
89 |
|
|
|
38 |
|
|
|
737 |
|
|
|
(650 |
) |
|
|
214 |
|
Current assets discontinued operations |
|
|
|
|
|
|
2 |
|
|
|
11 |
|
|
|
|
|
|
|
13 |
|
|
Total current assets |
|
|
2,180 |
|
|
|
535 |
|
|
|
1,606 |
|
|
|
(650 |
) |
|
|
3,671 |
|
|
Net property, plant and equipment |
|
|
11,264 |
|
|
|
406 |
|
|
|
16 |
|
|
|
|
|
|
|
11,686 |
|
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
712 |
|
|
|
|
|
|
|
9,451 |
|
|
|
(10,163 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
32 |
|
|
|
287 |
|
|
|
|
|
|
|
|
|
|
|
319 |
|
Notes receivable, less current portion |
|
|
998 |
|
|
|
468 |
|
|
|
4,460 |
|
|
|
(5,458 |
) |
|
|
468 |
|
Goodwill |
|
|
1,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,547 |
|
Intangible assets, net |
|
|
994 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
1,001 |
|
Intangible assets held-for-sale |
|
|
53 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
53 |
|
Nuclear decommissioning trust fund |
|
|
331 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
331 |
|
Derivative instruments valuation |
|
|
346 |
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
360 |
|
Deferred income taxes |
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
27 |
|
Other non-current assets |
|
|
24 |
|
|
|
58 |
|
|
|
162 |
|
|
|
|
|
|
|
244 |
|
Non-current assets discontinued operations |
|
|
|
|
|
|
1 |
|
|
|
13 |
|
|
|
|
|
|
|
14 |
|
|
Total other assets |
|
|
5,037 |
|
|
|
848 |
|
|
|
14,100 |
|
|
|
(15,621 |
) |
|
|
4,364 |
|
|
Total Assets |
|
$ |
18,481 |
|
|
$ |
1,789 |
|
|
$ |
15,722 |
|
|
$ |
(16,271 |
) |
|
$ |
19,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital leases |
|
$ |
460 |
|
|
$ |
93 |
|
|
$ |
38 |
|
|
$ |
(468 |
) |
|
$ |
123 |
|
Accounts payable |
|
|
(988 |
) |
|
|
263 |
|
|
|
1,003 |
|
|
|
|
|
|
|
278 |
|
Deferred income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative instruments valuation |
|
|
901 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
901 |
|
Accrued expenses and other current liabilities |
|
|
494 |
|
|
|
63 |
|
|
|
110 |
|
|
|
(182 |
) |
|
|
485 |
|
Current liabilities discontinued operations |
|
|
|
|
|
|
3 |
|
|
|
5 |
|
|
|
|
|
|
|
8 |
|
|
Total current liabilities |
|
|
867 |
|
|
|
422 |
|
|
|
1,156 |
|
|
|
(650 |
) |
|
|
1,795 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
4,460 |
|
|
|
752 |
|
|
|
8,072 |
|
|
|
(5,458 |
) |
|
|
7,826 |
|
Nuclear decommissioning reserve |
|
|
278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
278 |
|
Nuclear decommissioning trust liability |
|
|
319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
319 |
|
Deferred income taxes |
|
|
240 |
|
|
|
(79 |
) |
|
|
201 |
|
|
|
|
|
|
|
362 |
|
Derivative instruments valuation |
|
|
342 |
|
|
|
6 |
|
|
|
21 |
|
|
|
|
|
|
|
369 |
|
Out-of-market contracts |
|
|
2,128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,128 |
|
Other non-current liabilities |
|
|
346 |
|
|
|
25 |
|
|
|
15 |
|
|
|
|
|
|
|
386 |
|
Non-current liabilities discontinued operations |
|
|
|
|
|
|
|
|
|
|
5 |
|
|
|
|
|
|
|
5 |
|
|
Total non-current liabilities |
|
|
8,113 |
|
|
|
704 |
|
|
|
8,314 |
|
|
|
(5,458 |
) |
|
|
11,673 |
|
|
Total liabilities |
|
|
8,980 |
|
|
|
1,126 |
|
|
|
9,470 |
|
|
|
(6,108 |
) |
|
|
13,468 |
|
|
Minority interest |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
247 |
|
Stockholders Equity |
|
|
9,501 |
|
|
|
662 |
|
|
|
6,005 |
|
|
|
(10,163 |
) |
|
|
6,005 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
18,481 |
|
|
$ |
1,789 |
|
|
$ |
15,722 |
|
|
$ |
(16,271 |
) |
|
$ |
19,721 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
44
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Cash Flows
For the Nine Months Ended September 30, 2006
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
869 |
|
|
$ |
172 |
|
|
$ |
651 |
|
|
$ |
(1,041 |
) |
|
$ |
651 |
|
Adjustments
to reconcile net income to net cash provided/(used)
by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions in excess of (less than) equity in earnings
of unconsolidated affiliates and consolidated subsidiaries |
|
|
(133 |
) |
|
|
(24 |
) |
|
|
(911 |
) |
|
|
1,041 |
|
|
|
(27 |
) |
Depreciation and amortization of nuclear fuel |
|
|
453 |
|
|
|
30 |
|
|
|
7 |
|
|
|
|
|
|
|
490 |
|
Amortization of financing costs and debt discounts |
|
|
|
|
|
|
5 |
|
|
|
19 |
|
|
|
|
|
|
|
24 |
|
Amortization of intangibles and out-of-market contracts |
|
|
(390 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
(393 |
) |
Amortization of unearned equity compensation |
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
|
|
|
|
13 |
|
Write-off of deferred financing costs and debt premium |
|
|
|
|
|
|
|
|
|
|
47 |
|
|
|
|
|
|
|
47 |
|
Write down
and (gains)/losses of equity method
investments |
|
|
5 |
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
(8 |
) |
Changes in deferred income taxes |
|
|
430 |
|
|
|
25 |
|
|
|
(146 |
) |
|
|
|
|
|
|
309 |
|
Nuclear decommissioning trust liability |
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Loss on sale of equipment |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Changes in derivatives |
|
|
(308 |
) |
|
|
1 |
|
|
|
6 |
|
|
|
|
|
|
|
(301 |
) |
Gain on legal settlement |
|
|
|
|
|
|
(67 |
) |
|
|
|
|
|
|
|
|
|
|
(67 |
) |
Gain on sale of discontinued operations |
|
|
|
|
|
|
(71 |
) |
|
|
|
|
|
|
|
|
|
|
(71 |
) |
Gain on sale of emission allowances |
|
|
(68 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(68 |
) |
Changes in collateral deposit payments supporting of
energy risk management activities |
|
|
349 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
349 |
|
Cash provided/(used) by changes in working capital, net of
acquisition and disposition affects |
|
|
(494 |
) |
|
|
129 |
|
|
|
453 |
|
|
|
|
|
|
|
88 |
|
|
Net Cash Provided by Operating Activities |
|
|
725 |
|
|
|
184 |
|
|
|
139 |
|
|
|
|
|
|
|
1,048 |
|
|
Cash Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Texas Genco LLC, WCP and Padoma, net of cash
acquired |
|
|
|
|
|
|
|
|
|
|
(4,336 |
) |
|
|
|
|
|
|
(4,336 |
) |
Capital expenditures |
|
|
(140 |
) |
|
|
(17 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
(159 |
) |
Decrease/(Increase) in restricted cash, net |
|
|
2 |
|
|
|
(26 |
) |
|
|
|
|
|
|
|
|
|
|
(24 |
) |
Decrease/(Increase) in notes receivable |
|
|
(922 |
) |
|
|
22 |
|
|
|
(3,063 |
) |
|
|
3,985 |
|
|
|
22 |
|
Purchases of emission allowances |
|
|
(76 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(76 |
) |
Proceeds from sale of emission allowances |
|
|
97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97 |
|
Investments in nuclear decommissioning trust fund securities |
|
|
(158 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(158 |
) |
Proceeds from sales of nuclear decommissioning trust fund
securities |
|
|
149 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
149 |
|
Proceeds from sale of equipment |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Proceeds from sale of investments |
|
|
53 |
|
|
|
33 |
|
|
|
|
|
|
|
|
|
|
|
86 |
|
Proceeds from sale of discontinued operations |
|
|
|
|
|
|
239 |
|
|
|
|
|
|
|
|
|
|
|
239 |
|
|
Net Cash Provided/(Used) by Investing Activities |
|
|
(994 |
) |
|
|
251 |
|
|
|
(7,401 |
) |
|
|
3,985 |
|
|
|
(4,159 |
) |
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payment of dividends to preferred stockholders |
|
|
|
|
|
|
|
|
|
|
(37 |
) |
|
|
|
|
|
|
(37 |
) |
Payment for treasury stock |
|
|
|
|
|
|
(297 |
) |
|
|
|
|
|
|
|
|
|
|
(297 |
) |
Funded letter of credit |
|
|
|
|
|
|
|
|
|
|
350 |
|
|
|
|
|
|
|
350 |
|
Proceeds from Intercompany loans |
|
|
3,063 |
|
|
|
|
|
|
|
922 |
|
|
|
(3,985 |
) |
|
|
|
|
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 |
|
|
|
|
|
|
198 |
|
|
|
7,175 |
|
|
|
|
|
|
|
7,373 |
|
Payment of deferred debt issuance costs |
|
|
|
|
|
|
|
|
|
|
(174 |
) |
|
|
|
|
|
|
(174 |
) |
Payments of short and long-term debt |
|
|
(2,751 |
) |
|
|
(42 |
) |
|
|
(1,904 |
) |
|
|
|
|
|
|
(4,697 |
) |
|
Net Cash
Provided/(Used) by Financing Activities |
|
|
312 |
|
|
|
(141 |
) |
|
|
7,804 |
|
|
|
(3,985 |
) |
|
|
3,990 |
|
Change in Cash from Discontinued Operations |
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
14 |
|
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
Net Increase in Cash and Cash
Equivalents |
|
|
43 |
|
|
|
310 |
|
|
|
542 |
|
|
|
|
|
|
|
895 |
|
Cash and Cash Equivalents at Beginning of Period |
|
|
(7 |
) |
|
|
78 |
|
|
|
422 |
|
|
|
|
|
|
|
493 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
36 |
|
|
$ |
388 |
|
|
$ |
964 |
|
|
$ |
|
|
|
$ |
1,388 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
45
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Three Months Ended September 30, 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from majority-owned operations |
|
$ |
594 |
|
|
$ |
93 |
|
|
$ |
1 |
|
|
$ |
(1 |
) |
|
$ |
687 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
541 |
|
|
|
64 |
|
|
|
|
|
|
|
(1 |
) |
|
|
604 |
|
Depreciation and amortization |
|
|
33 |
|
|
|
6 |
|
|
|
2 |
|
|
|
|
|
|
|
41 |
|
General, administrative and development |
|
|
7 |
|
|
|
7 |
|
|
|
28 |
|
|
|
|
|
|
|
42 |
|
Impairment charges |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Corporate relocation charges |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
Total operating costs and expenses |
|
|
587 |
|
|
|
77 |
|
|
|
32 |
|
|
|
(1 |
) |
|
|
695 |
|
|
Operating Income/(Loss) |
|
|
7 |
|
|
|
16 |
|
|
|
(31 |
) |
|
|
|
|
|
|
(8 |
) |
|
Other Income (Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
20 |
|
|
|
|
|
|
|
42 |
|
|
|
(62 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
14 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
29 |
|
Write downs and gains/(losses) on sales of equity
method investments |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
4 |
|
Other income, net |
|
|
2 |
|
|
|
12 |
|
|
|
1 |
|
|
|
(5 |
) |
|
|
10 |
|
Refinancing expense |
|
|
|
|
|
|
|
|
|
|
(19 |
) |
|
|
|
|
|
|
(19 |
) |
Interest expense |
|
|
|
|
|
|
(15 |
) |
|
|
(33 |
) |
|
|
5 |
|
|
|
(43 |
) |
|
Total other income/(expense) |
|
|
36 |
|
|
|
16 |
|
|
|
(9 |
) |
|
|
(62 |
) |
|
|
(19 |
) |
|
Income/(Loss) From Continuing Operations Before Income
Taxes |
|
|
43 |
|
|
|
32 |
|
|
|
(40 |
) |
|
|
(62 |
) |
|
|
(27 |
) |
Income tax expense/(benefit) |
|
|
11 |
|
|
|
12 |
|
|
|
(13 |
) |
|
|
|
|
|
|
10 |
|
|
Income/(Loss) From Continuing Operations |
|
|
32 |
|
|
|
20 |
|
|
|
(27 |
) |
|
|
(62 |
) |
|
|
(37 |
) |
Income/(losses) from discontinued operations, net of
income taxes |
|
|
11 |
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
10 |
|
|
Net Income/(Loss) |
|
$ |
43 |
|
|
$ |
19 |
|
|
$ |
(27 |
) |
|
$ |
(62 |
) |
|
$ |
(27 |
) |
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
46
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Operations
For the Nine Months Ended September 30, 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues from majority-owned operations |
|
$ |
1,475 |
|
|
$ |
253 |
|
|
$ |
(1 |
) |
|
$ |
(4 |
) |
|
$ |
1,723 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
1,204 |
|
|
|
178 |
|
|
|
|
|
|
|
(4 |
) |
|
|
1,378 |
|
Depreciation and amortization |
|
|
99 |
|
|
|
18 |
|
|
|
4 |
|
|
|
|
|
|
|
121 |
|
General, administrative and development |
|
|
31 |
|
|
|
15 |
|
|
|
90 |
|
|
|
|
|
|
|
136 |
|
Impairment charges |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Corporate relocation charges |
|
|
|
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
6 |
|
|
Total operating costs and expenses |
|
|
1,340 |
|
|
|
211 |
|
|
|
100 |
|
|
|
(4 |
) |
|
|
1,647 |
|
|
Operating Income/(Loss) |
|
|
135 |
|
|
|
42 |
|
|
|
(101 |
) |
|
|
|
|
|
|
76 |
|
|
Other Income (Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of consolidated subsidiaries |
|
|
88 |
|
|
|
|
|
|
|
195 |
|
|
|
(283 |
) |
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
30 |
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
82 |
|
Write downs and gains/(losses) on sales of equity
method investments |
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
Other income, net |
|
|
4 |
|
|
|
46 |
|
|
|
6 |
|
|
|
(15 |
) |
|
|
41 |
|
Refinancing expense |
|
|
|
|
|
|
|
|
|
|
(54 |
) |
|
|
|
|
|
|
(54 |
) |
Interest expense |
|
|
|
|
|
|
(47 |
) |
|
|
(109 |
) |
|
|
15 |
|
|
|
(141 |
) |
|
Total other income (expense) |
|
|
122 |
|
|
|
67 |
|
|
|
38 |
|
|
|
(283 |
) |
|
|
(56 |
) |
|
Income/(Loss) From Continuing Operations Before Income
Taxes |
|
|
257 |
|
|
|
109 |
|
|
|
(63 |
) |
|
|
(283 |
) |
|
|
20 |
|
Income tax expense/(benefit) |
|
|
80 |
|
|
|
20 |
|
|
|
(76 |
) |
|
|
|
|
|
|
24 |
|
|
Income/(Loss) From Continuing Operations |
|
|
177 |
|
|
|
89 |
|
|
|
13 |
|
|
|
(283 |
) |
|
|
(4 |
) |
Income from discontinued operations, net of income tax
expense |
|
|
11 |
|
|
|
6 |
|
|
|
7 |
|
|
|
|
|
|
|
24 |
|
|
Net Income |
|
$ |
188 |
|
|
$ |
95 |
|
|
$ |
20 |
|
|
$ |
(283 |
) |
|
$ |
20 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
47
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Balance Sheet
December 31, 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
NRG Energy, Inc. |
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
(Note Issuer) |
|
|
Eliminations(1) |
|
|
Balance |
|
|
ASSETS
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
(7 |
) |
|
$ |
78 |
|
|
$ |
422 |
|
|
$ |
|
|
|
$ |
493 |
|
Restricted cash |
|
|
3 |
|
|
|
46 |
|
|
|
|
|
|
|
|
|
|
|
49 |
|
Accounts receivable-trade, net |
|
|
214 |
|
|
|
249 |
|
|
|
(214 |
) |
|
|
|
|
|
|
249 |
|
Inventory |
|
|
232 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
240 |
|
Deferred income taxes |
|
|
6 |
|
|
|
(1 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
Derivative instruments valuation |
|
|
385 |
|
|
|
(1 |
) |
|
|
3 |
|
|
|
|
|
|
|
387 |
|
Collateral on deposit in support of energy
risk management activities |
|
|
438 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
438 |
|
Prepayments and other current assets |
|
|
63 |
|
|
|
42 |
|
|
|
550 |
|
|
|
(468 |
) |
|
|
187 |
|
Current assets held for sale |
|
|
8 |
|
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
43 |
|
Current assets discontinued operations |
|
|
|
|
|
|
99 |
|
|
|
11 |
|
|
|
|
|
|
|
110 |
|
|
Total current assets |
|
|
1,342 |
|
|
|
520 |
|
|
|
802 |
|
|
|
(468 |
) |
|
|
2,196 |
|
|
Net property, plant and equipment |
|
|
2,176 |
|
|
|
412 |
|
|
|
21 |
|
|
|
|
|
|
|
2,609 |
|
Other Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries |
|
|
787 |
|
|
|
|
|
|
|
1,774 |
|
|
|
(2,561 |
) |
|
|
|
|
Equity investments in affiliates |
|
|
243 |
|
|
|
359 |
|
|
|
|
|
|
|
|
|
|
|
602 |
|
Notes receivable |
|
|
76 |
|
|
|
457 |
|
|
|
1,397 |
|
|
|
(1,473 |
) |
|
|
457 |
|
Intangible assets, net |
|
|
238 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
257 |
|
Derivative instruments valuation |
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18 |
|
Funded letter of credit |
|
|
|
|
|
|
|
|
|
|
350 |
|
|
|
|
|
|
|
350 |
|
Deferred income taxes |
|
|
|
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
26 |
|
Other non-current assets |
|
|
22 |
|
|
|
19 |
|
|
|
83 |
|
|
|
|
|
|
|
124 |
|
Noncurrent assets discontinued operations |
|
|
|
|
|
|
814 |
|
|
|
13 |
|
|
|
|
|
|
|
827 |
|
|
Total other assets |
|
|
1,384 |
|
|
|
1,694 |
|
|
|
3,617 |
|
|
|
(4,034 |
) |
|
|
2,661 |
|
|
Total Assets |
|
$ |
4,902 |
|
|
$ |
2,626 |
|
|
$ |
4,440 |
|
|
$ |
(4,502 |
) |
|
$ |
7,466 |
|
|
LIABILITIES AND STOCK HOLDERS EQUITY
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current portion of long-term debt and capital
leases |
|
$ |
459 |
|
|
$ |
90 |
|
|
$ |
14 |
|
|
$ |
(468 |
) |
|
$ |
95 |
|
Accounts payable |
|
|
158 |
|
|
|
67 |
|
|
|
16 |
|
|
|
|
|
|
|
241 |
|
Derivative instruments valuation |
|
|
678 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
679 |
|
Other bankruptcy settlement |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Accrued expenses and other current liabilities |
|
|
60 |
|
|
|
42 |
|
|
|
67 |
|
|
|
|
|
|
|
169 |
|
Current liabilities discontinued
operations |
|
|
|
|
|
|
163 |
|
|
|
7 |
|
|
|
|
|
|
|
170 |
|
|
Total current liabilities |
|
|
1,355 |
|
|
|
366 |
|
|
|
104 |
|
|
|
(468 |
) |
|
|
1,357 |
|
|
Other Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt and capital leases |
|
|
1,397 |
|
|
|
620 |
|
|
|
1,866 |
|
|
|
(1,473 |
) |
|
|
2,410 |
|
Deferred income taxes |
|
|
37 |
|
|
|
143 |
|
|
|
(52 |
) |
|
|
|
|
|
|
128 |
|
Derivative instruments valuation |
|
|
25 |
|
|
|
11 |
|
|
|
20 |
|
|
|
|
|
|
|
56 |
|
Out-of-market contracts |
|
|
298 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
298 |
|
Other non-current liabilities |
|
|
126 |
|
|
|
22 |
|
|
|
22 |
|
|
|
|
|
|
|
170 |
|
Non-current liabilities discontinued
operations |
|
|
|
|
|
|
568 |
|
|
|
1 |
|
|
|
|
|
|
|
569 |
|
|
Total non-current liabilities |
|
|
1,883 |
|
|
|
1,364 |
|
|
|
1,857 |
|
|
|
(1,473 |
) |
|
|
3,631 |
|
|
Total liabilities |
|
|
3,238 |
|
|
|
1,730 |
|
|
|
1,961 |
|
|
|
(1,941 |
) |
|
|
4,988 |
|
|
Minority interest |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
3.625% Preferred Stock |
|
|
|
|
|
|
|
|
|
|
246 |
|
|
|
|
|
|
|
246 |
|
Stockholders Equity |
|
|
1,664 |
|
|
|
897 |
|
|
|
2,231 |
|
|
|
(2,561 |
) |
|
|
2,231 |
|
|
Total Liabilities and Stockholders Equity |
|
$ |
4,902 |
|
|
$ |
2,628 |
|
|
$ |
4,438 |
|
|
$ |
(4,502 |
) |
|
$ |
7,466 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
48
NRG Energy, Inc. and Subsidiaries
Condensed Consolidating Statements of Cash Flows
For the Nine Months Ended September 30, 2005
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantor |
|
|
Non-Guarantor |
|
|
|
|
|
|
|
|
|
|
Consolidated |
|
(In millions) |
|
Subsidiaries |
|
|
Subsidiaries |
|
|
NRG Energy, Inc. |
|
|
Eliminations (a) |
|
|
Balance |
|
|
Cash Flows from Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
188 |
|
|
$ |
95 |
|
|
$ |
20 |
|
|
$ |
(283 |
) |
|
$ |
20 |
|
Adjustments to reconcile net income to net cash
provided (used) by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions in excess of/(less than)
equity in earnings of unconsolidated
affiliates and consolidated subsidiaries |
|
|
(54 |
) |
|
|
(33 |
) |
|
|
304 |
|
|
|
(216 |
) |
|
|
1 |
|
Depreciation and amortization |
|
|
100 |
|
|
|
38 |
|
|
|
7 |
|
|
|
|
|
|
|
145 |
|
Amortization of financing costs and debt
discounts |
|
|
|
|
|
|
5 |
|
|
|
3 |
|
|
|
|
|
|
|
8 |
|
Amortization of intangibles and
out-of-market contracts |
|
|
11 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
16 |
|
Amortization of unearned equity compensation |
|
|
2 |
|
|
|
|
|
|
|
6 |
|
|
|
|
|
|
|
8 |
|
Write-off of deferred financing costs and
debt premium |
|
|
|
|
|
|
(9 |
) |
|
|
2 |
|
|
|
|
|
|
|
(7 |
) |
Write downs and (gains)//losses on sale of
equity method investments |
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
(16 |
) |
Asset impairment |
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Changes in deferred income taxes |
|
|
(172 |
) |
|
|
(4 |
) |
|
|
122 |
|
|
|
|
|
|
|
(54 |
) |
Minority interest |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Changes in derivatives |
|
|
245 |
|
|
|
3 |
|
|
|
4 |
|
|
|
|
|
|
|
252 |
|
Gain on legal settlement |
|
|
|
|
|
|
(14 |
) |
|
|
|
|
|
|
|
|
|
|
(14 |
) |
Gain on sale of discontinued operations |
|
|
|
|
|
|
(11 |
) |
|
|
|
|
|
|
|
|
|
|
(11 |
) |
Changes in collateral deposit payments
supporting energy risk management
activities |
|
|
(598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(598 |
) |
Cash provided/(used) by changes in working
capital, net of acquisition and disposition
affects |
|
|
315 |
|
|
|
(402 |
) |
|
|
216 |
|
|
|
|
|
|
|
129 |
|
|
Net Cash
Provided/(Used) by Operating Activities |
|
|
43 |
|
|
|
(342 |
) |
|
|
684 |
|
|
|
(499 |
) |
|
|
(114 |
) |
|
Cash Flows from Investing Activities |
Capital expenditures |
|
|
(32 |
) |
|
|
(11 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
(46 |
) |
Decrease/(increase) in restricted cash, net |
|
|
1 |
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
18 |
|
Decrease/(increase) in notes receivable |
|
|
305 |
|
|
|
225 |
|
|
|
(430 |
) |
|
|
|
|
|
|
100 |
|
Proceeds from sale of investments |
|
|
|
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
|
70 |
|
Proceeds on sale of discontinued operations |
|
|
|
|
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
36 |
|
Return of capital from equity method
investments and projects |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
Net Cash
Provided/(Used) by Investing Activities |
|
|
274 |
|
|
|
338 |
|
|
|
(433 |
) |
|
|
|
|
|
|
179 |
|
|
Cash Flows from Financing Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments of dividends to preferred stockholders |
|
|
(478 |
) |
|
|
(21 |
) |
|
|
(12 |
) |
|
|
499 |
|
|
|
(12 |
) |
Payment for treasury stock |
|
|
|
|
|
|
|
|
|
|
(251 |
) |
|
|
|
|
|
|
(251 |
) |
Repayment of minority interest obligations |
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
(4 |
) |
Borrowing under revolving line of credit |
|
|
|
|
|
|
|
|
|
|
80 |
|
|
|
|
|
|
|
80 |
|
Proceeds from issuance of preferred stock, net |
|
|
|
|
|
|
|
|
|
|
246 |
|
|
|
|
|
|
|
246 |
|
Proceeds from issuance of long-term debt, net |
|
|
|
|
|
|
249 |
|
|
|
|
|
|
|
|
|
|
|
249 |
|
Deferred debt issuance costs |
|
|
|
|
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Payments for short and long-term debt |
|
|
|
|
|
|
(331 |
) |
|
|
(648 |
) |
|
|
|
|
|
|
(979 |
) |
|
Net Cash Used by Financing Activities |
|
|
(478 |
) |
|
|
(109 |
) |
|
|
(585 |
) |
|
|
499 |
|
|
|
(673 |
) |
|
Change in Cash from Discontinued Operations |
|
|
|
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Effect of Exchange Rate Changes on Cash and Cash
Equivalents |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
Change in Cash and Cash equivalents |
|
|
(161 |
) |
|
|
(97 |
) |
|
|
(334 |
) |
|
|
|
|
|
|
(592 |
) |
Cash and Cash Equivalents at Beginning of Period |
|
|
156 |
|
|
|
201 |
|
|
|
712 |
|
|
|
|
|
|
|
1,069 |
|
|
Cash and Cash Equivalents at End of Period |
|
$ |
(5 |
) |
|
$ |
104 |
|
|
$ |
378 |
|
|
$ |
|
|
|
$ |
477 |
|
|
|
|
|
(a) |
|
All significant intercompany transactions have been eliminated in consolidation. |
49
Item 2 Managements Discussion and Analysis of Financial Condition and Results of
Operations
MANAGEMENTS DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Introduction
NRG Energy, Inc., NRG, or the Company, is a wholesale power generation
company, 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
marketing and trading of energy, capacity and related products in the United States and overseas.
NRG has a diverse portfolio of electric generation facilities in terms of geography, fuel type and
dispatch levels. NRGs principal domestic generation assets consist of a diversified mix of natural
gas, coal, oil and nuclear facilities, representing approximately 46%, 34%, 15% and 5% of the
Companys total domestic generation capacity, respectively. In addition, approximately 15% of the
Companys domestic generating facilities have dual or multiple fuel capacity, which allows plants
to dispatch with the lowest cost fuel option. NRG has also acquired Padoma Wind Power LLC, making
it likely that the Company will invest in domestic terrestrial wind projects.
NRGs 2005 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 and nine months ended September 30, 2006 and 2005.
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; |
|
|
|
|
significant events that occurred in 2006 that are important to understanding the results of operations; |
|
|
|
|
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.
50
Regulatory Matter Developments
Northeast Region
Improvements in the New England market design should favorably impact revenues from operations
in the fourth quarter 2006 and beyond. Interim capacity transition payments provided for under the
FCM settlement are scheduled to commence December 1, 2006. In addition, the LFRM market for Connecticut cleared at the cap of $14
KW-month for the eight month winter period from October 1, 2006 to May 31, 2007. NRG sold 292 MW in
LFRM auction and expects its participation in this market to increase
revenues from the region. On November 3, 2006, the New England
Power Pool participants committee voted to eliminate Peaking Unit
Safe Harbor, or PUSH, bidding and the ISO-NE is expected to make a
filing implementing this vote. The elimination of PUSH bidding would
primarily impact NRGs Norwalk Harbor plant.
On September 29, 2006, the Management Committee of the NYISO approved a proposal sponsored by
Consolidated Edison, or ConEd, to impose additional mitigation on the current owners of its
divested generation units in New York City, including NRG with its Arthur Kill and Astoria
facilities. The proposed mitigation effectively lowers the bid caps currently set forth in the
NYISO tariffs that were specified at the time ConEd divested the units. NRG is contesting the
proposal before the NYISO Board of Directors.
NRG expects that the Settlement Agreement filed on September 29, 2006, in the Reliability
Pricing Model, or RPM, proceeding will have a positive impact on its operations in the region when
it is implemented. The Settlement Agreement proposes to implement RPM, a locational forward
capacity market. The Settlement Agreement, which is supported by the majority of the parties in the
proceeding, makes a number of changes to the RPM proposal filed by PJM on August 31, 2005,
including changes to the demand curve, use of 3-year forward auctions, inclusion of a Fixed
Resource Requirement Alternative that allows certain load-serving entities to opt out, and a
generator peak-period availability metric. The Settlement Agreement proposes to implement RPM with
the annual planning period that begins June 1, 2007, and to commence the RPM forward auctions in
April 2007.
West Region
On September 29, 2006, CAISO notified NRG that it wishes to extend the existing RMR agreements
for NRGs Cabrillo Power I, LLC and Cabrillo Power II, LLC facilities currently scheduled to expire
on December 31, 2006, for another year.
On September 21, 2006, FERC conditionally accepted the CAISOs Market Redesign and Technology
Upgrade, or MRTU, proposal which is currently scheduled to go into effect in November 2007.
Significant components of the MRTU include locational marginal pricing of energy, a more effective
congestion management system, a day-ahead market, and an increase to the existing bid caps. NRG
considers these market reforms to be a positive development.
On July 20, 2006, the California Public Utility Commission, or CPUC, issued an
order toward establishing a standard Resource Adequacy Capacity Product that follows on its
decision to impose local capacity requirements, which takes effect January 1, 2007. On the same
date, the CPUC issued its order on long-term resource procurement that requires Southern California
Edison, or SCE, to procure at least 1,500 MW over the next couple of years. NRG views these
initiatives as positive developments and expects to participate in auctions and Request for
Proposals, or RFPs, to supply power to SCE and other load-serving entities affected by the order.
For
a further discussion on NRGs regulatory matters, see Note 16 to the Condensed Consolidated
Financial Statements of this Form 10-Q. Some of this information is about costs that may be material to NRGs
financial results.
Environmental Matter Developments
West Region
On September 27, 2006, Governor Arnold Schwarzenegger signed Assembly Bill 32 California
Global Warming Solutions Act of 2006 and Senate Bill 1368 Electricity: Emissions of Greenhouse
Gases. Assembly Bill 32, or AB 32, requires the state to develop a greenhouse gas, or GHG,
reduction program to reduce emissions to 1990 levels by 2020, a reduction of approximately 25%. The
reductions will be phased in beginning 2012 pursuant to regulations to be adopted by 2011. The
financial impact to NRG will depend on final regulations. Senate Bill 1368, or SB 1368, prohibits
utilities from entering into contracts of five years or more for any baseload generation exceeding
a 60% capacity factor unless the contracting facility complies with a greenhouse gas performance
standard no higher than the rate of GHG emissions for a combined cycle natural gas baseload power
plant. NRGs California plants and development projects are unaffected by SB 1368 because they
either meet the combined cycle standard or they do not exceed the 60% capacity factor and/or five
year contract term thresholds.
Northeast Region
On December 20, 2005, seven northeastern states entered into a Memorandum of Understanding to
create a regional initiative to establish a cap-and-trade greenhouse gas program for electric
generators, referred to as the Regional Greenhouse Gas Initiative, or
51
RGGI. The
state of Maryland has since announced its intent to join pending an analysis of its impact to the
state. In August 2006, the states participating in RGGI released a model rule to be adopted by the
states. The program begins in 2009. The model rule addresses program descriptions including,
timelines, monitoring, the use of offsets, and allowance trading. Individual states including
Connecticut, Delaware and New York in which NRG operates, must promulgate state rules which can be
based on the model rule, and in addition, address allowance allocations, treatment of unallocated
allowances and leakage. NRG continues to actively participate in state and regional RGGI
proceedings.
The USEPA issued rules adding Delaware and New Jersey to the Clean Air Interstate Rule, or
CAIR, because emissions from these states contribute to non-attainment of the fine particle
pollution National Ambient Air Quality Standards in other states. The USEPA also reconfirmed its
position on five contested CAIR issues including striking down the pollution control project, or
PCP, exclusion under the NSR regulations.
A number of states in which NRG operates or intends to operate coal plants, including
Connecticut, Delaware, Massachusetts and New York, plan to constrain in-state mercury emissions
above and beyond the federal Clean Air Mercury Rule, or CAMR. These states are in various stages of
finalizing state regulations and a state implementation plan which will cap the states mercury
emissions at the proposed CAMR cap and trade levels. Louisiana and Texas will adopt the EPA cap
and trade program. NRG continues to actively track developments to determine its financial impact,
if any, on its operations.
In the fourth quarter 2006, the DNREC is expected to promulgate 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 are expected to govern the control of SO2, NOx and mercury emissions from
electric generating units. NRGs current plans to install controls at its Indian River facility may
be affected by the regulation when it is promulgated.
All Other Regions
In February 2006, the USEPA promulgated a regulation that sets New Source Performance
Standards, or NSPS, criteria for air pollutants from utility, industrial, commercial, and
institutional steam generating units. While the emissions control requirements already in place
through USEPAs air permitting and air toxic programs require controls for boilers equivalent to
those established by this rule, the final rule substantially tightens the existing NSPS. Units
constructed or undergoing major modification after February 28, 2005 are affected.
For a further discussion on NRGs environmental matters see Note 17 to the Condensed
Consolidated Financial Statements of this Form 10-Q. Some of this information includes costs that may be material to
NRGs financial results.
52
Consolidated Results of Operations
The following table provides selected financial information for NRG Energy, Inc., for the
three and nine months ended September 30, 2006 and 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
(In millions except otherwise noted) |
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
1,070 |
|
|
$ |
699 |
|
|
|
53 |
% |
|
$ |
2,364 |
|
|
$ |
1,385 |
|
|
|
71 |
% |
Capacity revenue |
|
|
430 |
|
|
|
141 |
|
|
|
205 |
|
|
|
1,125 |
|
|
|
416 |
|
|
|
170 |
|
Alternative revenue |
|
|
28 |
|
|
|
29 |
|
|
|
(3 |
) |
|
|
93 |
|
|
|
90 |
|
|
|
3 |
|
O & M fees |
|
|
4 |
|
|
|
5 |
|
|
|
(20 |
) |
|
|
13 |
|
|
|
14 |
|
|
|
(7 |
) |
Risk management activities |
|
|
156 |
|
|
|
(255 |
) |
|
NA |
|
|
265 |
|
|
|
(291 |
) |
|
NA |
Revenue contract amortization |
|
|
224 |
|
|
|
4 |
|
|
NA |
|
|
494 |
|
|
|
5 |
|
|
NA |
Other revenues |
|
|
88 |
|
|
|
64 |
|
|
|
38 |
|
|
|
125 |
|
|
|
104 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
2,000 |
|
|
|
687 |
|
|
|
191 |
|
|
|
4,479 |
|
|
|
1,723 |
|
|
|
160 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of majority-owned operations |
|
|
1,055 |
|
|
|
604 |
|
|
|
75 |
|
|
|
2,478 |
|
|
|
1,378 |
|
|
|
80 |
|
Depreciation and amortization |
|
|
148 |
|
|
|
41 |
|
|
|
261 |
|
|
|
443 |
|
|
|
121 |
|
|
|
266 |
|
General, administrative and development |
|
|
79 |
|
|
|
42 |
|
|
|
88 |
|
|
|
220 |
|
|
|
136 |
|
|
|
62 |
|
Impairment charges |
|
|
|
|
|
|
6 |
|
|
NA |
|
|
|
|
|
|
6 |
|
|
NA |
Corporate relocation charges |
|
|
|
|
|
|
2 |
|
|
NA |
|
|
|
|
|
|
6 |
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
Total operating costs and expenses |
|
|
1,282 |
|
|
|
695 |
|
|
|
84 |
|
|
|
3,141 |
|
|
|
1,647 |
|
|
|
91 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
718 |
|
|
|
(8 |
) |
|
NA |
|
|
1,338 |
|
|
|
76 |
|
|
NA |
Other Income/(Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of unconsolidated affiliates |
|
|
17 |
|
|
|
29 |
|
|
|
(41 |
) |
|
|
46 |
|
|
|
82 |
|
|
|
(44 |
) |
Write downs and gains/(losses) on sales of
equity method investments |
|
|
(3 |
) |
|
|
4 |
|
|
NA |
|
|
8 |
|
|
|
16 |
|
|
|
(50 |
) |
Other income, net |
|
|
30 |
|
|
|
10 |
|
|
|
200 |
|
|
|
118 |
|
|
|
41 |
|
|
|
188 |
|
Refinancing expenses |
|
|
|
|
|
|
(19 |
) |
|
NA |
|
|
(178 |
) |
|
|
(54 |
) |
|
|
(230 |
) |
Interest expense |
|
|
(154 |
) |
|
|
(43 |
) |
|
|
(258 |
) |
|
|
(420 |
) |
|
|
(141 |
) |
|
|
(198 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total other (expenses) |
|
|
(110 |
) |
|
|
(19 |
) |
|
|
(479 |
) |
|
|
(426 |
) |
|
|
(56 |
) |
|
|
(661 |
) |
Income/(Loss) from Continuing Operations before
income tax expense |
|
|
608 |
|
|
|
(27 |
) |
|
NA |
|
|
912 |
|
|
|
20 |
|
|
NA |
Income tax expense |
|
|
235 |
|
|
|
10 |
|
|
NA |
|
|
324 |
|
|
|
24 |
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
Income/(Loss) from Continuing Operations |
|
|
373 |
|
|
|
(37 |
) |
|
NA |
|
|
588 |
|
|
|
(4 |
) |
|
NA |
Income from discontinued operations, net of
income tax expense |
|
|
49 |
|
|
|
10 |
|
|
|
390 |
|
|
|
63 |
|
|
|
24 |
|
|
|
163 |
|
|
|
|
|
|
|
|
|
|
|
|
Net Income/(Loss) |
|
$ |
422 |
|
|
$ |
(27 |
) |
|
NA |
|
$ |
651 |
|
|
$ |
20 |
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average natural gas price Henry Hub (S/MMbtu) |
|
|
6.12 |
|
|
|
9.92 |
|
|
|
(38 |
)% |
|
|
6.90 |
|
|
|
7.76 |
|
|
|
(11 |
)% |
|
NA- Not Applicable
Significant Events Reflected in NRGs Results of Operations during the nine months ended September 30, 2006
Operational
|
|
|
Total generation increased by 141% primarily due to the addition of NRG Texas to the NRG
total portfolio. |
|
|
|
|
Improved operating performance and new tolling agreements contributed to $81 million of
higher operating income from the South Central region. |
|
|
|
|
A mild winter and weakened power prices lowered generation demand for the Northeast
regions peaking and intermediate assets by 57%. |
|
|
|
|
NRG recorded a gain of $68 million from the sale of excess emission allowances. |
|
|
|
|
NRG recorded $178 million in refinancing costs and
$420 million in interest expense primarily due
to new debt facilities associated with the acquisition of NRG Texas. |
|
|
|
|
Record peak energy demand in each of the markets served by
NRGs major business segments ranging with increases of 4% to
11% over previous records. |
|
|
|
|
Recognized $265 million in gains from risk management activities. |
53
Acquisitions/Dispositions
|
|
|
On February 2, 2006, NRG acquired Texas Genco LLC. Texas Genco LLC is now a wholly-owned
subsidiary of NRG, and is managed and accounted for as a separate business segment referred
to as NRG Texas. |
|
|
|
|
On August 30, 2006, NRG announced the completion of the sale of its 100% owned Flinders
power station and related assets. NRG received approximately $242 million in cash and
recognized an after-tax gain on the sale of approximately $61 million. |
|
|
|
|
On March 31, 2006, NRG acquired Dynegys 50% ownership interest in WCP, and became the
sole owner of WCPs 1,808 MW of generation in Southern California. The results of
operations of WCP were consolidated as of April 1, 2006, prior to which, NRGs 50%
ownership of WCP was recorded as an equity method investment. |
|
|
|
|
On January 31, 2006, NRG finalized a settlement agreement with an equipment manufacturer
related to certain turbine purchase agreements. Upon finalization of the settlement, NRG
recorded a total of $67 million of other income, of which $35 million was related to the
discharge of accounts payable previously recorded and $32 million was related to the
receiving and recording of the equipment at fair value. |
For the benefit of the following discussions, the tables below represent the results of NRG
excluding the impact of NRG Texas and WCP for the three and nine months ended September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the three months ended September 30, |
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total excluding |
|
|
|
|
(In millions) |
|
Consolidated |
|
|
NRG Texas |
|
|
WCP |
|
|
NRG Texas/WCP |
|
|
Consolidated |
|
|
Energy revenue |
|
$ |
1,070 |
|
|
$ |
578 |
|
|
$ |
31 |
|
|
$ |
461 |
|
|
$ |
699 |
|
Capacity revenue |
|
|
430 |
|
|
|
234 |
|
|
|
27 |
|
|
|
169 |
|
|
|
141 |
|
Alternative revenue |
|
|
28 |
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
29 |
|
O & M fees |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
5 |
|
Risk management activities |
|
|
156 |
|
|
|
114 |
|
|
|
(2 |
) |
|
|
44 |
|
|
|
(255 |
) |
Contract amortization |
|
|
224 |
|
|
|
219 |
|
|
|
|
|
|
|
5 |
|
|
|
4 |
|
Other revenues |
|
|
88 |
|
|
|
6 |
|
|
|
3 |
|
|
|
79 |
|
|
|
64 |
|
|
Total Operating revenues |
|
|
2,000 |
|
|
|
1,151 |
|
|
|
59 |
|
|
|
790 |
|
|
|
687 |
|
|
Cost of majority-owned operations |
|
|
1,055 |
|
|
|
506 |
|
|
|
43 |
|
|
|
506 |
|
|
|
604 |
|
Depreciation and amortization |
|
|
148 |
|
|
|
104 |
|
|
|
|
|
|
|
44 |
|
|
|
41 |
|
General, administrative and development |
|
|
79 |
|
|
|
29 |
|
|
|
6 |
|
|
|
44 |
|
|
|
42 |
|
Impairment charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Corporate relocation charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
|
Total operating costs and expenses |
|
|
1,282 |
|
|
|
639 |
|
|
|
49 |
|
|
|
594 |
|
|
|
695 |
|
|
Operating income/(loss) |
|
$ |
718 |
|
|
$ |
512 |
|
|
$ |
10 |
|
|
$ |
196 |
|
|
$ |
(8 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the nine months ended September 30, |
|
2006 |
|
|
2005 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total excluding |
|
|
|
|
(In millions) |
|
Consolidated |
|
|
NRG Texas (a) |
|
|
WCP (b) |
|
|
NRG Texas |
|
|
Consolidated |
|
|
Energy revenue |
|
$ |
2,364 |
|
|
$ |
1,219 |
|
|
$ |
58 |
|
|
$ |
1,087 |
|
|
$ |
1,385 |
|
Capacity revenue |
|
|
1,125 |
|
|
|
624 |
|
|
|
47 |
|
|
|
454 |
|
|
|
416 |
|
Alternative revenue |
|
|
93 |
|
|
|
|
|
|
|
|
|
|
|
93 |
|
|
|
90 |
|
O & M fees |
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
13 |
|
|
|
14 |
|
Risk management activities |
|
|
265 |
|
|
|
165 |
|
|
|
(3 |
) |
|
|
103 |
|
|
|
(291 |
) |
Contract amortization |
|
|
494 |
|
|
|
481 |
|
|
|
|
|
|
|
13 |
|
|
|
5 |
|
Other revenues |
|
|
125 |
|
|
|
9 |
|
|
|
6 |
|
|
|
110 |
|
|
|
104 |
|
|
Total Operating revenues |
|
|
4,479 |
|
|
|
2,498 |
|
|
|
108 |
|
|
|
1,873 |
|
|
|
1,723 |
|
|
Cost of majority-owned operations |
|
|
2,478 |
|
|
|
1,251 |
|
|
|
80 |
|
|
|
1,147 |
|
|
|
1,378 |
|
Depreciation and amortization |
|
|
443 |
|
|
|
309 |
|
|
|
1 |
|
|
|
133 |
|
|
|
121 |
|
General, administrative and development |
|
|
220 |
|
|
|
80 |
|
|
|
12 |
|
|
|
128 |
|
|
|
136 |
|
Impairment charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Corporate relocation charges |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
|
Total operating costs and expenses |
|
|
3,141 |
|
|
|
1,640 |
|
|
|
93 |
|
|
|
1,408 |
|
|
|
1,647 |
|
|
Operating income |
|
$ |
1,338 |
|
|
$ |
858 |
|
|
$ |
15 |
|
|
$ |
465 |
|
|
$ |
76 |
|
|
|
|
|
(a) |
|
Financial information for the results of operations for NRG Texas is for the period of
February 2, 2006 to September 30, 2006 |
|
(b) |
|
Financial information for the results of operations for WCP is for the period of April 1,
2006 to September 30, 2006 |
54
Managements discussion of the results of operations for the three months ended September
30, 2006 and 2005
Revenues from Majority-Owned Operations
Total operating revenues from majority-owned operations rose by $1,313 million or 191%, from
the third quarter 2005 to approximately $2.0 billion. Energy revenues comprised $1.1 billion of the
total, with 47% contracted compared to $700 million in the third quarter of 2005 of which 11% was
contracted. The current quarters results were favorably impacted by the acquisition of NRG Texas,
which contributed $1.2 billion to operating revenues, and included $578 million of energy revenues
and $219 million related to contract amortization from out-of-market power contracts. Additionally,
the acquisition of Dynegys 50% interest in WCP, contributed $59 million to total operating
revenues. Excluding NRG Texas and WCP, total operating revenues for the current quarter increased
by $103 million, as generation demand for the Northeast regions intermediate and peaking plants
declined by 43% compared to the third quarter 2005, were more than
offset by $300 million in gains
from risk management activities. Energy revenues, excluding NRG Texas and WCP, declined by $239
million, of which $225 million was due to lower power prices and lower generation in the Northeast
region. Third quarter power prices in the Northeast regions two key New York markets fell by 32%
and 28%, primarily due to a 37% decline in natural gas prices. The South Central regions total
operating revenues declined by $10 million during the quarter compared to the same period in 2005,
primarily due to lower purchased energy costs due to the netting of energy purchased for resale against merchant sales this quarter. For
the third quarter 2005, the South Central region purchased energy primarily to service its load
obligations and not for resale.
Capacity revenues for the three months ended September 30, 2006 increased by $289 million or
205%, compared to the three months ended September 30, 2005. Of this increase, $234 million was
related to NRG Texas primarily from auction sales. In addition, capacity revenues increased to $27
million in the West region primarily due to the acquisition of WCP. The remainder of the
increase was related to the Northeast regions New York assets where capacity prices
increased from the third quarter of 2005 as well as a higher contract rate related to the
Connecticut RMR settlement agreement.
Risk management activities not qualifying for hedge accounting treatment resulted in a total
derivative gain of $156 million for the three months ended September 30, 2006 compared to a $260
million loss in the comparable quarter last year. NRGs third quarter 2006 gain was comprised of
$27 million in financial revenue losses and $183 million of mark-to-market gains. The $27 million
loss of financial revenues represents the settled value for the quarter of financial instruments
that no longer qualify for hedge accounting treatment. Of the $183 million of mark-to-market gains,
$161 million represents the change in fair value of forward sales of electricity and fuel, and $38
million represents the reversal of mark-to-market losses which ultimately settled as financial
revenues. Additionally, NRG recognized a $16 million loss associated with its trading activity.
These activities primarily support the Northeast and Texas regions assets.
The following table shows NRGs risk management activities that do not qualify for hedge
accounting treatment for the three months ended September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, 2006 |
|
|
Three months ended September 30, 2005 |
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
(In millions) |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
All Other |
|
|
Total |
|
|
Northeast |
|
|
Central |
|
|
All Other |
|
|
Total |
|
|
|
|
Net losses on settled
positions, or financial revenues |
|
$ |
(14 |
) |
|
$ |
(7 |
) |
|
$ |
(3 |
) |
|
$ |
(3 |
) |
|
$ |
(27 |
) |
|
$ |
(87 |
) |
|
$ |
(1 |
) |
|
$ |
|
|
|
$ |
(88 |
) |
|
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized
unrealized losses on settled
positions |
|
|
|
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
38 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Net unrealized gains/(losses) on
open positions related to economic
hedges |
|
|
128 |
|
|
|
35 |
|
|
|
(2 |
) |
|
|
|
|
|
|
161 |
|
|
|
(172 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(173 |
) |
Net unrealized gains/(losses) on open
positions related to trading activity |
|
|
|
|
|
|
(33 |
) |
|
|
17 |
|
|
|
|
|
|
|
(16 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results |
|
|
128 |
|
|
|
40 |
|
|
|
15 |
|
|
|
|
|
|
|
183 |
|
|
|
(171 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(172 |
) |
Total derivative gain/(losses)(a) |
|
$ |
114 |
|
|
$ |
33 |
|
|
$ |
12 |
|
|
$ |
(3 |
) |
|
$ |
156 |
|
|
$ |
(258 |
) |
|
$ |
(2 |
) |
|
$ |
|
|
|
$ |
(260 |
) |
|
|
|
(a) 2005 results includes derivative cost of energy
Since NRG risk management 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
qualify for hedge accounting treatment) and costs of energy. In late 2005 and in 2006, NRG hedged a
portion of its 2006 and 2007 Northeast regions generation. Since that time, the settled and
forward prices of electricity have decreased, resulting in the recognition of mark-to-market
forward sales and the settlement of such positions at reduced losses. Additionally, due to a
decline in correlation between gas and power prices, $78 million of hedge accounting
ineffectiveness on Texas hedge contracts was recognized. In 2005, Hurricanes Katrina and Rita
disrupted gas
55
production in the Gulf of Mexico causing a strong increase in natural gas prices
resulting in a mark-to-market loss of approximately $173 million. Since the fourth quarter 2005,
gas inventories have risen to levels that are approximately 10% above the average of the last five
years, easing gas supply concerns and reducing forward 2007 gas prices by approximately 20%.
Cost of Majority-Owned Operations
Cost of majority-owned operations includes cost of energy, operating and maintenance expenses,
and non-income tax expenses. For the three months ended September 30, 2006, cost of majority-owned
operations was $1.1 billion or 53% of total operating revenues compared to $604 million, or 88%, of
total operating revenues for the comparable period in 2005, an increase of $451 million or 75%.
This increase in absolute terms but decrease in relative percentage terms was primarily due to NRG
Texas which incurred costs of $506 million. Cost of energy increased from $516 million for the
three months ended September 30, 2005 to $858 million for the three months ended September 30,
2006. The increase was primarily due to NRG Texas which recorded $406 million in cost of energy.
Additionally, WCPs cost of energy for the third quarter 2006 was $33 million. Excluding NRG
Texas and WCP, cost of energy decreased by $97 million. This decrease was driven by $94 million in
lower cost of energy in the Northeast region primarily due to lower oil and gas fuel costs related
to lower generation from oil- and gas-fired assets of approximately 52% and 13% respectively. The
South Central regions cost of energy was lower in the third quarter 2006 compared to the same
period in 2005 by $43 million primarily due to a reduction in the amount and price per MWh of
purchased power and fewer unplanned outages at the regions baseload coal plants in 2006.
Other operating costs during the third quarter 2006 were $196 million compared to $88 million
for the third quarter 2005. This increase was primarily driven by other operating costs related to
NRG Texas of $101 million and WCP of $10 million.
Depreciation and Amortization
NRGs depreciation and amortization expense for the three months ended September 30, 2006 and
2005 was $148 million and $41 million, respectively. The increase in depreciation and amortization
from was primarily due to the acquisition of NRG Texas.
General, Administrative and Development
NRGs general, administrative and development, or G&A, costs for the three months ended
September 30, 2006 were $79 million or 4% of total operating revenues compared to $42 million or 6%
of total operating revenue for the three months ended September 30, 2005. These costs are primarily
comprised of corporate labor, insurance and external professional support, such as legal,
accounting and audit fees. G&A costs at NRG Texas were $17 million excluding corporate allocations
and were $5 million at WCP. Corporate G&A incurred, before overhead allocations to regional
segments, during the third quarter 2006 was $32 million compared to $22 million for the third
quarter 2005. This $10 million increase was due to $4 million of non-recurring costs associated
with the NRG Texas integration efforts and higher labor and consulting expenses. Development costs
incurred in 2006 in support of NRGs recently announced repowering programs amounted to
approximately $9 million.
Equity in Earnings of Unconsolidated Affiliates
For the three months ended September 30, 2006, NRG recorded $17 million in equity earnings
from the Companys investments in unconsolidated affiliates, a 41% decrease from the comparable
period last year of $29 million. Of the $12 million decrease, $7 million was due to the acquisition
of Dynegys 50% interest in WCP. As part of that transaction, NRG also sold its 50% interest in
the Rocky Road investment, which accounted for $6 million of the decline in total equity earnings.
Other Income, Net
For the three months ended September 30, 2006 and 2005, NRG recorded other income of $30
million and $10 million, respectively. Other income is primarily comprised of interest income, of
which NRG recorded $22 million and $9 million for the third quarter 2006 and 2005, respectively.
The increase in interest income this quarter compared to the third quarter 2005 was due to average
quarterly cash balances that were almost twice as large as in 2005.
NRG also recorded $7 million of other income in
this years third quarter from the favorable settlement with respect to post closing adjustments on
the acquisition of NRGs western NY plants in 1998 and 1999.
Interest Expense
Interest expense for the three months ended September 30, 2006 was $154 million compared to
$43 million, for the three months ended September 30, 2005. Interest expense increased due to the
servicing of new debt issued to finance the acquisition of NRG
Texas. For further discussion of the acquisition and financing thereof, see Notes 3 and 8 to
the condensed consolidated financial statements of this Form 10-Q.
56
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 September 30, 2006, NRG had deferred gains of $10
million in other comprehensive income. See Note 8 to the condensed consolidated financial
statements of this Form 10-Q for a further discussion on these interest rate swaps.
Refinancing Expense
During the three months ended September 30, 2005, NRG recorded $19 million of refinancing
expense related to the repurchase of $229 million of its Second Priority Notes.
Income Tax Expense
Income tax expense was $235 million and $10 million for the three months ended September 30,
2006 and 2005, respectively. The effective tax rate was 38.7% and (37.0)% for the three months
ended September 30, 2006 and 2005, respectively. The effective income tax rate for the three months
ended September 30, 2006 differs from the U.S. statutory rate of 35% due to a property basis
difference relating to disbursements from the disputed claims reserve, subpart F income and
dividends, and earnings in foreign jurisdictions that are taxed at rates lower than the U.S.
statutory rate.
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
NRG classified as discontinued operations the operations and gains/losses recognized on the
sale of projects that were sold or were deemed to have met the required criteria for such
classification pending final disposition. For the three months ended September 30, 2006, NRG
recorded income from discontinued operations of $49 million, net of income tax expense compared to
$10 million for the prior comparable period. For the three months ended September 30, 2006,
discontinued operations consisted of the results of the Companys 100% owned Flinders power
station, Resource Recovery and Audrain. For the third quarter 2005, discontinued operations
consisted of the results of NRG McClain LLC, Northbrook New York, LLC, Northbrook Energy, LLC,
Flinders, Resource Recovery and Audrain. NRG closed the sale of Flinders during the third quarter
2006 and recognized an after-tax gain of approximately $61 million from the sale. Discontinued
operations for the three months ended September 30, 2005 included an $11 million after-tax gain on
the disposition of NRGs Northbrook New York and Northbrook Energy operations.
Managements discussion of the results of operations for the nine months ended September 30,
2006 and 2005
Total operating revenues from majority-owned operations was $4.5 billion for the nine months
ended September 30, 2006, an increase of 160% compared to $1.7 billion for the nine months ended
September 30, 2005. Total operating revenues for the nine months ended September 30, 2006 included
$2.4 billion of energy revenues, a 71% increase over the comparable period in 2005. Of the $2.4
billion in energy revenues, 53% was contracted compared to 14% for
the nine months ended September 30, 2005. This increase was primarily due to the acquisition of NRG Texas. NRG Texas recorded $2.5
billion of total operating revenues for the nine months ended September 30, 2006. Of this amount,
$1.2 billion was energy revenues, of which 80% were contracted. Excluding the results of NRG Texas
and WCP, total operating revenues for the nine months ended September 30, 2006 was $1.9 billion, of
which $1.1 billion were energy revenues, a decrease of $298 million compared to the nine months
ended September 30, 2005. The decline in energy revenues was primarily due to lower generation and
lower power prices in the Northeast region. Total generation in the Northeast region declined by
21% from the comparable period in 2005 reducing energy revenues by $317 million primarily due to
decreased generation demand for NRGs peaking oil-fired and intermediate gas-fired plants, as an
unseasonably mild winter and declining natural gas prices weakened power prices and demand in the
region. Average power prices in NRGs two key New York markets declined by 15% and 17% for the nine
months ended September 30, 2006 compared to the same period in 2005. The decrease in the Northeast
region was partially offset by a $17 million increase from the South Central regions energy
revenues as generation from NRGs South Central plants increased by 12% over the comparable prior
period.
Capacity revenues for the nine months ended September 30, 2006 were $1.1 billion compared to
$416 million for the nine months ended September 30, 2005, an increase of $709 million or 170%. The
increase was largely due to capacity revenues related to NRG Texas of $624 million and WCP of $47
million. Excluding NRG Texas and WCP, capacity revenues increased by $38 million. Capacity revenues
from the Northeast region increased by approximately $35 million due to higher New York capacity
prices and higher rates related to the Connecticut RMR settlement
agreement, the South Central
region also saw increases in capacity revenues of approximately $10 million due to higher contract
rates.
57
Risk management activities resulted in a total derivative gain of $265 million for the nine
months ended September 30, 2006. This was comprised of $35 million in financial revenue losses and
$300 million of mark-to-market gains. The $35 million loss on financial revenues represents the
settled value for the nine months ended September 30, 2006 of financial instruments that do not
qualify for hedge accounting treatment. Of the $300 million of mark-to-market gains, $208 million
represents the change in fair value of forward sales of electricity and fuel, and $76 million
represents the reversal of mark-to-market losses which ultimately settled as financial revenues.
Additionally, NRG recognized a $16 million gain associated with
trading activities. These trading activities primarily support the Northeast and South Central regions assets.
The following table shows NRGs risk management activities that do not qualify for hedge
accounting treatment for the nine months ended September 30, 2006 and 2005.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, 2006 |
|
|
Nine months ended September 30, 2005 |
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
South |
|
|
|
|
|
|
|
(In millions) |
|
Texas |
|
|
Northeast |
|
|
Central |
|
|
All Other |
|
|
Total |
|
|
Northeast |
|
|
Central |
|
|
All Other |
|
|
Total |
|
|
|
|
Net gains/(losses) on settled
positions, or financial revenues |
|
$ |
(14 |
) |
|
$ |
(19 |
) |
|
$ |
1 |
|
|
$ |
(3 |
) |
|
$ |
(35 |
) |
|
$ |
(39 |
) |
|
$ |
(1 |
) |
|
$ |
1 |
|
|
$ |
(39 |
) |
|
|
|
Mark-to-market results |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reversal of previously recognized unrealized
(gains)/losses on settled positions |
|
|
|
|
|
|
76 |
|
|
|
|
|
|
|
|
|
|
|
76 |
|
|
|
(51 |
) |
|
|
|
|
|
|
|
|
|
|
(51 |
) |
Net unrealized gains/(losses) on open
positions related to economic hedges |
|
|
179 |
|
|
|
32 |
|
|
|
(2 |
) |
|
|
(1 |
) |
|
|
208 |
|
|
|
(205 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(206 |
) |
Net unrealized gains/(losses) on open
positions related to trading activity |
|
|
|
|
|
|
(1 |
) |
|
|
17 |
|
|
|
|
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal mark-to-market results |
|
|
179 |
|
|
|
107 |
|
|
|
15 |
|
|
|
(1 |
) |
|
|
300 |
|
|
|
(256 |
) |
|
|
(1 |
) |
|
|
|
|
|
|
(257 |
) |
Total derivative gain/(losses) (a) |
|
$ |
165 |
|
|
$ |
88 |
|
|
$ |
16 |
|
|
$ |
(4 |
) |
|
$ |
265 |
|
|
$ |
(295 |
) |
|
$ |
(2 |
) |
|
$ |
1 |
|
|
$ |
(296 |
) |
|
|
|
(a) 2005 results includes derivative cost of energy
In late 2005 and in 2006, NRG hedged a portion of its 2006 and 2007 Northeast
regions generation. Since that time, the settled and forward prices of electricity have decreased,
resulting in the recognition of mark-to-market forward sales and the settlement of such positions
at reduced losses. Additionally, due to a decline in correlation between gas and power prices, $122
million of hedge accounting ineffectiveness on Texas hedge contracts was recognized. In 2005,
Hurricanes Katrina and Rita disrupted gas production in the Gulf of Mexico causing a strong
increase in natural gas prices resulting in a mark-to-market loss of approximately $206 million.
Since the fourth quarter 2005, gas inventories have risen to levels that are approximately 10%
above the average of the last five years, easing gas supply concerns and reducing forward 2007 gas
prices by approximately 20%.
Cost of Majority-Owned Operations
Cost of majority-owned operations for the nine months ended September 30, 2006 was $2.5
billion or 56% of total operating revenues. Cost of majority-owned operations for the nine months
ended September 30, 2005 was $1.4 billion or 80% of total
operating revenues. The increase was primarily due to the acquisition of NRG Texas and WCP, of which NRG
Texas recorded cost of majority-owned operations of $1.3 billion and WCP recorded $80 million.
Excluding NRG Texas and WCP, cost of majority-owned operations decreased by $231 million, driven
primarily by a $227 million decline in cost of energy to $864 million for the nine months ended
September 30, 2006. This was due to a 21% decrease in generation in the Northeast region which
drove fuel oil and gas costs down by $126 million and $66 million, respectively. Partially
offsetting this decrease was higher coal costs in the Northeast region of $16 million primarily due
to an increase in the cost of coal.
Other operating costs increased by $302 million to $589 million, $285 million related to the
acquisition of NRG Texas and $21 million related to WCP. Excluding the impact of NRG Texas and
WCP, other operating costs were 2% lower than last year. Operating and Maintenance costs benefited
in the second quarter 2006 from an accrual reversal of $18 million related to a favorable court
decision in a station service dispute at NRGs Western New York plants. This accrual reversal was
offset by $12 million of higher major maintenance in the Northeast region related to maintenance
activities to improve plant reliability and additional outage work at
NRGs Oswego plant.
Depreciation and Amortization
NRGs depreciation and amortization expense for the nine months ended September 30, 2006 and
2005 was $443 million and $121 million, respectively. NRG Texas depreciation and amortization made
up $309 million of the $322 million year-over-year increase.
58
General, Administrative and Development
NRGs G&A costs for the nine months ended September 30, 2006 were $220 million compared to
$136 million for the nine months ended September 30, 2005. Corporate costs represented $102 million
or 2% of total operating revenues and $72 million or 4% of total operating revenues for the periods
ended September 30, 2006 and 2005, respectively. G&A costs were adversely impacted by $6 million of
costs associated with the unsolicited acquisition offer by Mirant
Corporation and $11 million of NRG
Texas integration costs, partially offset by lower insurance costs. NRG also incurred a total of
$15 million in development expenses in 2006 to support its recently announced repowering
initiatives. The balance of the total increase in G&A was due to the acquisition of NRG Texas,
which recorded $44 million, and WCP, which recorded $10 million, in G&A costs, excluding
development and integration costs, for the nine months ended September 30, 2006.
Equity in Earnings of Unconsolidated Affiliates
For the nine months ended September 30, 2006, equity earnings from NRGs investments in
unconsolidated affiliates were $46 million compared to $82 million for the nine months ended
September 30, 2005, a decline of 44%. The decline in earnings was largely due to a number of sales
of investments NRG completed over the past year. NRGs earnings in WCP accounted for $15 million of
the decline as the results of WCP were fully consolidated as of March 31, 2006, the date of the
purchase of Dynegys 50% interest. As part of that transaction, NRG sold its 50% interest in the
Rocky Road investment, which accounted for $7 million of the decline in total equity earnings.
Additionally, NRGs Enfield investment, which was sold on April 1, 2005, earned $16 million for the
nine months ended September 30, 2005. Sales of other equity investments in 2006 included James
River, Cadillac and certain Latin American power funds. Declines in equity earnings as a result of
these sales were offset by an approximately $7 million improvement in equity income from NRGs
MIBRAG investment. MIBRAG experienced improved results compared to 2005 as a result of
fewer customer outages and higher prices.
Gains on Sales of Equity Method Investments
During the nine months ended September 30, 2006, NRG sold its interests in James River,
Cadillac, as well as interests in certain Latin American power funds for a pre-tax loss of $6
million, a pre-tax gain of $11 million and a pre-tax gain of $3 million, respectively. For the
nine month ended September 30, 2005, NRG sold its 25% interest in its Enfield investment for a
pre-tax gain of $12 million and its remaining interest in Kendall for a pre-tax gain of $4 million.
Other Income, Net
Other income increased by $77 million or 185% for the nine months ended September 30, 2006 to
$118 million compared to the same period in 2005. Other income in 2006 was favorably impacted by
$67 million of income associated with the settlement with an equipment manufacturer related to
turbine purchase agreements entered into in 1999 and 2001 and $7 million from the favorable
settlement with respect to post closing adjustments on the acquisition of western NY plants in 1998
and 1999. In 2005, NRG recorded a $14 million gain from the settlement related to the Companys
TermoRio project in Brazil and a contingent gain of $4 million related to the sale of a former
project, the Crockett Cogeneration Facility, which was sold in 2002. Other income was also
favorably impacted by $11 million of higher interest income related to higher levels of cash and
more efficient management of cash balances.
Refinancing Expense
Refinancing expenses for the nine months ended September 30, 2006 and 2005 were $178 million
and $54 million, respectively. In the first quarter 2006, NRG acquired NRG Texas for a purchase
price of approximately $6.2 billion. NRG partially financed this purchase through borrowings under
new debt facilities and repaid and terminated previous debt facilities. As a result of this
financing, NRG incurred $178 million of refinancing expenses for the nine months ended September
30, 2006. Of the $178 million, $127 million was related to the premium paid to NRGs previous debt
holders, $34 million for the amortization of a bridge loan commitment entered into on September 30,
2005, and $31 million related to write-offs of deferred financing costs associated with NRGs
previous debt, and a credit of $14 million related to a debt premium write-off.
In the first nine months of 2005, NRG redeemed and purchased a total of approximately $645
million of the Companys Second Priority Notes. As a result of the redemption and purchases, NRG
incurred approximately $54 million in premiums and write-offs of deferred financing costs.
Interest Expense
Interest expense for the nine months ended September 30, 2006 was $420 million compared to
$141 million for the nine months ended September 30, 2005. The increase in interest expense was
primarily due to interest on new debt issued to finance the acquisition of NRG Texas. See Notes 3
and 8 to the condensed consolidated financial statements of this Form 10-Q for a further discussion
of the
59
acquisition and the related financing. As part of the refinancing, NRG replaced its previous
senior secured term loan with a new $3.575 billion senior secured term loan. Additionally, NRG
retired $1.1 billion of its 8% Second Priority Notes and issued $3.6 billion in senior unsecured
notes with a weighted average interest rate of 7.33%.
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 any impact associated with ineffectiveness was immaterial to
NRG financial results. For the nine months ended September 30, 2006, NRG had deferred gains of $10
million in other comprehensive income. See Note 8 to the condensed consolidated financial
statements of this Form 10-Q for a further discussion on these interest rate swaps.
Additionally, NRG designated an existing fixed-to-floating interest rate swap, previously as a
hedge of NRGs 8% Second Priority Notes, into a fair value hedge of the Senior Notes which NRG
closed on February 2, 2006. For the nine months ended September 30, 2006, NRG recognized $3 million
in ineffectiveness associated with this hedge transaction. NRG does not anticipate any
ineffectiveness of this hedge transaction in the future.
Income Tax Expense
Income tax expense was $324 million and $24 million for the nine months ended September 30,
2006 and 2005, respectively. The overall effective tax rate was 35.5% and 120.0% for the nine
months ended September 30, 2006 and 2005, respectively. The effective income tax rate for the nine
months ended September 30, 2006 and 2005 differs from the U.S. statutory rate of 35% due to a
property basis difference relating to disbursements from the disputed claims reserve, subpart F
income and dividends, and earnings in foreign jurisdictions that are taxed at rates lower than the
U.S. statutory rate. NRGs 2005 domestic income tax expense partially offset the low foreign
effective tax rate due to the subpart F inclusion and taxation for the Companys gain on the sale
of Enfield, of approximately $12 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
NRG classified as discontinued operations the income from operations and gains/losses
recognized on the sale of projects that were sold or were deemed to have met the required criteria
for such classification pending final disposition. For the nine months ended September 30, 2006 and
2005, NRG recorded income from discontinued operations, net of income tax expense of $63 million
and $24 million, respectively. Discontinued operations for the nine months ended September 30, 2006
was comprised of the results of Flinders, Audrain and Resource Recovery. Discontinued operations
for the nine months ended September 30, 2005, consisted of the results of the Flinders, Audrain,
Resource Recovery, Northbrook New York LLC, Northbrook Energy LLC and NRG McClain LLC. NRG closed
on the sale of Flinders during the third quarter 2006 and recognized an after-tax gain of
approximately $61 million from the sale. Discontinued operations for the nine months ended
September 30, 2005 included an $11 million gain on the
disposition of NRGs Northbrook New York and
Northbrook Energy operations.
60
Business Segment Results
NRG Energy, Inc.s identified reportable segments are primarily based on geographic areas,
both domestic and foreign. On February 2, 2006, NRG acquired Texas Genco LLC now referred to as NRG
Texas creating a separate segment of operations Wholesale Power Generation Texas.
The following is a detailed discussion of the results of operations of NRGs major wholesale
power generation business segments.
Texas Region
For a discussion of the business profile of the
Texas region, see pages 19-23 of NRG Energy,
Incs. 2005 Annual Report on Form 10-K.
|
|
|
|
|
|
|
|
|
Selected income statement data |
|
Three months ended |
|
|
Period ended |
|
(In millions except otherwise noted) |
|
September 30, 2006 |
|
|
September 30,2006 (a) |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
578 |
|
|
$ |
1,219 |
|
Capacity revenue |
|
|
234 |
|
|
|
624 |
|
Risk Management Activities |
|
|
114 |
|
|
|
165 |
|
Contract amortization |
|
|
219 |
|
|
|
481 |
|
Other revenues |
|
|
6 |
|
|
|
9 |
|
|
Total operating revenues |
|
|
1,151 |
|
|
|
2,498 |
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
406 |
|
|
|
966 |
|
Depreciation and amortization |
|
|
104 |
|
|
|
309 |
|
Other operating expenses |
|
|
129 |
|
|
|
365 |
|
Operating income |
|
$ |
512 |
|
|
$ |
858 |
|
|
MWh sold (in thousands) |
|
|
14,568 |
|
|
|
34,622 |
|
Business Metrics |
|
|
|
|
|
|
|
|
Average on-peak market power prices ($/MWh) |
|
|
61.73 |
|
|
|
71.06 |
|
Cooling Degree Days, or CDDs (b) |
|
|
1,541 |
|
|
|
2,667 |
|
CDDs 30 year rolling average |
|
|
1,599 |
|
|
|
2,456 |
|
Heating Degree Days, or HDDs (b) |
|
|
10 |
|
|
|
1,003 |
|
HDDs 30 year rolling average |
|
|
|
|
|
|
1,382 |
|
|
(a) |
|
For the period February 2, 2006 to September 30, 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. |
Quarterly Results
Operating Income
For the three months ended September 30, 2006, operating income for the Texas region was $512
million. Total generation for the quarter was 14 million MWh, approximately two million more than
generated in the second quarter 2006. The Texas region achieved total sales volumes for the third
quarter 2006 of approximately 14.6 million MWh of which 66% were sold under long-term agreements.
The difference between MWh sold and MWh generated represents MWh
purchased from the marketplace. In July and August, 2006, ERCOT set
new records for peak demand, 62,396 MW on July 17 and
63,056 MW on August 17.
Because of strong operating performance of the regions generating
facilities, NRG Texas was able to fully participate in meeting these
record demands. For the three months ended September 30, 2006,
the Texas regions generating capacity was 96.8 available,
including baseload availability of 99.2%.
Total Operating Revenues
Total operating revenues from the Texas region for the three months ended September 30, 2006
were $1.2 billion. Operating revenues included $578 million in energy revenues of which 66% were
contracted. Capacity revenues totaled $234 million of which $100 million was related to investments
in the STP nuclear generation facility. Additionally, the region recorded $219 million of contract
amortization related to out-of-market power contracts assumed upon the acquisition.
Risk Management Activity The total derivative gain for the quarter was $114 million,
reflecting $78 million of ineffectiveness related to cash flow hedge positions.
Cost of Energy
Cost of energy for the Texas region was $406 million for the three months ended September 30,
2006. Coal and lignite costs were $143 million for the quarter, gas fuel costs were $218 million
and nuclear fuel-related expenses were $14 million. These costs directly relate to the generation
from the Texas regions coal-fired, gas-fired and nuclear-fired units. Coal costs included $36
million of lignite
61
coal used at the Limestone coal plant. Also included in cost of energy were an
emissions allowance expense of $11 million and $23 million in cost contract amortization for the
quarter.
Other Operating Expenses
Other operating expenses for the Texas region for the three months ended September 30, 2006
were $129 million or 11% of the regions total operating revenues. These costs include $86 million
of operating and maintenance costs of which 54% represents normal and major maintenance and $15
million of property tax expense. In addition, the Texas region incurred $29 million of G&A expense,
of which $11 million was related to corporate allocations.
Year-to-date Results
Operating Income
For the period ended September 30, 2006, which includes results since the acquisition date of
February 2, 2006, operating income for the Texas region was $858 million. These results were
largely driven by $624 million of capacity revenues, energy revenues of $1.2 billion, and power
contract amortization of $481 million. The Texas regions total generation for the period was
approximately 33.6 million MWh. Total sales volumes for the period totaled 34.6 million MWh, of
which 73% were sold under long-term sales agreements. NRG Texas purchased approximately 1 million
MWh from the marketplace. For the period ended September 30,
2006, the regions generating facilities was 91.8% available,
including baseload availability of 92.0%.
Total Operating Revenues
Total operating revenues were approximately $2.5 billion for the period ended September 30,
2006. Operating revenues included $1.2 billion in energy revenues of which 80% were contracted.
Capacity revenues were $624 million, of which $261 million was related to the STP nuclear
generation facility. Additionally, the Texas region recorded $481 million of contract amortization
related to out-of-market power contracts assumed upon acquisition.
Risk Management Activity The total derivative gain for the period was $165 million,
reflecting $122 million of ineffectiveness related to cash flow hedge positions.
Cost of Energy
Cost of energy for the Texas region was approximately $1.0 billion for the period. Coal and
lignite costs were $341 million, gas costs were $446 million and nuclear fuel expense was $40
million. These costs represent direct fuel-related costs for the generation of power from the Texas
region. Purchased energy was $49 million, averaging $59 per MWh, acquired to cover contracted
obligations. Also included in cost of energy was an emissions allowance expense of $28 million and
$62 million in coal contract amortization for the period ended September 30, 2006.
Other Operating Expenses
Other operating expenses for the period ended September 30, 2006 were $365 million or 14% of
total operating revenues. This included $241 million of operating and maintenance costs, 53% of
which was related to normal and major maintenance and $45 million of property tax expense. G&A
expense was $81 million for the period, including $36 million of charges related to corporate
allocations.
62
Northeast Region
For a discussion of the business profile of the Northeast region, see pages 23-25 of NRG
Energy, Incs. 2005 Annual Report on Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
(In millions except otherwise noted) |
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
342 |
|
|
$ |
567 |
|
|
|
(40 |
)% |
|
$ |
763 |
|
|
$ |
1,080 |
|
|
|
(29 |
)% |
Capacity revenue |
|
|
98 |
|
|
|
74 |
|
|
|
32 |
|
|
|
247 |
|
|
|
212 |
|
|
|
17 |
|
Risk management activities |
|
|
33 |
|
|
|
(254 |
) |
|
NA |
|
|
88 |
|
|
|
(292 |
) |
|
NA |
Other revenues |
|
|
28 |
|
|
|
52 |
|
|
|
(48 |
) |
|
|
98 |
|
|
|
87 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
501 |
|
|
|
439 |
|
|
|
14 |
|
|
|
1,196 |
|
|
|
1,087 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
233 |
|
|
|
327 |
|
|
|
(29 |
) |
|
|
482 |
|
|
|
670 |
|
|
|
(28 |
) |
Other operating expenses |
|
|
88 |
|
|
|
89 |
|
|
|
(1 |
) |
|
|
273 |
|
|
|
284 |
|
|
|
(4 |
) |
Depreciation and amortization |
|
|
22 |
|
|
|
19 |
|
|
|
16 |
|
|
|
66 |
|
|
|
56 |
|
|
|
18 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
$ |
158 |
|
|
$ |
4 |
|
|
NA |
|
$ |
375 |
|
|
$ |
77 |
|
|
|
387 |
|
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands) |
|
|
4,097 |
|
|
|
5,291 |
|
|
|
(23 |
) |
|
|
10,178 |
|
|
|
12,640 |
|
|
|
(19 |
) |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices
($/MWh) |
|
|
78.90 |
|
|
|
111.81 |
|
|
|
(29 |
) |
|
|
73.20 |
|
|
|
85.83 |
|
|
|
(15 |
) |
Cooling Degree Days, or CDDs(a) |
|
|
1,022 |
|
|
|
1,251 |
|
|
|
(18 |
) |
|
|
1,302 |
|
|
|
1,585 |
|
|
|
(18 |
) |
CDDs 30 year rolling average |
|
|
1,129 |
|
|
|
958 |
|
|
|
18 |
|
|
|
1,338 |
|
|
|
987 |
|
|
|
36 |
|
Heating Degree Days, or HDDs(a) |
|
|
295 |
|
|
|
109 |
|
|
|
171 |
|
|
|
7,208 |
|
|
|
8,159 |
|
|
|
(12 |
) |
HDDs 30 year rolling average |
|
|
101 |
|
|
|
164 |
|
|
|
(38 |
) |
|
|
7,970 |
|
|
|
10,004 |
|
|
|
(20 |
) |
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly Results
Operating Income
Operating income for the Northeast region for the three months ended September 30, 2006
increased by $154 million to $158 million driven largely by
a $287 million improvement in risk
management activities including $202 million in unrealized derivative gains. The third quarter
2005 results included a $167 million loss in unrealized derivative positions driven by the run up
in gas and power prices following Hurricane Katrina. Record gas storage
brought about by mild winter weather pushed gas prices down 37% in the third quarter 2006 versus
the same period in 2005. Power prices followed a similar pattern with Western New York, New York
City, New England and Eastern PJM prices down 32%, 28% 32% and 24% respectively in the third
quarter 2006 compared to the same period in 2005. These lower prices helped give rise to the $33
million gain recorded in the quarter on risk management activities. The decline in energy prices
also explains the 40% or $225 million decline in energy revenues.
The third quarter 2006 started off strong with heat waves in late July and early August
driving new records for peak energy demands in all the regions key markets Weather induced demand
however began to moderate in late August and throughout September 2006. Northeast region
generation fell 1.2 million MWh or 23% in the third quarter 2006 compared to the same period in
2005. Almost 55% of the generation decline was from the regions oil-fired generating units with
declines in coal-fired generation accounting for 30% of the overall decrease. While regional plant
capacity factor of 24% was 6% less than third quarter 2005, the regions baseload coal plants EFOR
improved this quarter from 8.8% to 6.2% due to ongoing investment in plant reliability projects.
Increased capacity revenues of $24 million reflected the continuation of higher capacity
prices in the New York and Connecticut markets compared to the third quarter 2005. Operating income
for the third quarter 2006 benefited from lower cost of energy of approximately $94 million or 29%
compared to the same period in 2005, primarily due to lower generation. Other operating expenses
were in line with the third quarter 2005.
Total Operating Revenues
Total operating revenues from the Northeast region increased by 14% to $501 million for the
three months ended September 30, 2006 compared to $439 million for the three months ended September
30, 2005. Revenues for the three months ended September 30, 2006 included $342 million in energy
revenues compared to $567 million for the three months ended September 30, 2005. This
63
unfavorable
decrease was due to lower generation and lower energy prices. Capacity revenues for the three
months ended September 30, 2006 increased 32% to $98 million compared to $74 million for the three
months ended September 30, 2005. The increase was
primarily due to a new RMR agreement at several of the regions Connecticut facilities at
higher approved rates than those prevailing during the third quarter 2005. In addition, capacity
prices for both In-City and the rest of the state of New York have cleared at higher rates than in the
prior comparable period in 2005 contributing $16 million of the total $24 million increase in
quarterly capacity revenues.
Risk Management Activities
For the three months ended September 30, 2006, the Northeast region
recorded a $33 million gain compared to a $254 million loss in the same period in 2005. The $33
million gain includes a $40 million unrealized gain related to the changes in fair value of forward
derivative positions not qualifying for hedge accounting treatment as compared to a $171 million
loss in the same period in 2005. This $40 million gain includes a $38 million benefit from the
roll-off in the quarter of forward positions existing at end of fiscal year 2005. Risk management activity results in the third quarter 2006 included $7
million in realized losses on settled power positions. This compares with an $87 million loss in the
third quarter 2005.
Other
revenues in the third quarter 2006 of $28 million were down $24 million from the same
period in the prior year. Such revenues in 2005 included $40 million in emission credit sales
revenues. Following active trading of emission allowances in the first and second quarter of 2006,
no similar sales occurred in the third quarter 2006.
Cost of Energy
Cost of energy in the Northeast region was approximately $233 million compared to $327 million
in 2005, a decrease of $94 million or 29%. Oil costs in the Companys Northeast region decreased by
$54 million reflecting reduced generation from the oil-fired
plants. Similarly, gas costs of $94 million decreased by $15 million over the third quarter 2005 primarily due to lower generation from
the New York City plants. Coal costs in the Northeast region decreased by $7 million, also due to
lower generation partially offset by higher coal prices.
Other Operating Expenses
Other operating expenses include O&M expenses, non-income based taxes, and general &
administrative expenses, or G&A. Other operating expenses for the Northeast region were $88 million
for the third quarter 2006 compared to $89 million in the third quarter 2005. For the third quarter
2006, G&A expenses were approximately $21 million compared to approximately $26 million in the
comparable period 2005. This decrease was primarily due to a reduction in corporate allocations as
a result of the inclusion of NRG Texas to the NRG portfolio of $4 million combined with a reduction
in insurance costs of $2 million.
Year-to-date Results
Operating Income
For the nine months ended September 30, 2006, operating income for the Northeast region
increased by 387% to $375 million compared to $77 million for the nine months ended September 30,
2005. This was primarily driven by net forward mark-to-market gains, higher capacity revenues,
and the sale of SO2 emission allowances. The Northeast region recorded a net $88 million
gain associated with forward sales of electricity associated with its risk management activities
compared to a $292 million loss for the same period in 2005. Increased capacity revenues reflected
higher capacity prices for the New York and Connecticut RMR assets compared to the first nine
months of 2005.
Generation in the nine months ended Septem
ber 30, 2006 decreased by 2.5 million MWh or 19%
versus the comparable period in 2005. Generation from the regions oil-based units accounted for
75% of the decrease with declines from the regions Oswego plant alone accounting for 36% of the
overall decrease. Coal-based generation was in line with the third quarter 2005 while gas-fired
generation was down by approximately 0.6 million MWh. Lower generation followed weaker energy
prices where Western New York, New York City, New England and Eastern PJM prices were down 15%, 17%
12% and 11% respectively for the nine months ended September 30, 2006 compared to the same period
in 2005.
Lower generation combined with lower market prices accounted for a 29% decline in energy
revenue to $763 million for the nine months ended September 30, 2006 compared to the same period in
2005. Other revenues of $98 million for the nine months ended September 30, 2006 were positively
impacted by the sale of emission allowances, which contributed approximately $64 million for the
nine months ended September 30, 2006 compared to $42 million for the same period in 2005.
Total Operating Revenues
Total operating revenues for the Northeast region increased by 10% to approximately $1.2
billion for the nine months ended September 30, 2006 compared to $1.1 billion for the nine months
ended September 30, 2005. Revenues for the nine months ended
64
September 30, 2006 included $763
million in energy revenues compared to $1.1 billion for the same period in 2005. Of this $317
million decrease, approximately $210 million and $74 million can be attributed to the regions New
York and New England assets, respectively. Capacity revenues for the
nine months ended September
30, 2006 increased by $35 million or 17% to $247 million compared to $212 million for the prior
comparable period in 2005. This increase was primarily due to $14 million of additional
capacity revenues recorded during the first nine months of 2006 due to higher approved rates
from the Connecticut RMR agreements. In addition, the Northeast region recognized $21 million in
higher capacity revenues from the New York plants as in-City prices have been clearing at higher
rates than the prior comparable period.
Risk
Management Activities For the nine months ended September 30, 2006, gains of
approximately $88 million were recognized compared to losses of approximately $292 million for the
same period in 2005. The $88 million gain included
$107 million unrealized gains related to changes in fair value of forward derivative positions not qualifying for hedge accounting treatment
compared to a $256 million loss in the same period in 2005. This $107 million gain includes a $76
million net benefit from the roll-off in the nine month period ended September 30, 2006 of forward
positions associated with risk management activities existing at the end of fiscal year 2005. The $88 million gain
in risk management activities included
a $19 million realized loss on settled power positions.
Other revenues increased by 13% to $98 million for the first nine months of 2006 compared to
$87 million for the same period in 2005. During the first half of 2006, the Northeast region
realized $64 million in emission allowance sales compared to $42 million in the first nine months
of 2005.
Cost of Energy
Cost of energy in the Northeast region decreased by 28% to $482 million for the nine months
ended September 30, 2006 compared to $670 million for the same period in 2005. This was primarily
due to lower generation from the New York City and Connecticut plants, which reduced oil and gas
costs by approximately $126 million and $66 million, respectively. These costs were partially
offset by higher coal costs of approximately $16 million to $235 million, an increase of 8% over
the comparable prior period in 2005 due to higher coal prices.
Other Operating Expenses
Other operating expenses for the Northeast region were $273 million for the nine months ended
September 30, 2006 compared to $284 million for the nine months ended September 30, 2005.
Maintenance expenditures were $16 million higher this period than the prior comparable period,
which more than offset an $18 million accrual reversal related to a favorable court decision
related to station service obligations at the Western New York plants. Corporate allocations were
lower by $12 million over the prior comparable period due to the inclusion of NRG Texas to the NRG
portfolio. Property taxes were $5 million higher than the prior comparable period due to the
reduction of property tax credit from the State of New York which was offset by lower insurance
expense of $6 million.
65
South Central Region
For a discussion of the business profile of the South Central region, see pages 25-27 of NRG
Energy, Incs. 2005 Annual Report on Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three
months ended September 30, |
|
|
Nine months ended September 30, |
|
(In millions except otherwise noted) |
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
86 |
|
|
$ |
101 |
|
|
|
(15 |
) |
|
$ |
247 |
|
|
$ |
230 |
|
|
|
7 |
|
Capacity revenue |
|
|
50 |
|
|
|
46 |
|
|
|
9 |
|
|
|
147 |
|
|
|
137 |
|
|
|
7 |
|
Risk Management Activities |
|
|
12 |
|
|
|
|
|
|
NA |
|
|
16 |
|
|
|
|
|
|
NA |
Contract amortization |
|
|
5 |
|
|
|
5 |
|
|
|
|
|
|
|
13 |
|
|
|
11 |
|
|
|
18 |
|
Other revenues |
|
|
12 |
|
|
|
23 |
|
|
|
(48 |
) |
|
|
8 |
|
|
|
23 |
|
|
|
(65 |
) |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
165 |
|
|
|
175 |
|
|
|
(6 |
) |
|
|
431 |
|
|
|
401 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
98 |
|
|
|
141 |
|
|
|
(30 |
) |
|
|
237 |
|
|
|
279 |
|
|
|
(15 |
) |
Other operating expenses |
|
|
19 |
|
|
|
24 |
|
|
|
(21 |
) |
|
|
66 |
|
|
|
75 |
|
|
|
(12 |
) |
Depreciation and amortization |
|
|
15 |
|
|
|
15 |
|
|
|
|
|
|
|
45 |
|
|
|
45 |
|
|
|
|
|
Operating income/(loss) |
|
$ |
33 |
|
|
$ |
(5 |
) |
|
NA |
|
$ |
83 |
|
|
$ |
2 |
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands) |
|
|
3,526 |
|
|
|
2,734 |
|
|
|
29 |
|
|
|
9,319 |
|
|
|
7,398 |
|
|
|
26 |
|
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices
($/MWh) |
|
|
61.56 |
|
|
|
86.58 |
|
|
|
(29 |
) |
|
|
57.52 |
|
|
|
64.30 |
|
|
|
(11 |
) |
Cooling Degree Days, or CDDs(a) |
|
|
1,541 |
|
|
|
1,626 |
|
|
|
(5 |
) |
|
|
2,667 |
|
|
|
2,563 |
|
|
|
4 |
|
CDDs 30 year rolling average |
|
|
1,599 |
|
|
|
1,503 |
|
|
|
6 |
|
|
|
2,456 |
|
|
|
1,939 |
|
|
|
27 |
|
Heating Degree Days, or HDDs(a) |
|
|
10 |
|
|
|
2 |
|
|
|
400 |
|
|
|
1,003 |
|
|
|
1,178 |
|
|
|
(15 |
) |
HDDs 30 year rolling average |
|
|
|
|
|
|
1 |
|
|
NA |
|
|
1,382 |
|
|
|
1,902 |
|
|
|
(27 |
) |
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly Results
Operating Income
Operating income for the South Central region was up $38 million for the third quarter 2006
compared to the same period in 2005. The regions results were helped by strong operating
performance at the Big Cajun II coal plant and tolling agreements. The Big Cajun II plant achieved
an EFOR rate of 2.2% for the quarter, compared to the plants EFOR rate of 7.9% in the third
quarter 2005. The region also benefited from improved results in its risk management activities.
Total Operating Revenues
Total operating revenues for the third quarter 2006 decreased by $10 million, or 6%, compared
to the third quarter 2005 primarily due to lower energy revenues, which declined by approximately
$15 million. Energy sold to the regions contract customers
increased by 112,000 MWh which resulted in a $4 million increase in contract energy revenues. Merchant energy revenues
dropped by $20 million due to falling power prices and the
impact of the netting energy
purchases and resales under EITF 02-3. Average on-peak energy prices in the SERC Entergy region
declined by 29% from the third quarter 2005 primarily due to the impact of Hurricane Katrina and
the warm summer of 2005. Capacity revenue increased by approximately $4 million due to higher billing
peaks for the regions cooperative contract customers. The cooperatives set a new summer peak of
2,011 megawatts on August 15, 2006. The increase in the regions risk management activities was
primarily due to mark-to-market gains related to a contract with a counterparty.
Cost of Energy
South Centrals cost of energy decreased by $43 million for the three months ended September
30, 2006 compared to the same period in 2005. The decrease was due to
declining purchased power
prices, fewer unplanned outages at the regions base-load coal plants in 2006, and to the impact of
netting energy purchases and resales per EITF 02-3. Also, the third
quarter 2005 results included the impacts of
Hurricane Katrina, which drove up natural gas costs. Coal cost increased by $11
million due to higher generation at the regions coal plants. Plant generation increased 10% over
the third quarter 2005. The regions tolling agreements provided an additional 0.9 million MWh of
energy to support the regions load contracts and merchant sales.
66
Other Operating Expenses
Other operating expenses decreased by approximately $5 million during the third quarter 2006
compared to the third quarter 2005. Normal maintenance decreased by $1 million compared to the
third quarter 2005 due to lower expenditures for boiler tube maintenance and substation
maintenance. Major maintenance was also down $1 million because of lower spending on various
projects, including river cell repairs. Corporate allocations decreased by $2 million in the third
quarter 2006 compared to the third quarter 2005 as a result of the inclusion of NRG Texas in the
NRG portfolio.
Year-to-date Results
Operating Income
Operating income for the nine months ended September 30, 2006, was up $81 million from the
same period in 2005. This reflected better availability of the regions baseload coal plants,
increased use of tolling agreements, and gains from the regions risk management activities. The
regions Big Cajun II coal plants performance was significantly better through the first nine
months of 2006 than in the same period in 2005 as a result of a reduced number of forced outage
hours from 1,289 in 2005 to 355 in 2006.
Total Operating Revenues
The regions energy revenue increased by $17 million primarily due to higher MWh sales to
contract customers. Sales to cooperative customers were up by approximately 418,000 MWh and sales
to other contract customers increased by approximately 48,000 MWh. The increased sales were driven
by warmer weather, especially in the first half of 2006. Cooling
degree days through September 30, 2006
were up by 333 days, while heating degree days were down 90 days compared to the first nine months
of 2005. Capacity revenue increased by approximately $10 million because billing peaks set by the
cooperative customers in the summer of 2005 were incorporated into 2006 capacity rates.
Cost of Energy
Cost of energy for the nine months ended September 30, 2006 decreased by 15%, or $42 million
compared to the same period in 2005. Coal costs increased by approximately $20 million, reflecting
an 11% increase in plant generation. Natural gas and purchase power costs declined by approximately
$63 million, primarily due to higher coal plant availability and increased utilization of the
regions tolling agreements which reduced the need to purchase energy to support contract load
requirements. Transmission costs were up by approximately $5 million as a result of higher contract
customer peaks and higher Entergy transmission tariffs.
Other Operating Expenses
For the nine months ended September 30, 2006, other operating expenses decreased by
approximately $9 million from the same period in 2005. Normal maintenance decreased by
approximately $1 million as better plant availability translated into lower expenditures for tube
leaks and other forced outage items. Major maintenance also dropped by approximately $1 million due
to project scheduling associated with the regions long-term maintenance plan. Corporate
allocations declined by approximately $6 million as a result of the inclusion of NRG Texas in the
NRG portfolio. These decreases were partially offset by an increase of approximately $1 million in
external consulting expense related to the regions development projects.
67
West Region
For
a discussion of the business profile of the West region, see pages 27-31 of NRG Energy,
Incs. 2005 Annual Report on Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended September 30, |
|
|
Nine months ended September 30, |
|
(In millions except otherwise noted) |
|
2006 |
|
|
2005 |
|
|
Change % |
|
|
2006 |
|
|
2005 |
|
|
Change |
|
|
Operating Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Energy revenue |
|
$ |
31 |
|
|
$ |
1 |
|
|
NA |
|
$ |
58 |
|
|
$ |
1 |
|
|
NA |
Capacity revenue |
|
|
27 |
|
|
|
|
|
|
NA |
|
|
47 |
|
|
|
|
|
|
NA |
Risk management activities |
|
|
(2 |
) |
|
|
|
|
|
NA |
|
|
(3 |
) |
|
|
|
|
|
NA |
Other revenues |
|
|
3 |
|
|
|
|
|
|
NA |
|
|
6 |
|
|
|
|
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
Total operating revenues |
|
|
59 |
|
|
|
1 |
|
|
NA |
|
|
108 |
|
|
|
1 |
|
|
NA |
|
|
|
|
|
|
|
|
|
|
|
Operating Costs and Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of energy |
|
|
33 |
|
|
|
1 |
|
|
NA |
|
|
59 |
|
|
|
1 |
|
|
NA |
Other operating expenses |
|
|
16 |
|
|
|
1 |
|
|
NA |
|
|
33 |
|
|
|
4 |
|
|
NA |
Depreciation and amortization |
|
|
|
|
|
|
|
|
|
NA |
|
|
1 |
|
|
|
|
|
|
NA |
Operating income/(loss) |
|
$ |
10 |
|
|
$ |
(1 |
) |
|
NA |
|
$ |
15 |
|
|
$ |
(4 |
) |
|
NA |
|
|
|
|
|
|
|
|
|
|
|
MWh sold (in thousands) |
|
|
718 |
|
|
|
4 |
|
|
NA |
|
|
1,966 |
|
|
|
6 |
|
|
NA |
Business Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average on-peak market power prices
($/MWh) |
|
|
69.71 |
|
|
|
80.68 |
|
|
|
(14 |
) |
|
|
59.10 |
|
|
|
62.75 |
|
|
|
(8 |
) |
Cooling Degree Days, or
CDDs(a) |
|
|
640 |
|
|
|
568 |
|
|
|
13 |
|
|
|
880 |
|
|
|
719 |
|
|
|
22 |
|
CDDs 30 year rolling average |
|
|
574 |
|
|
|
481 |
|
|
|
19 |
|
|
|
731 |
|
|
|
539 |
|
|
|
36 |
|
Heating Degree Days, or
HDDs(a) |
|
|
52 |
|
|
|
53 |
|
|
|
(2 |
) |
|
|
1,921 |
|
|
|
1,847 |
|
|
|
4 |
|
HDDs 30 year rolling average |
|
|
68 |
|
|
|
122 |
|
|
|
(44 |
) |
|
|
2,041 |
|
|
|
2,584 |
|
|
|
(21 |
) |
|
(a) |
|
National Oceanic and Atmospheric Administration-Climate Prediction Center A CDD
represents the number of degrees that the mean temperature for a particular day is above 65
degrees Fahrenheit in each region. An HDD represents the number of degrees that the mean
temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs
for a period of time are calculated by adding the CDDs/HDDs for each day during the period. |
Quarterly and Year-to-date Results
Operating Income
For the three and nine months ended September 30, 2006, operating income for the West region
was approximately $10 million and $15 million respectively, compared to a loss of $1 million and $4
million for the three and nine months ended September 30, 2005. This gain in operating income was
entirely due to NRGs acquisition of Dynegys 50% interest
of WCP. The California high-voltage power grid handled an all time
record peak demand on July 24, 2006 at 50,270 MW, with the
previous record peak demand of 45,431 MW set on July 20, 2005.
Total Operating Revenues
Total operating revenues from the West region was approximately $59 million, comprised of $31
million in energy revenues, and $27 million of capacity revenues for the three months ended
September 30, 2006. Total operating revenues for the nine months ended September 30, 2006 was $108
million, comprised of $58 million in energy revenues and $47 million in capacity revenues. This
compares to $1 million in energy revenues for the three and nine months ended September 30, 2005.
Cost of Energy
Cost of energy for the three and nine months ended September 30, 2006, was approximately $33
million and $59 million, respectively. For the three and nine months ended September 30, 2005, cost of energy
for the West region was $1 million.
Other Operating Expenses
Operating expenses for the West region for the three and nine months ended September 30, 2006
was $16 million and $33 million, respectively. This compares to $1 million and $4 million for the
three and nine months ended September 30, 2005.
68
Liquidity and Capital Resources
Significant Events during the nine months ended September 30, 2006
Acquisitions and Dispositions
|
|
|
The acquisition of Texas Genco LLC of $6.2 billion. |
|
|
|
|
Net proceeds of approximately $239 million and a net after-tax gain of approximately $71
million recognized from the sale of Flinders and Audrain. |
|
|
|
|
Proceeds of approximately $86 million from the sale of non-core assets. |
|
|
|
|
The purchase of the remaining 50% interest in WCP and sale of NRGs 50% interest
in Rocky Road for a net $160 million. |
Financings
|
|
|
The issuance of approximately $147 million of notes and $50 million of preferred
interests by unrestricted subsidiaries to partially fund the purchase of $297 million of
NRGs common stock pursuant to a Capital Allocation Program
announced on August 1, 2006. |
|
|
|
|
The issuance of $5.6 billion in a new credit facility, including a $1 billion revolving
credit facility and $1 billion synthetic letter of credit facility; $3.6 billion in
unsecured high yield notes; $500 million of 5.75% Preferred Stock; and $1 billion of common
stock. |
|
|
|
|
The termination of NRG term loan, funded letter of credit and
revolving credit facilities issued on December 24, 2004. |
|
|
|
|
The repurchase of $1.1 billion in aggregate principal
amount of NRGs 8% Second Priority Notes. |
|
|
|
|
The repurchase of $1.1 billion in aggregate principal amount of NRG Texass and Texas
Genco Financing Corp.s 6.875% senior notes. |
|
|
|
|
The return of cash collateral payments of $349 million due to the downward shift in the
underlying price curves and settlement of trades. |
Liquidity Position
As of September 30, 2006, NRG Energy, Inc.s liquidity was approximately $2.4 billion and
included approximately $1.5 billion of unrestricted and restricted cash. NRGs liquidity also
included $843 million of borrowing capacity under the Companys revolving line of credit, and $142
million of availability under the Companys letter of credit facility. As of December 31, 2005,
NRGs liquidity was $730 million and included
$542 million of unrestricted and restricted cash. The
Companys year-end liquidity also included $150 million of available capacity under the Companys
revolving line of credit and $38 million of availability under the Companys letter of credit
facility.
Capital Allocation Strategy
NRGs capital allocation philosophy includes reinvestment in its core facilities, maintenance
of prudent debt levels and interest coverage, the regular return of capital to shareholders and
investment in repowering opportunities. Each of these components is described further as follows:
|
|
|
Reinvestment in Existing Assets Opportunities to invest in the existing business,
including maintenance and environmental capital expenditures that improve operational
performance, ensure compliance with environmental laws and regulations, or expand projects. |
|
|
|
|
Management of Debt Levels The Company uses several metrics to measure the efficiency of
its capital structure and debt balances. Generally, the Companys targeted net debt to
total capital ratio range is 45% to 60%. The Company intends to in the normal course of
business to continue to manage its debt levels towards the lower end of the range and may,
from time to time, pay down its debt balances for a variety of reasons. |
|
|
|
|
Return of Capital to Shareholders The Companys debt instruments include restrictions
on the amount of capital that can be returned to shareholders. The Company has in the past
returned capital to shareholders while maintaining compliance with existing debt agreements
and indentures. The Company expects to regularly return capital either through dividends or
share repurchases to shareholders. |
|
|
|
|
Repowering Opportunities The Company intends to pursue repowering initiatives that
enhance and diversify its portfolio and provide a targeted economic return to the Company. |
Capital Allocation Program
During the third quarter 2006, NRG initiated a plan, known as the Capital Allocation Program, to
repurchase approximately $750 million of its common stock. Phase I was a $500 million stock repurchase program, which
was completed on October 13, 2006. Phase II, as originally announced, was to be an additional $250
million common stock buyback anticipated to commence during the first quarter 2007. NRG
69
has upsized
Phase II to $500 million and has accelerated the start to the fourth quarter 2006 and is expected
to be completed by the end of the second quarter 2007.
To
implement Phase I, the Company formed two wholly-owned unrestricted subsidiaries to repurchase shares of
NRGs common stock in the public markets or in privately negotiated transactions. These
subsidiaries were funded with a combination of approximately $166 million in cash from NRG,
together with the proceeds from the issuance of approximately $250 million in notes and
approximately $84 million in preferred stock to Credit Suisse, for a total amount of approximately
$500 million. As of September 30, 2006, the total amount of notes and preferred interests issued
and outstanding was approximately $147 million and $50 million, respectively. Both the notes and
the preferred interests will mature in two tranches: $137.5 million in notes and $53 million in
preferred interests will mature in October 2008, and $112.5 million in notes and $31 million in
preferred interests will mature in October 2009.
As of September 30, 2006, NRG through its two wholly-owned unrestricted subsidiaries had
purchased approximately 6.1 million of its common stock at an average price of $48.61 per share for
a total amount of approximately $297 million. On October 13, NRG completed Phase I of the program
with total common stock repurchased of 10,587,700 common shares at an average price of $47.22 for
approximately $500 million.
Australia
On August 30, 2006, NRG announced the completion of the sale of its 100% owned Flinders power
station and related assets or Flinders, located near Port Augusta, Australia, to Babcock & Brown
Power Pty, a subsidiary of Babcock & Brown, a global investment and advisory firm. Proceeds from
the sale were approximately $242 million (AU$317 million). The sale resulted in the elimination of
approximately $370 million (AU$485 million) of consolidated liabilities including approximately
$183 million (AU$240 million) of non-recourse debt obligations and approximately $92 million
(AU$121 million) in non-current liabilities related to the obligations for the purchase of
electricity and the supply of fuel to the Osborne power station that were guaranteed by NRG. NRG
recognized an after-tax gain of approximately $61 million from the sale.
Acquisition of Texas Genco and Related Financing
On February 2, 2006, NRG acquired Texas Genco LLC, pursuant to an Acquisition Agreement dated
September 30, 2005. The purchase price of approximately $6.2 billion consisted of approximately
$4.4 billion in cash, the issuance of approximately 35.4 million shares of NRGs common stock
valued at approximately $1.7 billion and acquisition costs of approximately $0.1 billion. This
amount may be subject to an adjustment due to additional acquisition costs. The value of NRGs
common stock issued to the Sellers was based on the Companys average stock price immediately
before and after the closing date of February 2, 2006. The acquisition also included the assumption
of approximately $2.7 billion of Texas Genco LLC debt. In connection with the acquisition, NRG
substantially revised its financial structure.
The acquisition of Texas Genco LLC and the related financial restructuring was funded with (i)
cash proceeds received upon the issuance and sale in a public offering of 20,855,057 shares of NRG
common stock at a price of $48.75 per share; (ii) cash proceeds received upon the issuance and sale
of $1.2 billion aggregate principal amount of 7.25% Senior Notes due 2014 and $2.4 billion
aggregate principal amount of 7.375% Senior Notes due 2016; (iii) cash proceeds received upon the
issuance and sale in a public offering of 2 million shares of mandatory convertible preferred stock
at a price of $250 per share; (iv) funds borrowed under a new senior secured credit facility
consisting of a $3.575 billion term loan facility, a $1.0 billion revolving credit facility and a
$1.0 billion synthetic letter of credit facility; and (v) cash on hand.
On January 31, 2006, NRG used proceeds from the issuance of common stock and cash on hand to
repay the $446 million outstanding principal balance of the Companys senior secured term loan
facility, along with accrued but unpaid interest of approximately $2 million and terminated the
facility. On February 2, 2006, NRG used proceeds from the new debt financing to pay accrued but
unpaid fees on the Companys revolving credit facility and funded letter of credit facility, and
terminated those facilities. Those facilities were replaced by the new term loan, letter of credit
and revolving financing facilities as of February 2, 2006.
NRGs previously outstanding 8% Second Priority Notes of approximately $1.2 billion were
repurchased by NRG on February 2, 2006 and previously outstanding Texas Genco Notes of
approximately $1.2 billion were purchased by NRG on February 3, 2006, with proceeds from the
issuance of new unsecured high yield notes.
As of September 30, 2006, NRG had $3.6 billion in aggregate principal amount of unsecured high
yield notes or Senior Notes and approximately $3.6 billion in principal amount outstanding under
the term loan and had issued $858 million of letters of credit under the Companys $1 billion
funded letter of credit facility, leaving $142 million available for future issuances. Under the
Companys $1 billion revolving facility, as of September 30, 2006, NRG had issued $157 million in
letters of credit, leaving $843 million available for borrowings, of which approximately $143
million could be used to issue additional letters of credit. As of November 1, 2006, $160 million
of undrawn letters of credit remain available under the funded letter of credit facility, $143
million of undrawn letters of credit remain available under the revolving credit facility, and NRG
had no borrowings on the Companys revolving credit facility.
70
Collateral
In connection with the Companys power generation business, NRG manages the commodity price
risk associated with the Companys supply activities and electric generation facilities. This
includes forward power sales, fuel and energy purchases and
emission allowances. In order to manage these risks, NRG enters into financial instruments to
hedge the variability in future cash flows from forecasted sales of electricity and purchases of
fuel and energy. NRG utilizes a variety of instruments including forward contracts, futures
contracts, swaps and options. Certain of these contract counterparties require NRG to post margin
collateral. As of November 1, 2006, NRG had posted $113 million in collateral to support these
contracts.
In March 2004, NRG entered into two interest rate swap agreements, one of which matured on
March 31, 2006. The remaining swap agreement matures in 2011. Depending on market interest rates,
NRG or the swap counterparty may be required to post collateral on a daily basis in support of this
swap, to the benefit of the other party. On September 30, 2006 and November 1, 2006, NRG had posted
approximately $12 million and $11 million, respectively, in collateral.
Second Lien Structure
NRG has granted second priority liens on substantially all of its assets in the United States
in order to secure obligations under certain power sale agreements and related hedges. 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.
As of October 31, 2006, the net discounted exposure on the agreements and hedges that were subject to the
second lien structure was approximately $905 million.
The following table summarizes the utilization of the second lien structure as of October 31,
2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equivalent Net Sales secured by Second Lien Structure (a) |
|
2006 (b) |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
2011 |
|
In MW |
|
|
2,062 |
|
|
|
3,402 |
|
|
|
3,421 |
|
|
|
3,766 |
|
|
|
2,875 |
|
|
|
3,353 |
|
As a percentage of net baseload capacity in collateral pool |
|
|
30 |
% |
|
|
49 |
% |
|
|
49 |
% |
|
|
54 |
% |
|
|
41 |
% |
|
|
48 |
% |
|
(a) Equivalent Net Sales include natural gas swaps converted using a weighted average heat rate by region.
(b) 2006 MW value consists of November and December positions only.
NOLs and Deferred Tax Assets
As of September 30, 2006 NRG had U.S. domestic net operating loss carryforward of $271 million
which will expire through 2026, including $15 million of NOL which is eligible for carryback to
prior periods. NRG believes that it is more likely than not that a benefit will be realized on
the deferred tax assets relating to the net operating loss carryforwards. This assessment included
consideration of positive and negative factors, including NRGs current financial position, results
of operations, projected future taxable income, including projected operating and capital gains,
and available tax planning strategies. As of September 30, 2006, no valuation allowance was
recorded against deferred tax assets relating to net operating loss carryforwards with any
pre-existing valuation allowance relating to any net operating loss
carryforwards reversed.
71
Discussion of Known Trends
Repowering Initiative
On June 21, 2006, NRG announced a comprehensive portfolio redevelopment effort, which involves
the development, financing, construction and operation of up to 10,000 megawatts of new multi-fuel,
multi-technology generation capacity at NRGs existing domestic sites to meet the growing demand in
all of the Companys core domestic markets. Through this repowering initiative, NRGs total
generation could potentially increase from approximately 22,800 MW to 32,800 MW for a total cost of
up to $16 billion. Both the increase in NRGs generation and NRGs share of the costs are dependent
upon a number of factors, including successfully obtaining required permits and off-take agreements
and achieving targeted project economics. In addition, NRG expects to mitigate the capital cost of its repowering
initiative through sell-downs of equity and public-private partnerships. The Company also expects
to charge development fees to equity partners. To mitigate the investment risks, NRG anticipates
entering into long-term PPAs and EPC contracts. The Company currently expects its share of cash
contributions for the repowering investments to be between $500 million and $1.5 billion.
The total 10,000 MW increase based on fuel type is as follows:
|
|
|
|
|
Fuel Type |
|
Megawatts |
|
Gas |
|
|
2,800 |
|
Nuclear |
|
|
2,700 |
|
Coal Gasification, or IGCC |
|
|
2,250 |
|
Solid Fuel |
|
|
1,800 |
|
Wind |
|
|
450 |
|
|
Total |
|
|
10,000 |
|
|
Capital Expenditures
Capital expenditures were approximately $159 million and $46 million for the nine months ended
September 30, 2006 and 2005, respectively. Of these amounts, environmental capital expenditures for
the nine months ended September 30, 2006 and 2005 were approximately $9 million and $16 million,
respectively. Capital expenditures for the fourth quarter 2006 are expected to be approximately $56
million of which $4 million will be related to environmental capital expenditures.
NRG has estimated that approximately $1.3 billion of environmental capital expenditures will
be incurred during the period 2007 through 2012, primarily related to installation of particulate,
SO2, NOX, and mercury controls to comply with the CAIR and Clean
Air Mercury rules, as well as installation of BTA under the Phase II 316(b) Rule. NRG currently
updates its estimates for environmental capital expenditures annually, and these estimates can be
expected to change over time, in some cases materially.
The following table summarizes the estimated environmental capital expenditures for the
referenced period, by region and by year:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
( In millions) |
|
Texas |
|
Northeast |
|
South Central |
|
Other |
|
Total |
|
Periods: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
10 |
|
|
|
118 |
|
|
|
40 |
|
|
|
9 |
|
|
|
177 |
|
2008 |
|
|
13 |
|
|
|
174 |
|
|
|
92 |
|
|
|
10 |
|
|
|
289 |
|
2009 |
|
|
23 |
|
|
|
206 |
|
|
|
179 |
|
|
|
5 |
|
|
|
412 |
|
2010 |
|
|
26 |
|
|
|
138 |
|
|
|
86 |
|
|
|
4 |
|
|
|
255 |
|
2011 |
|
|
19 |
|
|
|
27 |
|
|
|
52 |
|
|
|
1 |
|
|
|
99 |
|
2012 |
|
|
13 |
|
|
|
5 |
|
|
|
34 |
|
|
|
|
|
|
|
52 |
|
|
Total |
|
|
103 |
|
|
|
669 |
|
|
|
481 |
|
|
|
29 |
|
|
|
1,284 |
|
|
NRG is working to reduce or mitigate a portion of the above environmental capital
expenditures. To date, two potential mitigants have been identified.
First, NRG has the ability to
monetize a portion of the Companys excess emission allowances over the 2007-2012 timeframe and
still leave sufficient credits to operate the fleet at existing levels through 2020. Secondly,
NRGs current contracts with its rural electrical customers in the South Central region allow
recovery of up to approximately 93% of costs incurred by complying with new laws, including
interest over the asset life of the required expenditure for the duration of the contracts. Actual
recoveries may be less and will depend, among other things, on the
duration of the contracts and the
treatment of the expenditures.
72
Hedge Reset and Extension
On November 3, 2006, NRG announced its intention to enter into a series of transactions that
includes (i) the reset of existing out-of-the-money hedges for years 2006 through 2010 to market, (ii)
substantial new baseload hedges for the years 2010 and 2011 and, possibly, later years, (iii) the
issuance of $1.1 billion of new high yield notes and (iv) amendments to NRGs existing
Senior Credit Facility, including the increase of the synthetic letter of credit facility
by $500 million.
Resetting of Existing Hedges, or Hedge Reset NRG has entered
into amendments of certain existing hedge agreements for the years 2006 through 2010, including
hedge agreements with J. Aron & Company. These hedges were gas swaps and power contracts that were
acquired as part of the acquisition of Texas Genco LLC, which closed on February 2, 2006. These hedges
were entered into by Texas Genco at a time when power and natural gas prices were lower than
they are today, and as a result, the hedges obligate NRG to sell power or natural gas at prices
significantly below current market prices. Under the amended agreements, NRG has reset the pricing
of these hedges to reflect current market prices, and has agreed to pay cash to the hedge
counterparties in amounts that reflect a negotiated present value of the difference between the
original prices in the hedges and the amended prices. The total amount to be paid to the
counterparties is expected to be approximately
$1.35 billion.
The Hedge Reset will provide the flexibility through NRGs
second lien structure to expand its hedges on baseload generation for an
extended period, and will improve the Companys cash flows and credit profile which will contribute to the
Companys ability to amend its existing Senior Credit Facility, as described below.
The following table summarizes the Texas regions percentage of hedged baseload capacity and
the corresponding revenues (excluding revenues from contract
amortization) resulting from baseload hedge agreements that were contracted by Texas
Genco LLC and assumed by NRG as of February 2, 2006 compared to the revenues (excluding revenues from contract
amortization) expected from the
hedges following the Hedge Reset:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December |
|
|
|
|
|
|
|
|
|
|
|
|
|
(In million unless otherwise stated) |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
Texas Region Net Baseload Capacity (MW) |
|
|
5,294 |
|
|
|
5,340 |
|
|
|
5,340 |
|
|
|
5,340 |
|
|
|
5,340 |
|
Texas Region Baseload Sales (MW)(a) |
|
|
4,575 |
|
|
|
4,267 |
|
|
|
4,157 |
|
|
|
3,449 |
|
|
|
1,395 |
|
Percentage
Baseload Capacity Sold Forward(b) |
|
|
86 |
% |
|
|
80 |
% |
|
|
78 |
% |
|
|
65 |
% |
|
|
26 |
% |
|
As of Acquisition: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Forward Price
($/MWh)(c) |
|
$ |
43 |
|
|
$ |
39 |
|
|
$ |
41 |
|
|
$ |
47 |
|
|
$ |
51 |
|
Total
Forward Hedged Revenues (c) |
|
|
146 |
|
|
|
1,443 |
|
|
|
1,505 |
|
|
|
1,434 |
|
|
|
621 |
|
After Reset: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Forward Price
($/MWh)(c) |
|
|
51 |
|
|
|
56 |
|
|
|
54 |
|
|
|
57 |
|
|
|
55 |
|
Total
Forward Hedged Revenues (c) |
|
|
173 |
|
|
|
2,103 |
|
|
|
1,963 |
|
|
|
1,707 |
|
|
|
723 |
|
|
Increase in Forward Hedged Revenues due to
Hedge Reset |
|
$ |
27 |
|
|
$ |
660 |
|
|
$ |
458 |
|
|
$ |
273 |
|
|
$ |
102 |
|
|
|
|
|
(a) |
|
Includes amounts under fixed price power sales contracts and financially
hedged under natural gas swap contracts. The forward natural gas swap quantities are reflected
in equivalent MWh and are derived by first dividing the quantity of MMBtu of natural gas
hedged by the forward market heat rate as of December 30, 2005 to arrive at the equivalent MWh
hedged which is then divided by 8,760 hours (total hours in a year) to arrive at MW hedged. |
|
(b) |
|
Percentage hedged is based on total MWh sold as power and gas converted using the method as
described in (a) above divided by the net capacity. The net capacity excludes loss in
generation from expected forced outages and in generation from forecasted market
uncertainties. |
|
(c) |
|
Includes amounts under fixed price power sales contracts and financially hedged under natural
gas swap contracts. |
Based on the table above, due to the
Hedge Reset of the Texas regions hedges that were
outstanding as of February 2, 2006, revenues (exclusively revenues from contract amortization) during the period
December 2006-2011 will increase by approximately $1.5 billion.
New
Hedges NRG has entered into, and will continue to enter into, new forward natural gas
swaps contracts for the years 2010 and 2011, in order to hedge future power prices with respect to
NRGs baseload power generation facilities in those years. As appropriate market opportunities
arise, NRG will extend the hedging program to later years. As a result of these transactions, NRG
will be significantly more hedged with respect to its baseload power generation through 2011. NRGs
obligations under the New Hedges and Hedge Reset are or will be secured by second liens on substantially
all of the assets of NRG and its subsidiaries, pursuant to NRGs existing second lien structure.
73
The
following table summarizes NRGs total baseload capacity and the
corresponding revenues (excluding revenues from contract amortization) resulting from baseload hedge agreements extending beyond December 2006 through 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual |
|
|
|
December |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average for |
|
(In million unless otherwise stated) |
|
2006 |
|
|
2007 |
|
|
2008 |
|
|
2009 |
|
|
2010 |
|
|
2011 |
|
|
2007-2011 |
|
|
NRG Net Baseload Capacity (MW) |
|
|
8,660 |
|
|
|
8,660 |
|
|
|
8,660 |
|
|
|
8,660 |
|
|
|
8,660 |
|
|
|
8,660 |
|
|
|
8,660 |
|
NRG Baseload Sales (MW)(a) |
|
|
6,270 |
|
|
|
6,691 |
|
|
|
5,766 |
|
|
|
5,002 |
|
|
|
3,614 |
|
|
|
3,548 |
|
|
|
4,924 |
|
Percentage Baseload Capacity Sold Forward
(b) |
|
|
72 |
% |
|
|
77 |
% |
|
|
67 |
% |
|
|
58 |
% |
|
|
42 |
% |
|
|
41 |
% |
|
|
57 |
% |
Weighted Average Forward Price
($ per MWh)(c) |
|
$ |
49 |
|
|
$ |
45 |
|
|
$ |
53 |
|
|
$ |
55 |
|
|
$ |
55 |
|
|
$ |
48 |
|
|
$ |
51 |
|
Total Forward Hedged Revenues (c) |
|
$ |
227 |
|
|
$ |
2,609 |
|
|
$ |
2,672 |
|
|
$ |
2,423 |
|
|
$ |
1,736 |
|
|
$ |
1,490 |
|
|
$ |
2,186 |
|
|
|
|
|
(a) |
|
Includes amounts under fixed price power sales contracts and amounts
financially hedged under natural gas swap contracts. The forward natural gas swap quantities
are reflected in equivalent MWh and are derived by first dividing the quantity of MMBtu of
natural gas hedged by the forward market heat rate as of October 31, 2006 to arrive at the
equivalent MWh hedged which is then divided by 8,760 hours (total hours in a year) to arrive at MW hedged. |
|
(b) |
|
Percentage hedged is based on total MWh sold as power and gas converted using the method as
described in (a) above divided by the net capacity. The net capacity excludes loss in
generation from expected forced outages and in generation from forecasted market
uncertainties. |
|
(c) |
|
Includes amounts under fixed price power sales contracts and financially hedged under
natural gas swap contracts. |
Issuance of New High Yield Notes NRG plans to finance the payments required in order to
reset the existing hedges with cash on hand and with proceeds from the issuance of $1.1 billion of
new high yield notes.
Amendment
of Senior Credit Facility NRG plans to amend its existing Senior Credit Facility
to accomplish, among other things, the following objectives:
|
|
|
to permit the incurrence of the new debt represented by the new high yield notes; |
|
|
|
|
to increase the amount of the synthetic letter of credit facility by $500 million, from $1.0 billion to $1.5 billion; |
|
|
|
|
to increase the Available Amount, and effect a corresponding increase in NRG's restricted payments capacity, by $250 million; and |
|
|
|
|
to provide additional flexibility to NRG with respect to certain covenants governing or
restricting the use of excess cash flow, new investments, new indebtedness and permitted
liens. |
The amendments to the existing hedges, the issuance of the new high yield notes, and the
amendments to the Senior Credit Facility are expected to close by November 21, 2006. NRG
has entered into bridge agreements with Merrill Lynch & Co. to assure that it has adequate
financing to fund the amounts owed to the hedge counterparties, and Merrill Lynch & Co. has issued
a commitment to NRG to refinance its Senior Credit Facility if the desired amendments to
the existing facilities cannot be procured.
Impact
to Results of Operations NRG will account for the Hedge Reset as a net settlement of
its current hedge positions and a subsequent reestablishment of new hedge positions. The impact of
the net settlement will be recorded as a decrease to NRGs consolidated revenues with an offsetting
increase in revenues from a reduction in the associated derivative liability and the associated
out-of-market power contract balance established upon the Acquisition of NRG Texas.
As of October 31, 2006, NRG expects the impact to comprise of the following:
|
|
|
|
|
(In millions) |
|
|
|
|
|
Settlement payment |
|
$ |
(1,347 |
) |
Reduction in derivative liability |
|
|
146 |
|
Reduction in out-of-market contracts |
|
|
1,073 |
|
|
Net decrease in revenues |
|
|
(128 |
) |
|
Impact on
2006 earnings, net of tax |
|
|
(76 |
) |
|
74
Cash Flow Discussion
|
|
|
|
|
|
|
|
|
|
|
Nine months ended September 30, |
|
(In millions) |
|
2006 |
|
|
2005 |
|
|
Net cash
provided/(used) by operating activities |
|
$ |
1,048 |
|
|
$ |
(114 |
) |
Net cash
provided/(used) in investing activities |
|
|
(4,159 |
) |
|
|
179 |
|
Net cash
provided/(used) by financing activities |
|
$ |
3,990 |
|
|
$ |
(673 |
) |
|
Net Cash Provided/(Used) By Operating Activities
For the nine months ended September 30, 2006, net cash provided by operating activities
increased by $1,162 million compared to the same period in 2005. This was primarily due to the
following reasons:
|
|
|
Due to expiration of the underlying contracts and the downward shift of the forward
price curves, NRGs cash collateral deposits in support of derivative contracts decreased
by $349 million during the nine months ended September 30, 2006, compared to an increase of
$598 million during the same period in 2005, a difference of $947 million. As of September
30, 2006 NRG had cash collateral deposits of $132 million; |
|
|
|
|
Due to the redemption of NRGs previous senior notes, a premium of $126 million was paid
to NRGs former debt holders; |
|
|
|
|
NRGs activity for the period resulted in an increase of $88 million in working capital
compared to an increase in working capital for the same period in 2005 of $129 million, a
difference of $41 million; |
|
|
|
|
Due to redemption of NRGs 8% Second Priority Notes, during the nine months ended
September 30, 2006, NRG wrote off $61 million of deferred financing costs less debt premium
of $14 million for a net write-off of $47 million, compared to a write-off of debt premiums
of $7 million during the same period in 2005, a difference of $54 million; and |
|
|
|
|
A gain on the sale of emission allowances adjusted net income by $68 million to reflect
the activity as investing. Due to price conditions, it was economically beneficial to sell
emissions rather than operate certain plants. |
Net Cash Provided/(Used) By Investing Activities
For the nine months ended September 30, 2006, net cash used in investing activities was
approximately $4.2 billion more than the same period in 2005. NRGs use of cash was due to the
following mix of investment activities:
|
|
|
During the first quarter 2006, NRG acquired Texas Genco LLC for approximately $6.2
billion (net of assumed debt), which included the issuance of stock at a value of $1.7
billion and a net cash payment of approximately $4.3 billion (net of cash on hand at NRG
Texas of $238 million); |
|
|
|
|
NRG acquired Dynegys 50% ownership interest in WCP for $25 million (net of cash on hand
at WCP of $180 million). Prior to the purchase, NRG had an existing investment in WCP
accounted for as an unconsolidated equity method investment; |
|
|
|
|
During the third quarter 2006, NRG completed the acquisition of Padoma for net cash of
$7 million. |
|
|
|
|
As disclosed in Note 5 to the condensed consolidated financial statements of this Form
10-Q, NRG divested a number of its equity investments for total proceeds of $86 million, in
addition, NRG received approximately $239 million in net proceeds from sale of discontinued
operations. |
|
|
|
|
NRGs capital expenditures was $113 million more during the nine months ended September 30,
2006 than the same period in 2005, with the increase primarily related to
capital expenditures at NRG Texas; and |
|
|
|
|
During the nine months ended September 30, 2005, NRG received $70 million related to the
TermoRio settlement. |
Net Cash Provided/(Used) in Financing Activities
For the nine months ended September 30, 2006, net cash provided by financing activities
increased by approximately $4.7 billion in comparison to the same period in 2005. The increase was
primarily due to the financing activities related to the purchase of NRG Texas:
|
|
|
In connection with the Capital Allocation Program, during the third quarter 2006, NRG
through its two wholly-owned unrestricted subsidiaries issued approximately $147 million in
notes and $50 million in preferred interests to partially fund the purchase of $297 million
of NRGs common stock. |
|
|
|
|
In conjunction with the purchase of NRG Texas, NRG refinanced its outstanding debt as
well as NRG Texass outstanding debt as the Company: |
|
o |
|
Repaid $446 million in outstanding principal and terminated its term loan under
NRGs Amended Credit Facility; |
|
|
o |
|
Repurchased and retired approximately $1.1 billion of NRGs 8% Second Priority
Notes, pursuant to a tender offer; and |
|
|
o |
|
Repurchased NRG Texass outstanding notes for approximately $1.1 billion and NRG
Texass term loan for approximately $500 million. |
75
|
|
|
As part of raising the funds to purchase NRG Texas and to refinance the combined NRG
debt portfolio, the company: |
|
o |
|
Issued 20,855,057 shares of common stock on January 31, 2006 at an offering price
of $48.75 per share for total net proceeds of approximately $986 million, after
deducting expenses; |
|
|
o |
|
Issued 2 million shares of 5.75% Preferred Stock on January 30, 2006 at an
offering price of $250 per share for total net proceeds of approximately $486 million,
after deducting expenses; |
|
|
o |
|
Entered into a new senior secured credit facility providing for up to an
aggregate amount of $5.575 billion, consisting of a $3.575 billion Term Loan Facility, a
$1.0 billion Revolving Credit Facility and a $1.0 billion Letter of Credit Facility; and |
|
|
o |
|
Issued (i) $1.2 billion aggregate principal amount of 7.25% Senior Notes, and
(ii) $2.4 billion aggregate principal amount of 7.375% Senior Notes. |
Off-Balance Sheet Arrangements
Obligations Under Certain Guarantee Contracts
NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of
business to facilitate commercial transactions with third parties. These arrangements include
financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and
indemnifications. See Note 18 to the condensed consolidated financial statements of this Form 10-Q
for further details of the guarantee arrangements.
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
was considered a derivative per FAS 133. Although it is considered a derivative, it was exempt from
derivative accounting as it was excluded from the scope pursuant to paragraph 11(a) of FAS 133.
Despite this exclusion, per the guidance of EITF Topic D-98 the conversion feature must be
marked-to-market. As of September 30, 2006, the conversion feature has no value since NRGs stock
price is outside the conversion range.
Obligations Arising Out of a Variable Interest in an Unconsolidated Entity
Variable interest in Equity investments As of September 30, 2005, 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 $170 million as of
September 30, 2006. This indebtedness may restrict the ability of these subsidiaries to issue
dividends or distributions to NRG. In the normal course of business the Company may be asked to
loan funds to unconsolidated affiliates on both a long and short-term basis. Such transactions are
generally accounted for as accounts payable and receivable to/from affiliates and notes
payable/receivable to/from affiliates and where appropriate, bear market-based interest rates.
New Synthetic Letter of Credit Facility and Revolver Facility Under the New Senior
Credit Facility NRG entered into on February 2, 2006, the Company has a $1 billion synthetic Letter
of Credit Facility, and a $1 billion senior Revolving Credit Facility. The synthetic Letter of
Credit Facility was secured by a $1 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 is permitted to issue up to $300 million in unfunded
letters of credit under the Companys Revolving Credit Facility, or revolver letters of credit, for
ongoing working capital requirements and for general corporate purposes, including acquisitions
that are permitted under the New Senior Credit Facility.
As of September 30, 2006, the Company had issued $858 million in funded letters of credit
under the Letter of Credit Facility. Of this amount, a portion was issued to support obligations
under terminated NRG letter of credit facilities. As of September 30, 2006, the Company had issued
$157 million in revolver letters of credit, a portion of which supports non-commercial letter of
credit obligations under letter of credit facilities terminated as of February 2, 2006.
76
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, 2005.
See Note 15 to the condensed consolidated financial statements of this Form 10-Q for a
discussion of commitments and contingencies that also include contractual obligations and
commercial commitments that occurred during 2006.
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.
Goodwill and Other Intangible Assets
As part of the acquisition of Texas Genco LLC, NRG recorded intangible assets and goodwill.
The Company applied SFAS 141- Business Combinations and SFAS 142 Goodwill and Other Intangible
Assets, to account for these intangibles. Under these standards, the Company amortizes all
finite-lived intangible assets over their respective estimated
weighted-average useful lives; while
goodwill has an indefinite life and is not amortized. However, goodwill and all intangible assets
not subject to amortization will be tested for impairment whenever an event occurs that indicates that an impairment may have
occurred, or at a minimum on an annual basis. Where necessary, the Companys goodwill and/or
intangible asset will be impaired at that time.
In connection with the Texas Genco acquisition, the Company recognized the estimated fair
value of certain power sale contracts and fuel contracts acquired. NRG estimated their fair value
using forward pricing curves as of the closing date of the acquisition over the life of each
contract. These contracts had negative fair values at the closing date of the acquisition and will
be reflected as assumed contracts in the combined balance sheet. Assumed contracts are amortized to
revenues and fuel expense as applicable based on the estimated realization of the fair
value established on the closing date over the contractual lives.
The amount of goodwill as disclosed in the past has decreased due to a change in several
factors since the previously reported values. These factors include:
|
|
|
Earlier estimates reported were based on estimated working capital and estimated common
stock prices; |
|
|
|
|
Changes in the forecasted projected prices of electricity, coal and emission allowances.
These projections greatly affect the expected future cash flows from NRG Texas, as well as
the value of intangibles and out of market contracts; |
|
|
|
|
The tax basis of the assets and liabilities acquired is more accurate, although still subject to revision; and |
|
|
|
|
More precise information with respect to identifiable intangibles. |
Currently, NRG has valued goodwill at approximately $1.6 billion, with
the appraisal of Property, Plant and Equipment increasing its fair value, compared to Texas Genco
LLCs historical cost, by approximately $5.8 billion. If the remaining goodwill balance is
indicative of a further increase in value of depreciable property plant and equipment, depreciation
expense for the three and nine month period ended September 30, 2006, would increase by
approximately $20 million and $55 million, respectively, reducing income from continuing operations
before tax for the three and nine month period ended September 30, 2006 to approximately $588
million and $857 million, respectively.
See Note 1 to the condensed consolidated financial statements to this Form 10-Q for details of
changes in accounting standards.
77
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 utilizes 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 the 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, operational, 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. Value-at-risk, or VAR, is a statistical model that attempts to predict risk of
loss based on market price volatility. The Company calculates VAR using a variance/covariance
technique that models positions using a linear approximation of their value. NRGs VAR calculation
includes mark-to-market and non mark-to-market energy assets and liabilities.
NRG utilizes a diversified VAR model to calculate the estimate of potential loss in the fair
value of the Companys energy assets and liabilities including 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.
This model encompasses all of NRGs generating assets across the entire portfolio including
NRG Texas. As of September 30, 2006 the VAR for NRGs commodity portfolio, including generation
assets, load obligations and bilateral physical and financial transactions calculated using the
diversified VAR model was $49.1 million.
The following table summarizes average, maximum and minimum VAR for NRG for the three months
ended September 30, 2006.
|
|
|
|
|
VAR |
|
In millions |
|
|
As of September 30, 2006 |
|
$ |
49.1 |
|
Average for the three months ended September 30, 2006 |
|
|
58.1 |
|
Maximum |
|
|
66.7 |
|
Minimum |
|
|
49.1 |
|
|
78
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.
Additionally, actual changes in the value of options may differ from the VAR calculated using a
linear approximation inherent in the Companys calculation methodology. 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 utilizes VAR to model the estimate of potential loss of financial derivative instruments
included in derivative instruments valuation of assets and liabilities. This estimation includes
those energy contracts accounted for as a hedge under SFAS 133, as amended. The VAR for the
financial derivative instruments calculated using the diversified VAR model as of September 30,
2006 for the entire term of these instruments was approximately $94 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 May 3, 2006 was $2.15 billion. The notional amounts and
maturities of each tranche of these swaps are described in Note 8 to the condensed consolidated
financial statements of this Form 10-Q.
As of September 30, 2006, the Company had various interest rate swap agreements with notional
amounts totaling approximately $2.8 billion. If the swaps had been discontinued on September 30,
2006, the Company would have owed the counter-parties approximately $12.6 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 September 30, 2006, a 100 basis point
change in interest rates would result in a $18.7 million change in interest expense on a rolling
twelve month basis.
As of September 30, 2006, the fair value and the carrying amount of the Companys long-term
debt was $7.9 billion. NRG estimates that a 1% decrease in market interest rates would have
increased the fair value of the Companys long-term debt by $420 million.
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 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.
In connection with the sale of Flinders as discussed in Note 3 to the condensed consolidated
financial statements of this Form 10-Q, on August 15, 2006, NRG entered into a forward foreign
exchange contract to sell AU $300 million in exchange for $229 million and designated it as a fair
value hedge. Due to changes in the exchange rate, NRG recognized a loss as of September 30, 2006 of
approximately $5 million on its cash balance, with an offsetting gain from derivative income on the
related contract. The contract was settled on October 16, 2006.
79
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.
NRGs collateral posted in support of the management of NRGs electric generation facilities
fluctuates based on the amount of the portfolio hedged using collateralized contracts and market
price movements. Based on a sensitivity analysis a $1 per MWh increase or decrease in electricity
prices would cause a change in margin collateral outstanding of approximately $14.5 million as of
September 30, 2006. This sensitivity uses simplified assumptions and may not reflect actual market
movements.
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
September 30, 2006, NRG held collateral support of approximately $480 million from counterparties.
A portion of NRGs credit risk is related to transactions that are recorded in the Companys
consolidated Balance Sheets. 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 September 30, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exposure |
|
|
|
|
|
|
|
|
|
|
Before |
|
|
|
|
|
|
Net |
|
Credit Exposure (In millions, except ratios) |
|
Collateral |
|
|
Collateral |
|
|
Exposure |
|
|
Investment grade |
|
$ |
1,548 |
|
|
$ |
384 |
|
|
$ |
1,164 |
|
Non-investment grade |
|
|
50 |
|
|
|
41 |
|
|
|
9 |
|
Not rated |
|
|
156 |
|
|
|
5 |
|
|
|
151 |
|
|
Total |
|
$ |
1,754 |
|
|
$ |
430 |
|
|
$ |
1,324 |
|
|
Investment grade |
|
|
88 |
% |
|
|
89 |
% |
|
|
88 |
% |
Non-investment grade |
|
|
3 |
% |
|
|
10 |
% |
|
|
1 |
% |
Not rated |
|
|
9 |
% |
|
|
1 |
% |
|
|
11 |
% |
|
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 $1.3 billion was approximately $867 million as of September 30, 2006. 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
As the Company engages principally in the trading and marketing of its generation assets, most
of the Companys commercial activities qualify for hedge accounting under the requirements of SFAS
133. In order to so qualify, the physical generation and sale of electricity must be highly
probable at inception of the trade and throughout the period it is held, as is the case with NRGs
base-load coal plants. For this reason, trades in support of the Companys peaking units will not
generally qualify for hedge accounting treatment and any changes in the fair value is likely to be
reflected on a mark-to-market basis in the statement of operations. The majority of trades in
support of NRGs baseload coal units will normally qualify for hedge accounting treatment and any
fair value movements will be reflected in the balance sheet as part of other comprehensive income.
80
As part of the trading and marketing of NRGs generation assets, the Company may enter into
forward power sales contracts, forward gas purchase contracts and other energy related commodities
financial instruments to mitigate variability in earnings due to fluctuations in spot market
prices, hedge fuel requirements at generation facilities and protect fuel inventories. In addition,
in order to mitigate interest rate risk associated with the issuance of NRGs variable rate and
fixed rate debt, the Company enters into interest rate swap agreements.
The tables below disclose the derivative contracts accounted for at fair value. Specifically,
these tables disaggregate realized and unrealized changes in fair value; identify changes in fair
value attributable to changes in valuation techniques; disaggregate estimated fair values as at
September 30, 2006 based on whether fair values are determined by quoted market prices or more
subjective means; and indicate the maturities of contracts at September 30, 2006.
|
|
|
|
|
Derivative Activity Gains/(Losses) |
|
(In millions) |
|
|
Fair value of contracts at December 31, 2005 |
|
$ |
(403 |
) |
Value of Flinders contracts as at December 31, 2005, included in discontinued operations |
|
|
73 |
|
Value of contracts acquired with NRG Texas on February 2, 2006 |
|
|
(472 |
) |
Contracts realized or otherwise settled during the period |
|
|
153 |
|
Changes in fair value |
|
|
700 |
|
|
Fair value of contracts at September 30, 2006 |
|
$ |
51 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value of Contracts as of September 30, 2006 |
|
|
|
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 |
|
$ |
(4 |
) |
|
$ |
(2 |
) |
|
$ |
|
|
|
$ |
|
|
|
$ |
(6 |
) |
Prices provided by other external sources |
|
|
63 |
|
|
|
6 |
|
|
|
15 |
|
|
|
(27 |
) |
|
|
57 |
|
|
Total |
|
$ |
59 |
|
|
$ |
4 |
|
|
$ |
15 |
|
|
$ |
(27 |
) |
|
$ |
51 |
|
|
NRG may use a variety of financial instruments to manage the Companys exposure to
fluctuations in foreign currency exchange rates on NRGs international project cash flows, interest
rates on the Companys cost of borrowing and energy and energy-related commodities prices.
Item 4 Controls and Procedures
Under the supervision and with the participation of NRGs management, including the Companys
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 in Rule 13a-15(e) of 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 are effective to ensure
that the information required to be disclosed in reports filed under the Securities Exchange Act of
1934, as amended, is recorded, processed, summarized and reported within the time periods specified
in SEC rules and forms.
With the completion and associated integration of the acquisition of Texas Genco LLC and WCP,
there have been no changes in the Companys internal control over financial reporting during the
completed third quarter of 2006 that have materially affected, or are reasonably likely to
materially affect the Companys internal control over financial reporting.
81
PART II OTHER INFORMATION
Item 1 Legal Proceedings
For a discussion of material legal proceedings in which NRG was involved through September 30,
2006, see Note 15 to the condensed consolidated financial statements of this Form 10-Q.
Item 1A Risk Factors
Information regarding risk factors appears in Item 1A Risk Factors in NRG Energy, Inc.s 2005
Annual Report on Form 10-K for the fiscal year ended December 31, 2005. There have been no material
changes from the risk factors previously disclosed in NRG Energy, Inc.s 2005 Annual Report on Form
10-K.
Item 2 Unregistered Sales of Equity Securities and Use of Proceeds
Item 2(c) Purchase of Equity securities by NRG
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dollar value of |
|
|
|
|
|
|
|
|
|
|
|
Total number of shares |
|
|
shares that may be |
|
|
|
Total number of |
|
|
Average price |
|
|
purchased as part of publicly |
|
|
purchased under the |
|
For the period ended October 13, 2006 |
|
shares purchased |
|
|
paid per share |
|
|
announced plans or programs |
|
|
plans or programs |
|
|
First quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second quarter |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
July 1 July 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
August 1 August 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
500,000,000 |
|
September 1 - September 30 |
|
|
6,113,000 |
|
|
$ |
48.61 |
|
|
|
6,113,000 |
|
|
|
203,000,000 |
|
|
Third Quarter Total |
|
|
6,113,000 |
|
|
|
48.61 |
|
|
|
6,113,000 |
|
|
|
|
|
|
October 1 October 13, 2006 |
|
|
4,474,700 |
|
|
|
45.32 |
|
|
|
10,587,700 |
|
|
|
|
|
|
Year-to-date |
|
|
10,587,700 |
|
|
|
47.22 |
|
|
|
10,587,700 |
|
|
|
|
|
|
During the third quarter 2006, NRG repurchased 6,113,000 common shares at an average
price per share of $48.61 in connection with a share repurchase program announced on August 1,
2006. On October 13, 2006, NRG completed Phase I of the share repurchase program with a total of
10,587,700 shares of common stock repurchased at an average price per share of $47.22.
Item 3 Defaults Upon Senior Securities
None.
Item 4 Submission of Matters to a Vote of Security Holders
None
Item 5 Other Information
On November 3, 2006, NRG announced its intention to enter into a series of transactions that
includes (i) the reset of existing out-of-the-money hedges for years 2006 through 2010 to market, (ii)
substantial new baseload hedges for the years 2010 and 2011 and, possibly, later years, (iii) the
issuance of $1.1 billion of new high yield notes and (iv) amendments to NRGs existing
Senior Credit Facility, including the increase of the synthetic letter of credit facility
by $500 million. Except as otherwise noted, all of these transactions are expected to close by
November 21, 2006.
The Hedge Reset include amendments to the Amended and Restated Master Power Purchase
Agreement dated February 2, 2006, between J. Aron & Company,
or J. Aron, and Texas Genco II, LP
(including the cover sheet and confirmations letter thereto). The Amended Agreement provides among
other things, for the amendment of the prices to be paid by J. Aron to reflect current market
prices for power and for the payment by NRG of cash in an amount reflecting a negotiated present
value of the difference between the original price in the agreement and the amended price.
82
Item 6 Exhibits
(a) Exhibits
|
|
|
10.1
|
|
Limited Liability Company Agreement of NRG Common Stock Finance I LLC. (1) |
|
|
|
10.2
|
|
Limited Liability Company Agreement of NRG Common Stock Finance II LLC. (1) |
|
|
|
10.3
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International
and Credit Suisse Securities (USA) LLC. (1) |
|
|
|
10.4
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse
International and Credit Suisse Securities (USA) LLC, as agent. (1) |
|
|
|
10.5
|
|
Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse
Capital LLC and Credit Suisse Securities (USA) LLC, as agent. (1) |
|
|
|
10.6
|
|
Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit
Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent. (1) |
|
|
|
10.7
|
|
Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance I LLC. (1) |
|
|
|
10.8
|
|
Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance II LLC. (1) |
|
|
|
10.9
|
|
Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I
LLC. (1) |
|
|
|
10.10
|
|
Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II
LLC. (1) |
|
|
|
10.11
|
|
Underwriting Agreement, dated as of August 4, 2006, by and among NRG Energy, Inc., Credit Suisse International,
Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC. (1) |
|
|
|
10.12
|
|
Underwriting Agreement, dated as of August 9, 2006, among NRG Energy, Inc., affiliates of The Blackstone Group,
Hellman & Friedman, Kohlberg Kravis Roberts & Co. and Texas Pacific Group, as selling stockholders, and Morgan
Stanley & Co. Incorporated, as underwriter. (2) |
|
|
|
10.13
|
|
Underwriting Agreement, dated as of August 23, 2006, among NRG Energy, Inc., affiliates of Kohlberg Kravis Roberts
& Co., as selling stockholders, and Morgan Stanley & Co. Incorporated, as underwriter. (3) |
|
|
|
10.14
|
|
Underwriting Agreement, dated as of August 23, 2006, among NRG Energy, Inc., affiliates of Texas Pacific Group, as
selling stockholders, and Morgan Stanley & Co., Incorporated, as underwriter. (3) |
|
|
|
12.1
|
|
Computation of Earnings to Fixed Charges |
|
|
|
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. |
|
|
|
(1) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 10, 2006. |
|
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 11, 2006. |
|
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 25, 2006. |
83
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 CRANE
|
|
|
David Crane, |
|
|
Chief Executive Officer
(Principal Executive Officer) |
|
|
|
|
|
|
/s/ ROBERT C. FLEXON
|
|
|
Robert C. Flexon, |
|
|
Chief Financial Officer
(Principal Financial Officer) |
|
|
|
|
|
|
/s/ CAROLYN J. BURKE
|
|
|
Carolyn J. Burke, |
|
|
Controller
(Principal Accounting Officer) |
|
|
Date: November 6, 2006
84
Exhibit Index
|
|
|
10.1
|
|
Limited Liability Company Agreement of NRG Common Stock Finance I LLC. (1) |
|
|
|
10.2
|
|
Limited Liability Company Agreement of NRG Common Stock Finance II LLC. (1) |
|
|
|
10.3
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse International
and Credit Suisse Securities (USA) LLC. (1) |
|
|
|
10.4
|
|
Note Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit Suisse
International and Credit Suisse Securities (USA) LLC, as agent. (1) |
|
|
|
10.5
|
|
Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance I LLC, Credit Suisse
Capital LLC and Credit Suisse Securities (USA) LLC, as agent. (1) |
|
|
|
10.6
|
|
Preferred Interest Purchase Agreement, dated August 4, 2006, between NRG Common Stock Finance II LLC, Credit
Suisse Capital LLC and Credit Suisse Securities (USA) LLC, as agent.(1) |
|
|
|
10.7
|
|
Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance I LLC. (1) |
|
|
|
10.8
|
|
Certificate of Designations relating to the Series 1 Exchangeable Limited Liability Company Preferred Interests of
NRG Common Stock Finance II LLC. (1) |
|
|
|
10.9
|
|
Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance I
LLC. (1) |
|
|
|
10.10
|
|
Common Interest Purchase Agreement, dated August 4, 2006, between NRG Energy, Inc. and NRG Common Stock Finance II
LLC.(1) |
|
|
|
10.11
|
|
Underwriting Agreement, dated as of August 4, 2006, by and among NRG Energy, Inc., Credit Suisse International,
Credit Suisse Capital LLC and Credit Suisse Securities (USA) LLC.(1) |
|
|
|
10.12
|
|
Underwriting Agreement, dated as of August 9, 2006, among NRG Energy, Inc., affiliates of The Blackstone Group,
Hellman & Friedman, Kohlberg Kravis Roberts & Co. and Texas Pacific Group, as selling stockholders, and Morgan
Stanley & Co. Incorporated, as underwriter. (2) |
|
|
|
10.13
|
|
Underwriting Agreement, dated as of August 23, 2006, among NRG Energy, Inc., affiliates of Kohlberg Kravis Roberts
& Co., as selling stockholders, and Morgan Stanley & Co. Incorporated, as underwriter. (3) |
|
|
|
10.14
|
|
Underwriting Agreement, dated as of August 23, 2006, among NRG Energy, Inc., affiliates of Texas Pacific Group, as
selling stockholders, and Morgan Stanley & Co., Incorporated, as underwriter. (3) |
|
|
|
12.1
|
|
Computation of Earnings to Fixed Charges |
|
|
|
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. |
|
|
|
(1) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 10, 2006. |
|
(2) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 11, 2006. |
|
(3) |
|
Incorporated herein by reference to NRG Energy, Inc.s current report on Form 8-K filed on August 25, 2006. |
85