<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the Quarter Ended: SEPTEMBER 30, 2000 Commission File Number: 000-25569
NRG ENERGY, INC.
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(Exact name of registrant as specified in its charter)
Delaware 41-1724239
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
901 Marquette Avenue, Suite 2300
Minneapolis, Minnesota 55402
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (612) 373-5300
1221 Nicollet Mall, Suite 700, Minneapolis, Minnesota 55403
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Former name, former address and former fiscal year, if changed since last report
Indicated 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 [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Class Outstanding at November 13, 2000
-------------------------------------- --------------------------------
Class A - Common Stock, $.01 par value 147,604,500 Shares
Common Stock, $.01 par value 32,395,500 Shares
<PAGE> 2
INDEX
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PAGE NO.
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PART I - FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements and Notes
Consolidated Statements of Income 1
Consolidated Balance Sheets 2-3
Consolidated Statements of Stockholders' Equity 4
Consolidated Statements of Cash Flows 5
Notes to Financial Statements 6-15
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 16-21
Item 3. Quantitative and Qualitative Disclosures about Market Risk 22
PART II - OTHER INFORMATION
Item 1. Legal Proceedings 24
Item 5. Other 25
Item 6. Exhibits, Financial Statement Schedules, and Reports 26
on Form 8-K
SIGNATURES 27
<PAGE> 3
PART I - FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS AND NOTES
CONSOLIDATED STATEMENTS OF INCOME
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
<S> <C> <C> <C> <C>
(In thousands, except per share data) 2000 1999 2000 1999
---------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES
Revenues from wholly-owned operations $ 533,156 $ 139,974 $1,339,663 $ 237,855
Equity in earnings of unconsolidated affiliates 91,642 30,434 130,171 45,726
---------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 624,798 170,408 1,469,834 283,581
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OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations 319,438 79,147 840,269 148,211
Depreciation and amortization 36,424 12,663 87,276 23,688
General, administrative, and development 41,727 20,650 98,015 52,923
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Total operating costs and expenses 397,589 112,460 1,025,560 224,822
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OPERATING INCOME 227,209 57,948 444,274 58,759
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OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated subsidiaries (3,077) (382) (7,158) (1,537)
Other income, net 346 2,196 1,911 5,504
Interest expense (81,250) (30,760) (215,425) (57,607)
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Total other expense (83,981) (28,946) (220,672) (53,640)
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INCOME BEFORE INCOME TAXES 143,228 29,002 223,602 5,119
INCOME TAXES - EXPENSE (BENEFIT) 54,624 1,395 82,671 (23,889)
---------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 88,604 $ 27,607 $ 140,931 $ 29,008
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AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 180,000 147,605 161,114 147,605
EARNINGS PER AVERAGE COMMON SHARE - BASIC $0.49 $0.19 $0.87 $0.20
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING -DILUTED 182,683 147,605 162,242 147,605
EARNINGS PER AVERAGE COMMON SHARE - DILUTED $0.49 $0.19 $0.87 $0.20
</TABLE>
See notes to consolidated financial statements.
1
<PAGE> 4
CONSOLIDATED BALANCE SHEETS
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
(In thousands) 2000 1999
--------------------------------------------------------------------------------------------------------------------------
ASSETS
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents $ 165,403 $ 31,483
Restricted cash 32,784 17,441
Accounts receivable-trade, less allowance
for doubtful accounts of $867 and $186 266,532 126,376
Accounts receivable-affiliates 4,858 -
Inventory 212,943 119,181
Prepayments and other current assets 37,613 29,202
Current portion of notes receivable - affiliates 207 287
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Total current assets 720,340 323,970
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PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST
In service 4,125,719 2,078,804
Under construction 114,705 53,448
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4,240,424 2,132,252
Less accumulated depreciation (237,456) (156,849)
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Net property, plant and equipment 4,002,968 1,975,403
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OTHER ASSETS
Investments in projects 1,010,168 932,591
Capitalized project costs 7,687 2,592
Notes receivable, less current portion - affiliates 70,212 65,494
Notes receivable 5,815 5,787
Decommissioning fund investments 3,672 -
Intangible assets, net of accumulated amortization of $6,530 and $4,308 56,004 55,586
Debt issuance costs, net of accumulated amortization of $5,740 and $6,640 42,711 20,081
Other assets, net of accumulated amortization of $10,475 and $8,909 62,458 50,180
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Total other assets 1,258,727 1,132,311
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TOTAL ASSETS $5,982,035 $3,431,684
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</TABLE>
See notes to consolidated financial statements.
2
<PAGE> 5
CONSOLIDATED BALANCE SHEETS
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
(In thousands) 2000 1999
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LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES
Current portion of long-term debt $ 133,973 $ 30,462
Revolving line of credit - 340,000
Revolving line of credit, non-recourse 40,000 35,766
Accounts payable-trade 203,101 61,211
Accounts payable-affiliates - 6,404
Accrued income taxes 41,463 4,730
Accrued property and sales taxes 16,876 4,998
Accrued salaries, benefits and related costs 15,839 9,648
Accrued interest 55,939 13,479
Other current liabilities 18,885 17,657
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Total current liabilities 526,076 524,355
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Minority Interest 14,955 14,373
Consolidated Project-Level, Long Term, Non-recourse Debt 2,211,629 1,026,398
Corporate Level Long-Term, Recourse Debt 1,500,968 915,000
Deferred Income Taxes 53,812 16,940
Deferred Investment Tax Credits 896 1,088
Postretirement and Other Benefit Obligations 70,003 24,613
Deferred Income and Other Long-Term Obligations 199,497 15,263
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Total liabilities 4,577,836 2,538,030
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STOCKHOLDERS' EQUITY
Class A - common stock; $.01 par value; 250,000 shares authorized;
147,605 shares issued and outstanding 1,476 1,476
Common stock; $.01 par value; 550,000 shares authorized;
32,396 shares issued and outstanding 324 -
Additional paid-in capital 1,233,833 780,438
Retained earnings 328,141 187,210
Accumulated other comprehensive income (159,575) (75,470)
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Total Stockholders' Equity 1,404,199 893,654
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Commitments and Contingencies
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TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $5,982,035 $3,431,684
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</TABLE>
See notes to consolidated financial statements.
3
<PAGE> 6
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
Accumulated
Class A Additional Other Total
Common Common Paid-in Retained Comprehensive Stockholders'
(In thousands) Stock Stock Capital Earnings Income Equity
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCES AT JANUARY 1, 1999 $ 1,476 $ - $ 530,438 $130,015 $ (82,597) $ 579,332
Net Income 29,008 29,008
Foreign currency translation adjustments 13,903 13,903
---------------
Comprehensive income 42,911
Capital Contribution from parent 100,000 100,000
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BALANCES AT SEPTEMBER 30, 1999 $ 1,476 $ - $ 630,438 $159,023 $ (68,694) $ 722,243
=======================================================================================
BALANCES AT JANUARY 1, 2000 $ 1,476 $ - $ 780,438 $187,210 $ (75,470) $ 893,654
Net Income 140,931 140,931
Foreign currency translation adjustments (84,105) (84,105)
---------------
Comprehensive income 56,826
Capital stock activity:
Issuance of Common Stock 324 453,395 453,719
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BALANCES AT SEPTEMBER 30, 2000 $ 1,476 $324 $1,233,833 $328,141 $(159,575) $1,404,199
=======================================================================================
</TABLE>
See notes to consolidated financial statements.
4
<PAGE> 7
CONSOLIDATED STATEMENTS OF CASH FLOWS
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER, 30,
(In thousands) 2000 1999
--------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 140,931 $ 29,008
Adjustments to reconcile net income to net cash
Provided (used) by operating activities
Undistributed equity earnings of unconsolidated affiliates (92,807) (1,363)
Depreciation and amortization 87,276 23,688
Deferred income taxes and investment tax credits 36,680 (13,750)
Minority interest 582 (518)
Cash provided (used) by changes in certain working capital items,
net of acquisition effects:
Accounts receivable (97,647) (67,958)
Accounts receivable-affiliates (11,262) (26,555)
Accrued income taxes 35,489 11,356
Income tax receivable - 21,169
Inventory (32,337) (16,945)
Prepayments and other current assets (7,606) (10,553)
Accounts payable-trade 105,318 38,723
Accrued property and sales tax 11,728 2,755
Accrued salaries, benefits and related costs (7,304) (857)
Accrued interest 42,460 10,554
Other current liabilities 838 2,260
Cash provided (used) by changes in other assets and liabilities 29,772 (12,451)
--------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED (USED) BY OPERATING ACTIVITIES 242,111 (11,437)
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CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of liabilities assumed (1,940,642) (930,185)
Investments in projects (18,477) (118,231)
Proceeds from sale of property 9,785 -
Divestiture of projects - 1,000
Changes in notes receivable (net) (4,664) 22,917
Capital expenditures (102,169) (62,099)
Investment in decommissioning fund (115) -
(Increase) decrease in restricted cash (15,343) 1,899
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NET CASH USED BY INVESTING ACTIVITIES (2,071,625) (1,084,699)
--------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions from parent - 100,000
Proceeds from issuance of stock 453,719 -
Proceeds from (payments on) Revolving line of credit (340,000) 84,000
Proceeds from issuance of note - 613,890
Proceeds from issuance of long-term debt 2,985,316 326,713
Principal payments on long-term debt (1,135,601) (9,612)
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NET CASH PROVIDED BY FINANCING ACTIVITIES 1,963,434 1,114,991
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NET INCREASE IN CASH AND CASH EQUIVALENTS 133,920 18,855
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 31,483 6,381
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CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 165,403 $ 25,236
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</TABLE>
See notes to consolidated financial statements.
5
<PAGE> 8
NRG ENERGY, INC.
NOTES TO FINANCIAL STATEMENTS
NRG Energy, Inc. (the Company or NRG) is an indirect majority-owned subsidiary
of Xcel Energy, Inc. (Xcel), a Delaware corporation. Additional information
regarding the Company can be found in Xcel's Form 10-Q for the nine months ended
September 30, 2000.
The accompanying unaudited consolidated financial statements have been prepared
in accordance with SEC regulations for interim financial information and with
the instructions to Form 10-Q. Accordingly, they do not include all of the
information and footnotes required by generally accepted accounting principles
for complete financial statements. The accounting policies followed by the
Company are set forth in Note 1 to the Company's financial statements in its
Annual Report on Form 10-K for the year ended December 31, 1999 (Form 10-K). The
following notes should be read in conjunction with such policies and other
disclosures in the Form 10-K. Interim results are not necessarily indicative of
results for a full year.
In the opinion of management, the accompanying unaudited interim consolidated
financial statements contain all material adjustments necessary to present
fairly the consolidated financial position of the Company as of September 30,
2000 and December 31, 1999, the results of its operations for the three months
and nine months ended September 30, 2000 and 1999, and its cash flows and
stockholders' equity for the nine months ended September 30, 2000 and 1999.
Certain prior year amounts have been reclassified for comparative purposes.
These reclassifications had no effect on net income or stockholders' equity as
previously reported.
1. BUSINESS DEVELOPMENTS
In March 2000, the Company entered into an agreement with Great River
Energy under which Great River assigned to the Company all of its rights
and obligations with respect to two 135 MW turbines being built for it by
Siemens Westinghouse. The Company's total cost for the turbines, which are
scheduled for delivery in the first or second quarter of 2001, will be
approximately $43 million.
In March 2000, the Company acquired the Killingholme A generation facility
from National Power plc for (pound)390 million (approximately $615 million
at the time of acquisition), subject to post-closing adjustments.
Killingholme is a combined cycle gas-fired baseload facility located in
North Lincolnshire, England. The facility comprises three units with a
total generating capacity of 680 MW. The Company owns and operates the
facility, which sells its power into the wholesale electricity market of
England and Wales.
In March 2000, the Company acquired 1,708 MW of coal and gas-fired
generation assets in Louisiana for approximately $1,055.9 million (the
Cajun facilities). These assets were formally owned by Cajun Electric Power
Cooperative, Inc. (Cajun Electric). The Company sells a significant amount
of the energy and capacity of the Cajun facilities to 11 of Cajun
Electric's former power cooperative members. Seven of these cooperatives
have entered into 25-year power purchase agreements with the Company, and
four have entered into two to four year power purchase agreements. In
addition, the Company sells power under contract to two municipal power
authorities and one investor-owned utility that were former customers of
Cajun Electric. The Company estimates that payments under the contracts
with the 11 cooperatives will account for approximately 72% of the Cajun
facilities' projected 2001 revenues, and that payments under the contracts
with the municipal power authorities and the investor-owned utility will
account for approximately an additional 7% of such revenues.
6
<PAGE> 9
See Note 9 of Notes to the Financial Statements for pro forma results of
operations as if the acquisition of the Cajun facilities had occurred at
the beginning of the periods disclosed.
In June 2000, the Company successfully completed the initial public
offering of 32,395,500 shares of its common stock. Gross proceeds raised
from the offering, including exercise of the over-allotment option, were
approximately $485.9 million. The shares sold in the offering represent
approximately 18 percent of the common equity of the Company. Xcel owns
147,604,500 shares of the Company's Class A common stock which represents
an 82% interest in the Company.
In June 2000, the Estonian cabinet approved the terms under which the
Company may proceed to purchase a 49% interest in Narva Power, which owns
approximately 3,000 MW of oil shale-fired generation plants and a 51%
interest in state-owned oil shale mines. A government-owned entity,
Eesti-Energia, will retain 51% ownership of Narva Power. The terms of the
Company's purchase include a commitment by Narva Power to invest
approximately $361 million for reconstructing and refurbishing the
generation plants and making environmental improvements. The Company will
make an initial $65-70 million equity commitment. Narva Power's two
stations, Balti and Eestia, currently supply more than 90% of Estonia's
electricity. Narva Power expects to enter into a 15-year power purchase
agreement with Eesti Energia.
In July 2000, the Company and Dynegy Inc., completed a 100 MW expansion of
the Rocky Road Power Plant, a natural gas fired simple cycle peaking
facility in East Dundee, Illiniois. The installation of the additional 100
MW natural gas fired combustion turbine increases that facility's
generating capacity to 350 MW. The Company acquired a 50% interest in the
Rocky Road Power Plant in December 1999.
In August 2000, the Company completed its $11.7 million purchase of
Harrisburg Steam Works and Statoil Energy Power/Paxton L.P. located in
Harrisburg, PA from Statoil Energy Inc. Harrisburg Steam Works provides
steam to more than 300 residential, commercial and industrial customers,
including the City of Harrisburg, Pennsylvania and the Commonwealth of
Pennsylvania. Statoil Energy Power/Paxton L.P. is a cogeneration facility
capable of producing 12 MW of electrical power while supplying nearly 30%
of the steam requirements for Harrisburg Steam Works. Also included in the
purchase were a nationwide diesel engine service business and a chiller
plant that serves the Harrisburg Hospital.
In August 2000, the Company completed the acquisition from Statoil Energy,
Inc. of an 18 MW coal fired cogeneration facility that provides steam and
electricity to a major manufacturing facility located in Dover, Delaware.
The Company paid approximately $35 million for this facility. Excess
electrical energy is sold through the Dover municipal electric utility. In
a separate purchase agreement, the Company also acquired Statoil's
Distributed Generation and Engineering Services Group, which consists of
three-generation projects totaling 6.2 MW as well as a diesel-services
group for $2.5 million.
In August 2000, the Company completed the acquisition of the Koch Power
Louisiana Sterlington Project from Koch Power Inc. Koch Power Louisiana
consists of four generating units totaling 75 MW of summer capacity located
in Sterlington, Louisiana.
In September 2000, the Company entered into a Turbine Purchase Master
Agreement with General Electric Company (GE) providing for the purchase by
the Company from GE of thirteen gas turbine generators and six steam
turbine generators. The Turbine Purchase Master Agreement replaces the
Memorandum of Understanding entered into between the parties in January
2000. The turbine purchases will take place over the next five years with
the first delivery scheduled to be made in 2002. The turbines have an
equivalent generation output of approximately 4,400 MW and an acquisition
cost of approximately $700 million.
In September 2000, the Company completed the acquisition of approximately
24.4% of the common shares of Itiquira Energetica S.A. - owner of a 156 MW
hydroelectric power generation facility located in the state of Mato Grosso
in southwestern Brazil for approximately 14.5 million Brazilian reals
(approximately $7.9 million U.S. as of September 2000).
In September 2000, the Company completed the acquisition of Flinders Power
in South Australia. The Company paid approximately AUD $314.4 million ($180
million US as of August 2000) for a 100 year lease of the Flinders Power
assets. Flinders Power includes two power stations totaling 760 MW; the
Leigh Creek coal mine and a dedicated rail line. The lease agreement also
includes managing the long-term fuel supply and power purchase agreement of
the 180 MW Osborne Cogeneration Station.
In October 2000, the Company announced that it signed an asset purchase
agreement for a 50% interest in the 522 MW coal-fired North Valmy
Generating Station located in Valmy, Nevada and a 100% interest in 25 MW of
peaking units near Valmy Station. The Valmy assets are currently owned by
Sierra Pacific Resources subsidiary, Sierra Pacific Power Company. The
Company's acquisition is subject to Idaho Power's, the other 50% owner of
the Station, non-exercise of its
7
<PAGE> 10
180-day right of first refusal on purchasing Sierra Pacific Resource's 50%
interest. The Company will pay approximately $273.3 million, net of a
transition power purchase agreement and subject to other adjustments. The
acquisition is expected to be completed in the first quarter of 2001.
In November 2000, the Company announced it has signed a purchase agreement
to acquire a 5,691 MW portfolio of operating projects and projects in
construction and advanced development from LS Power, LLC for $658 million,
subject to purchase price adjustments. The acquisition is expected to close
in the first quarter of 2001. Additionally, until December 31, 2005 NRG has
the opportunity to acquire ownership interests in the next 3,000 MW of
generation projects developed and offered for sale by LS Power and its
partners.
In November 2000, the Company announced the formation of a partnership with
Avista-STEAG LLC to build, operate and manage a 633 MW natural gas-fired
merchant power plant. The Brazos Valley project is located in Fort Bend
County, Texas - 30 miles west of Houston, Texas. Avista-STEAG LLC will
retain a 51% ownership in the project while the Company will own the
remaining 49%. Construction is scheduled to begin in early 2001 with
commercial operation expected in January 2003.
2. SUMMARIZED INCOME STATEMENT INFORMATION OF AFFILIATES
The Company has 33-1/3-50% investments in the four companies reported in
Part IV - Item 14 - Exhibits, Financial Statement Schedules and Reports on
Form 8-K of Form 10-K that are considered significant subsidiaries, as
defined by applicable SEC regulations, and accounts for those investments
using the equity method. The following summarizes the income statements of
these unconsolidated entities:
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
(In thousands) 2000 1999 2000 1999
---------------- ----------------- ------------------ -----------------
<S> <C> <C> <C> <C>
Net sales $ 443,945 $ 257,621 $ 932,216 $ 597,184
Other income (expense) (15,153) (18,420) (7,928) (6,363)
Costs and expenses:
Cost of sales 240,005 220,471 597,649 483,278
General and administrative 5,338 (1,052) 20,478 17,803
Other (9,829) (28,861) 2,198 2,025
---------------- ----------------- ------------------ -----------------
Total Costs and expenses 235,514 190,558 620,325 503,106
---------------- ----------------- ------------------ -----------------
Income before income taxes 193,278 48,643 303,963 87,715
Income taxes 7,996 277 19,396 12,113
---------------- ----------------- ------------------ -----------------
Net income $ 185,282 $ 48,366 $ 284,567 $ 75,602
================ ================= ================== =================
Company's share of net income $ 90,598 $ 21,379 $ 136,915 $ 32,287
================ ================= ================== =================
</TABLE>
3. SHORT TERM BORROWINGS
The Company has a $500 million revolving credit facility under a commitment
fee arrangement that matures on March 9, 2001. This facility provides
short-term financing in the form of bank loans. At September 30, 2000 the
Company had no amounts outstanding under this facility.
In March 2000, the Company borrowed $300 million under a short-term bridge
facility that was terminated in June 2000, and bore interest at a floating
rate, and had a weighted average interest rate of 6.5% for the period ended
June 30, 2000. Proceeds from this loan were used to fund the acquisition of
the Cajun facilities. In June 2000, a portion of the proceeds raised by the
Company's initial public offering of its common stock were used to pay off
and terminate this short-term bridge facility.
The Company borrowed $40 million under a floating rate working capital
facility which NRG South Central Generating LLC, an indirect wholly owned
subsidiary of the Company, entered into in April 2000; the facility
terminates in March 2001. The working capital facility allows the Company
to choose between the lender's prime rate or LIBOR in determining an
interest rate. As of September 30, 2000, the weighted average interest rate
was 9.5%.
8
<PAGE> 11
4. LONG TERM DEBT
In February 2000, NRG Northeast Generating LLC, an indirect wholly-owned
subsidiary of the Company, issued $750 million of senior secured bonds,
non-recourse to the Company, to refinance short-term project borrowings and
for certain other purposes. The bond offering included three tranches: $320
million with an interest rate of 8.065% due in 2004, $130 million with an
interest rate of 8.842% due in 2015 and $300 million with an interest rate
of 9.292% due in 2024. In October 2000, NRG Northeast Generating LLC filed
with the Securities and Exchange Commission and went effective with an
exchange offer registration statement concerning these bonds. The exchange
offer will remove certain restrictions surrounding the resale of these
bonds.
In March 2000, the Company issued (pound)160 million (approximately $250
million at the time of issuance) of 7.97% reset senior notes due 2020,
principally to finance its equity investment in the Killingholme facility.
On March 15, 2005, these senior notes may be remarketed by Bank of America,
N.A. at a fixed rate of interest through the maturity date or at a floating
rate of interest for up to one year and then at a fixed rate of interest
through 2020. Interest is payable semi-annually on these securities
beginning September 15, 2000 through March 15, 2005, and then at intervals
and interest rates established in the remarketing process.
In March 2000, NRG South Central Generating LLC, a subsidiary of the
Company, issued $800 million of senior secured bonds, non-recourse to the
Company, in a two-part offering. The first tranche was for $500 million
with a coupon of 8.962% and a maturity of 2016. The second tranche was for
$300 million with a coupon of 9.479% and a maturity of 2024. During March
2000, the proceeds from these bonds were used to finance the Company's
investment in the Cajun generating facilities.
In March 2000, three of the Company's foreign subsidiaries entered into a
(pound)325 million (approximately $471.2 million at October 31, 2000)
secured borrowing facility agreement with Bank of America International
Limited, as arranger. Under this facility, the financial institutions have
made available to the Company's subsidiaries various term loans totaling
(pound)235 million (approximately $340.7 million at October 31, 2000) for
the purpose of financing the acquisition of the Killingholme facility and
(pound)90 million ($130.5 million at October 31, 2000) of revolving credit
and letter of credit facilities to provide working capital for operating
the Killingholme facility. The final maturity date of the facility is the
earlier of June 30, 2019, or the date on which all borrowings and
commitments under the largest tranche of the term facility have been repaid
or cancelled.
In September 2000, the Company issued $350 million of senior secured bonds,
with an interest rate of 8.25% due in 2010. Interest is payable
semi-annually on the securities beginning March 15, 2001. The proceeds from
these bonds were used for repayment of short-term indebtedness incurred to
fund acquisitions, primarily Flinders Power, and for investments and
general corporate purposes.
GUARANTEES
The Company may become directly liable for the obligations of certain of
its project affiliates and other subsidiaries pursuant to guarantees
relating to certain of their indebtedness, equity and operating
obligations. As of September 30, 2000, the Company's obligations pursuant
to its guarantees of the performance, equity and indebtedness obligations
of its subsidiaries totaled approximately $414.7 million.
5. FINANCIAL INSTRUMENTS
As of September 30, 2000, the Company had outstanding five interest rate
swap agreements with notional amounts totaling approximately $725.0
million. If the swaps had been discontinued on September 30, 2000, the
Company would have owed the counter-parties approximately $8.0 million.
Based on the investment grade rating of the counter-parties, the Company
believes that its exposure to credit risk due to nonperformance by the
counter-parties to our hedging contracts is insignificant.
O The Company entered into a swap agreement effectively converting
the 7.5% fixed rate on $200 million of our Senior Notes due 2007
to a variable rate based on the London Interbank Offered Rate.
The swap expires on June 1, 2009.
9
<PAGE> 12
O A second swap effectively converts a $16 million issue of
non-recourse variable rate debt into a fixed rate debt. The swap
expires on September 30, 2002 and is secured by the Camas Power
Boiler assets.
O A third swap converts $177 million of non-recourse variable rate
debt into fixed rate debt. The swap expires on December 17, 2014
and is secured by the Crockett Cogeneration assets.
O A fourth swap converts (pound)188 million of non-recourse
variable rate debt into fixed rate debt. The swap expires on June
30, 2019 and is secured by the Killingholme assets.
O A fifth swap converts AUD 105 million of non-recourse variable
rate debt into fixed rate debt. The swap expires on September 8,
2012 and is secured by the Flinders Power assets.
10
<PAGE> 13
6. SEGMENT REPORTING
NRG conducts its business within three segments: Independent Power
Generation, Alternative Energy (Resource Recovery and Landfill Gas) and
Thermal projects. These segments are distinct components of NRG with
separate operating results and management structures. The "Other"
category includes operations that do not meet the threshold for separate
disclosure and corporate charges that have not been allocated to the
operating segments. Segment information for the three and nine months ended
September 30, 2000 and 1999 are as follows:
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED
SEPTEMBER 30, 2000 INDEPENDENT
(In thousands) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-------------- -------------- ------------ ----------- -----------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 498,045 $ 7,684 $23,187 $ 3,939 $ 532,855
Intersegment revenues - 301 - - 301
Equity in earnings of unconsolidated 98,479 (6,842) 5 - 91,642
-------------- -------------- ------------ ----------- -----------
Total operating revenues 596,524 1,143 23,192 3,939 624,798
-------------- -------------- ------------ ----------- -----------
NET INCOME (LOSS) $ 113,675 $ 3,744 $ 1,287 $(30,102) $ 88,604
FOR THE THREE MONTHS ENDED
SEPTEMBER 30, 1999 INDEPENDENT
(In thousands) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-------------- -------------- ------------ ----------- -----------
OPERATING REVENUES
Revenues from wholly-owned operations $ 115,447 $ 5,356 $18,450 $ 506 $ 139,759
Intersegment revenues - 215 - - 215
Equity in earnings of unconsolidated 30,744 (3,365) 588 2,467 30,434
-------------- -------------- ------------ ----------- -----------
Total operating revenues 146,191 2,206 19,038 2,973 170,408
-------------- -------------- ------------ ----------- -----------
NET INCOME (LOSS) $ 48,272 $ 683 $ 1,498 $(22,846) $ 27,607
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
INDEPENDENT
(In thousands) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-------------- -------------- ------------ ----------- -----------
OPERATING REVENUES
Revenues from wholly-owned operations $1,240,619 $ 22,923 $63,595 $ 11,624 $1,338,761
Intersegment revenues - 902 - - 902
Equity in earnings of unconsolidated 143,491 (13,336) 16 - 130,171
-------------- -------------- ------------ ----------- -----------
Total operating revenues 1,384,110 10,489 63,611 11,624 1,469,834
-------------- -------------- ------------ ----------- -----------
NET INCOME (LOSS) $ 204,729 $ 11,576 $ 4,518 $(79,892) $ 140,931
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
INDEPENDENT
(In thousands) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-------------- -------------- ------------ ----------- -----------
OPERATING REVENUES
Revenues from wholly-owned operations $ 156,579 $ 20,498 $55,005 $ 4,810 $ 236,892
Intersegment revenues - 963 - - 963
Equity in earnings of unconsolidated affiliates 50,871 (2,029) 1,671 (4,787) 45,726
-------------- -------------- ------------ ----------- -----------
Total operating revenues 207,450 19,432 56,676 23 283,581
-------------- -------------- ------------ ----------- -----------
NET INCOME (LOSS) $ 55,799 $ 6,847 $ 4,683 $ (38,321) $ 29,008
</TABLE>
11
<PAGE> 14
The Company is a leading global energy company primarily engaged in the
construction, development, acquisition, ownership and operation of power
generation facilities and the sale of energy, capacity and related
products. The following geographic information for the three and nine
months ended September 30, 2000 and 1999 presents the Company's results of
operations on a geographic basis:
<TABLE>
<CAPTION>
ASIA OTHER
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
(In thousands) U.S. EUROPE PACIFIC AMERICAS TOTAL
-----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 454,732 $ 42,674 $35,329 $ 120 $ 532,855
Intersegment Revenues 301 - - - 301
Equity in earnings of unconsolidated affiliates 86,283 1,149 4,428 (218) 91,642
-----------------------------------------------------------------------
Total operating revenues 541,316 43,823 39,757 (98) 624,798
-----------------------------------------------------------------------
NET INCOME $ 82,432 $ 390 $ 6,477 $ (696) $ 88,603
-----------------------------------------------------------------------
ASIA OTHER
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1999
(In thousands) U.S. EUROPE PACIFIC AMERICAS TOTAL
-----------------------------------------------------------------------
OPERATING REVENUES
Revenues from wholly-owned operations $ 139,242 $ 80 $ 437 $ - $ 139,759
Intersegment Revenues 215 - - - 215
Equity in earnings of unconsolidated affiliates 17,233 7,368 3,817 2,016 30,434
-----------------------------------------------------------------------
Total operating revenues 156,690 7,448 4,254 2,016 170,408
-----------------------------------------------------------------------
NET INCOME (LOSS) $ 25,037 $ (89) $ 3,218 $ (559) $ 27,607
-----------------------------------------------------------------------
ASIA OTHER
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
(In thousands) U.S. EUROPE PACIFIC AMERICAS TOTAL
-----------------------------------------------------------------------
OPERATING REVENUES
Revenues from wholly-owned operations $1,181,389 $121,179 $35,976 $ 217 $1,338,761
Intersegment Revenues 902 - - - 902
Equity in earnings of unconsolidated affiliates 115,875 3,835 6,014 4,447 130,171
-----------------------------------------------------------------------
Total operating revenues 1,298,166 125,014 41,990 4,664 1,469,834
-----------------------------------------------------------------------
NET INCOME (LOSS) $ 127,063 $ 6,192 $ 5,015 $ 2,661 $ 140,931
-----------------------------------------------------------------------
ASIA OTHER
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
(In thousands) U.S. EUROPE PACIFIC AMERICAS TOTAL
-----------------------------------------------------------------------
OPERATING REVENUES
Revenues from wholly-owned operations $ 235,354 $ 284 $ 1,254 - $ 236,892
Intersegment Revenues 963 - - - 963
Equity in earnings of unconsolidated affiliates 25,376 13,392 3,859 3,099 45,726
-----------------------------------------------------------------------
Total operating revenues 261,693 13,676 5,113 3,099 283,581
-----------------------------------------------------------------------
NET INCOME (LOSS) $ 14,638 $ 1,986 $ 8,598 $ 3,786 $ 29,008
-----------------------------------------------------------------------
</TABLE>
12
<PAGE> 15
7. COMMITMENTS AND CONTINGENCIES
In January 2000, the Company entered into agreements for the purchase of
1,875 MW of fossil-fueled electric generating capacity and other assets
from Conectiv of Wilmington, Delaware for approximately $800 million. The
transaction is subject to the receipt of required regulatory approvals and
satisfaction of other closing conditions, the transaction is expected to
close in early 2001.
In September 2000, the Company entered into a Turbine Purchase Master
Agreement with General Electric Company, to purchase 13 gas turbine
generators and six steam turbine generators. The purchases will take place
over the next five years with the first delivery scheduled to be made in
2002. The turbines have an equivalent generation output of approximately
4,400 MW and an acquisition cost of approximately $700 million.
In March 2000, the Company entered into an agreement with Great River
Energy under which Great River assigned to the Company all of its rights
and obligations with respect to two 135 MW turbines being built for it by
Siemens Westinghouse. The Company's total cost for the turbines, which are
scheduled for delivery in the first or second quarter of 2001, will be
approximately $43 million. The Company expects to install these turbines at
either existing plant sites in the United States or new greenfield sites.
In October 2000, the Company announced that it signed an asset purchase
agreement for a 50% interest in the 522 MW coal-fired North Valmy
Generating Station located in Valmy, Nevada and a 100% interest in 25 MW of
peaking units near Valmy Station. The Valmy assets are currently owned by
Sierra Pacific Resource's subsidiary, Sierra Pacific Power Company. The
Company's acquisition is subject to Idaho Power's, the other 50% owner of
the Station, non-exercise of its 180-day right of first refusal on
purchasing Sierra Pacific Resource's 50% interest. The Company will pay
approximately $273.3 million, net of a transition power purchase agreement
and subject to other adjustments. The acquisition is expected to be
completed in the first quarter of 2001.
In November 2000, the Company announced it has signed a purchase agreement
to acquire a 5,691 MW portfolio of operating projects and projects in
construction and advanced development from LS Power, LLC for $658 million,
subject to purchase price adjustments. The acquisition is expected to close
in the first quarter of 2001. Additionally, the Company has the opportunity
to acquire ownership interests in the next 3,000 MW of generation projects
developed and offered for sale by LS Power and its partners.
In November 2000, the Company announced the formation of a partnership with
Avista-STEAG LLC to build, operate and manage a 633 MW natural gas-fired
merchant power plant. The Brazos Valley project is located in Fort Bend
County, Texas -- 30 miles west of Houston, Texas. Avista-STEAG LLC will
retain a 51% ownership in the project while the Company will own the
remaining 49%. Construction is scheduled to begin in early 2001 with
commercial operation expected in January 2003.
Regulatory Issue
On March 30, 2000 the Company received notification from the New York
Independent System Operator (NYISO) of its petition to the Federal Energy
Regulatory Commission (FERC) to place a $2.52 per megawatt hour market cap
on ancillary service revenues. The NYISO also requested authority to impose
this cap on a retroactive basis to March 1, 2000.
On May 31, 2000, the FERC approved the NYISO's request to impose price
limitations on one ancillary service, Ten Minute Non-Synchronized Reserves
(TMNSR) on a prospective basis only, effective March 28, 2000. The FERC
rejected the NYISO's request for authority to adjust the market-clearing
prices for TMNSR on a retroactive basis. As a result of the FERC order
(unless the NYISO or other party successfully appeals the order), the
Company will retain the approximately $8.0 million of revenues collected in
February 2000 and approximately $8.2 million included in revenues, but not
yet collected for March 2000. The NYISO has requested the FERC to
reconsider the order.
On October 16, 2000, Morgan Stanley Capital Group, Inc. filed a complaint
with the FERC against PJM Interconnection, L.L.C. seeking to remove the
$1,000 price cap in the PJM energy market and to eliminate PJM's installed
capability market. NRG Energy, Inc., NRG Thermal Corporation and NRG Power
Marketing, Inc. filed a motion to invervene, comment and protest,
protesting Morgan Stanley's filing with respect to the installed capability
market, but supporting the elimination of the $1,000 price cap on energy.
The FERC has not yet placed the complaint on any agenda for a Commission
hearing.
Disputed Revenues
As of June 30, 2000, disputed revenues totaled $41.7 million, related to
certain revenues earned prior to May 31, 2000. The Company is actively
pursuing resolution and/or collection of these amounts. The contingent
revenues relate to the interpretation of certain transmission power sales
agreements and to sales to the New York Power Pool and New England Power
Pool, conflicting meter readings, pricing of firm sales and other power
pool reporting issues. These amounts have not been recorded in the
financial statements and will not be recognized as income until disputes
are resolved and collection is assured. During the third quarter of 2000,
the Company collected and recognized approximately $23.6 million of
disputed revenues. As of September 30, 2000, disputed revenues of
approximately $24.7 million remained.
8. EARNINGS PER SHARE
In June 2000, the Company successfully completed the initial public
offering of 32,395,500 shares of its common stock (including 4,225,500
shares sold upon the exercise of the underwriters' over-allotment option).
Diluted earnings per average common share is calculated by dividing Net
Income by the weighted average shares of common stock outstanding including
stock options outstanding under the Company's stock option plans considered
to be common stock equivalents. The following table shows the effect of
those stock options on the weighted average number of shares outstanding
used in calculating diluted earnings per average common share.
13
<PAGE> 16
<TABLE>
<CAPTION>
FOR THE THREE FOR THE NINE
MONTHS ENDED MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------- ----------------------
(In thousands) 2000 1999 2000 1999
------------- ----------- ----------- ----------
<S> <C> <C> <C> <C>
Average Common Shares Outstanding 180,000 147,605 161,114 147,605
Assumed Conversion of Stock Options 2,683 - 1,128 -
------------- ----------- ----------- ----------
Potential Average Diluted Common Shares Outstanding 182,683 147,605 162,242 147,605
------------- ----------- ----------- ----------
</TABLE>
9. PRO FORMA RESULTS OF OPERATIONS - CAJUN ACQUISITION
During March 2000, the Company completed the acquisition of two fossil
fueled generating plants from Cajun Electric Power Cooperative, Inc.
for approximately $1,055.9 million. The following information
summarizes actual results for the three months ended September 30,
2000, and the pro forma results of operations as if the acquisition had
occurred as of the beginning of the three and nine month periods ended
September 30, 2000 and 1999. The pro forma information presented is for
informational purposes only and is not necessarily indicative of future
earnings or financial position or of what the earnings and financial
position would have been had the acquisition of the Cajun facilities
been consummated at the beginning of the respective periods or as of
the date for which pro forma financial information is presented.
<TABLE>
<CAPTION>
ACTUAL PRO FORMA
THREE MONTHS ENDED THREE MONTHS ENDED
(In thousands except per share amounts) SEPTEMBER 30, 2000 SEPTEMBER 30, 1999
------------------ ------------------
<S> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 533,156 $ 254,428
Equity in earnings of unconsolidated affiliates 91,642 30,434
------------------ ------------------
TOTAL OPERATING REVENUES 624,798 284,862
Total operating costs and expenses 397,589 192,787
------------------ ------------------
OPERATING INCOME 227,209 92,075
Other expense (83,981) (47,032)
------------------ ------------------
INCOME BEFORE INCOME TAXES 143,228 45,043
Income tax expense 54,624 8,031
------------------ ------------------
NET INCOME $ 88,604 $ 37,012
------------------ ------------------
EARNINGS PER AVERAGE COMMON SHARE - DILUTED $0.49 $0.25
PRO FORMA PRO FORMA
NINE MONTHS ENDED NINE MONTHS ENDED
(In thousands except for per share amounts) SEPTEMBER 30, 2000 SEPTEMBER 30, 1999
------------------ ------------------
OPERATING REVENUES
Revenues from wholly-owned operations $1,419,645 $ 525,703
Equity in earnings of unconsolidated affiliates 130,171 45,726
------------------ ------------------
TOTAL OPERATING REVENUES 1,549,816 571,429
Total operating costs and expenses 1,093,668 445,549
------------------ ------------------
OPERATING INCOME 456,148 125,880
Other expense (238,463) (109,894)
------------------ ------------------
INCOME BEFORE INCOME TAXES 217,685 15,986
Income tax expense (benefit) 80,223 (19,393)
------------------ ------------------
NET INCOME $ 137,462 $ 35,379
------------------ ------------------
EARNINGS PER AVERAGE COMMON SHARE - DILUTED $0.85 $0.24
</TABLE>
14
<PAGE> 17
10. INVENTORY
At September 30, 2000, inventory, which is stated at the lower of weighted
average cost or market, consisted of:
(IN THOUSANDS)
-----------------
Fuel oil $ 79,481
Spare parts 87,809
Coal 30,267
Kerosene 628
Other 14,758
-----------------
TOTAL $212,943
-----------------
11. DECOMMISSIONING FUND
The Company is required by the State of Louisiana Department of
Environmental Quality (DEQ) to rehabilitate its Big Cajun II ash and
wastewater impoundment areas upon removal from service of the Big Cajun II
facilities. On July 1, 1989, a guarantor trust fund (the "Solid Waste
Disposal Trust Fund") was established to accumulate the estimated funds
necessary for such purpose. NRG South Central Generating LLC's predecessor
deposited $1.06 million in the Solid Waste Disposal Trust Fund in 1989, and
funded $116,000 annually thereafter, based upon an estimated future
rehabilitation cost (in 1989 dollars) of approximately $3.5 million and the
remaining estimated useful life of the Big Cajun II facilities. Cumulative
contributions to the Solid Waste Disposal Trust Fund and earnings on the
investments therein are accrued as a decommissioning liability. At
September 30, 2000, the carrying value of the trust fund investments and
the related accrued decommissioning liability was approximately $3.7
million. The trust fund investments are comprised of various debt
securities of the United States and are carried at amortized cost, which
approximates their fair value.
15
<PAGE> 18
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
RESULTS OF OPERATIONS
The following table shows each revenue and expense category as a percentage of
total operating revenues:
<TABLE>
<CAPTION>
QUARTER ENDED NINE MONTHS ENDED SEPTEMBER
SEPTEMBER 30, 30,
------------- ---------------------------
2000 1999 2000 1999
---- ---- ---- ----
<S> <C> <C> <C> <C>
OPERATING REVENUES
85% 82% Revenues from wholly-owned operations 91% 84%
15% 18% Equity in earnings of unconsolidated affiliates 9% 16%
---------------- ------------ ---------------------------------------------------- -------------- --------------
100% 100% TOTAL OPERATING REVENUES 100% 100%
---------------- ------------ ---------------------------------------------------- -------------- --------------
OPERATING COSTS AND EXPENSES
51% 47% Cost of wholly-owned operations 57% 52%
6% 7% Depreciation and amortization 6% 8%
7% 12% General, administrative, and development 7% 19%
---------------- ------------ ---------------------------------------------------- -------------- --------------
64% 66% TOTAL OPERATING COSTS AND EXPENSES 70% 79%
---------------- ------------ ---------------------------------------------------- -------------- --------------
36% 34% OPERATING INCOME 30% 21%
---------------- ------------ ---------------------------------------------------- -------------- --------------
OTHER INCOME (EXPENSE)
- - Minority interest in earnings of consolidated - (1%)
Subsidiaries
- 1% Other income, net - 2%
(13%) (18%) Interest expense (15%) (20%)
---------------- ------------ ---------------------------------------------------- -------------- --------------
(13%) (17%) TOTAL OTHER EXPENSE (15%) (19%)
---------------- ------------ ---------------------------------------------------- -------------- --------------
23% 17% INCOME BEFORE INCOME TAXES 15% 2%
9% 1% INCOME TAX EXPENSE 6% 8%
---------------- ------------ ---------------------------------------------------- -------------- --------------
14% 16% NET INCOME 9% 10%
---------------- ------------ ---------------------------------------------------- -------------- --------------
</TABLE>
Net income for the three and nine months ended September 30, 2000, was
$88.6 million and $140.9 million, respectively, compared to $27.6 million and
$29.0 million, for the same periods in 1999. The increases of $61.0 million and
$111.9 million, respectively, were due to the factors described below.
OPERATING REVENUES
For the three and nine months ended September 30, 2000, total operating
revenues were $624.8 million and $1,469.8 million, respectively, an increase of
$454.4 million and $1,186.3 million over the same periods in 1999. For the three
and nine months ended September 30, 2000, revenues from wholly-owned operations
contributed approximately 85% and 91% to total operating revenues, compared to
82% and 84% for the same periods in 1999. For the three and nine months ended
September 30, 2000, Equity in earnings of unconsolidated affiliates contributed
approximately 15% and 9% to total operating revenues compared to 18% and 16% for
the same periods in 1999.
Revenues from wholly-owned operations, for the three and nine months ended
September 30, 2000 were $533.2 million and $1,339.7 million, respectively,
compared to $139.9 million and $237.9 million for the same periods in 1999.
Revenues from wholly-owned operations for the three and nine months ended
September 30, 2000 increased $393.2 million and $1,101.8 million, respectively,
compared to the same periods in 1999.
The increases of $393.2 million and $1,101.8 million for the three and nine
months ended September 30, 2000 as compared to the same periods in 1999 are due
primarily to the Company's acquisitions of electric generating assets during the
later portion of 1999 and the first and third quarter of 2000. During the later
portion of 1999, the Company acquired certain electric generating facilities in
the northeastern region of the United States (Arthur Kill Station,
16
<PAGE> 19
Astoria Gas Turbine Station, Connecticut Remote Jet Station, Devon Station,
Dunkirk Station, Huntley Station, Middletown Station, Montville Station, Norwalk
Harbor Station, Oswego Harbor Station). In addition, the Company acquired
certain electric generating facilities located in Louisiana and in England,
Louisiana Generating LLC and Killingholme Power Ltd, respectively at the end of
the first quarter of 2000. During the third quarter of 2000 the Company acquired
Flinders Power and the thermal operations, Harrisburg Steam Works and Statoil
Energy Power/Paxton L.P. These newly acquired generating facilities have
contributed significantly to the Company's growth in revenues during these
periods as compared to the same periods in 1999.
Equity in earnings of unconsolidated affiliates, for the three and nine
months ended September 30, 2000 was $91.6 million and $130.2 million,
respectively, compared to $30.4 million and $45.7 million for the same periods
in 1999. Revenues from equity in the earnings of unconsolidated affiliates for
the three and nine months ended September 30, 2000 increased $61.2 million and
$84.4 million, respectively, compared to the same periods in 1999.
The increases of $61.2 million and $84.4 million, for the three and nine
months ended September 30, 2000 as compared to the same period in 1999 are due
primarily to increased earnings from the Company's investment in West Coast
Power LLC and NRG Rocky Road LLC due to favorable weather conditions experienced
in the western portion of the United States in 2000. These increases were
partially offset by increased operating losses attributable to NEO Corporation
which derives a significant portion of its net income from Section 29 tax
credits.
OPERATING COSTS AND EXPENSES
Cost of wholly owned operations for the three and nine months ended
September 30, 2000, was $319.4 million and $840.3 million, respectively. These
are increases of $240.3 million and $692.1 million, over the same periods in
1999. Cost of wholly owned operations for the three and nine months ended
September 30, 2000 represented 51% and 57% of total operating revenues,
respectively, and represented 47% and 52% for the same periods in 1999.
The increases of $240.3 million and $692.1 million for the three and nine
months ended September 30, 2000 as compared to the same periods in 1999 are due
to the Company's acquisitions of electric generating assets during the later
portion of 1999 and the first and third quarters of 2000. During the later
portion of 1999, the Company acquired certain electric generating facilities in
the northeastern region of the United States (Arthur Kill Station, Astoria Gas
Turbine Station, Connecticut Remote Jet Station, Devon Station, Dunkirk Station,
Huntley Station, Middletown Station, Montville Station, Norwalk Harbor Station,
Oswego Harbor Station). In addition, the Company acquired certain electric
generating facilities located in Louisiana and in England, Louisiana Generating
LLC and Killingholme Power Ltd, respectively at the end of the first quarter of
2000. During the third quarter of 2000 the Company acquired Flinders Power and
the thermal operations, Harrisburg Steam Works and Statoil Energy Power/Paxton
L.P. The addition of these generating facilities and their respective costs of
operations, including fuel and other operating and maintenance costs, have
contributed significantly to the increase in the cost of wholly owned
operations.
Depreciation and amortization costs for the three and nine months ended
September 30, 2000 were $36.4 million and $87.3 million, respectively,
representing increases of $23.8 million and $63.6 million, over the same periods
in 1999. Depreciation and amortization costs represented 6% of total operating
revenues for both the three and nine months ended September 30, 2000 and 7% and
8%, for the same periods in 1999.
The increases of $23.8 million and $63.6 million for the three and nine
months ended September 30, 2000 as compared to the same periods in 1999, are due
primarily to the addition of property, plant and equipment related to the
Company's recently completed acquisitions of electric generating facilities. For
the three and nine months ended September 30, 2000 as compared to the same
periods in 1999, $5.0 million and $27.9 million of the increases relate to the
generating facilities acquired in the northeastern portion of the United States,
$6.8 million and 14.0 million of the increases relate to the generating
facilities acquired in the southern portion of the United States, $6.4 million
and 10.8 million of the increases relate to the Killingholme generating facility
and $2.8 million and $10.3 million of the respective increases relate to the
fourth quarter of 1999 increase in the Company's ownership in the Crockett
Cogeneration project.
General, administrative and development costs for the three and nine months
ended September 30, 2000 were $41.7 million and $98.0 million, respectively,
representing increases of $21.1 million and $45.1 million, over the same
17
<PAGE> 20
periods in 1999. General, administrative and development costs represented 7% of
total operating revenues for both the three and nine months ended September 30,
2000 and 12% and 19%, respectively, for the same periods in 1999.
The increases of $21.1 million and $45.1 million for the three and nine
months ended September 30, 2000 as compared to the same periods in 1999 are due
to increased business development activities, associated legal, technical, and
accounting expenses, employees and equipment resulting from expanded operations
and pending acquisitions. The Company's asset base increased from $3.4 billion
to $6.1 billion during the first nine months of 2000.
OTHER INCOME (EXPENSE)
Total other expense for the three and nine months ended September 30, 2000
was $84.0 million and $220.7 million, respectively. These are increases of $55.0
million and $167.0 million compared to the same periods in 1999. Total other
expense represented 13% and 15% of total operating revenues for the three and
nine months ended September 30, 2000, and 17% and 19%, respectively, for the
same periods in 1999.
The increase in total other expense of $55.0 million and $167.0 million for
the three and nine months ended September 30, 2000, respectively as compared to
the same period in 1999 consisted primarily of interest expense, minority
interest in earnings of consolidated subsidiaries, and other income, net.
Interest expense for the three and nine months ended September 30, 2000 was
$81.3 million and $215.4 million respectively, compared to $30.8 million and
$57.6 million for the same periods in 1999, increases of $50.5 million and
$157.8 million. Interest expense represented 13% and 15% of total operating
revenues, for the three and nine months ended September 30, 2000 and 18% and 20%
for the same periods in 1999. The increases of $50.5 million and $157.8 million
were due to increased corporate and project level debt issued during the three
and nine months ended September 30, 2000 as compared to the same periods in
1999. During the later portion of 1999, the Company acquired significant
electric generating facilities that were financed, in part, through a
combination of corporate level long term debt issuances and short term credit
facilities and from proceeds of the Company's initial public offering.
Minority interest in earnings of consolidated subsidiaries for the three
and nine months ended September 30, 2000 was $(3.1) million and $(7.2) million,
respectively, compared to $(0.4) million and $(1.5) million for the same periods
in 1999, increases of $2.7 million and $5.6 million. Minority interest in
earnings of consolidated subsidiaries represented less than 1% of total
operating revenues for the three and nine months ended September 30, 2000 and
1999, respectively. The increase of $2.7 million and $5.6 million for the three
and nine months ended September 30, 2000 is primarily due to the Company's
increased ownership interest in the Crockett Cogeneration project.
Other income, net for the three and nine months ended September 30, 2000,
was $0.03 million and $1.9 million, respectively, compared to $2.2 million and
$5.5 million for the same periods in 1999, decreases of $1.9 million and $3.6
million. Other income, net represented less than 1% for both, and 1% and 2% of
total operating revenues for the three and nine months ended September 30, 2000
and 1999, respectively. Other income, net consists primarily of interest income
on loans to affiliates and miscellaneous other items including the income
statement impact of certain foreign currency translation adjustments and the
income statement impacts of project write downs and gains and losses on the
disposition of investments. During the three and nine months ended September 30,
2000, other income decreased approximately $1.9 million and $3.6 million,
respectively as compared to the same period in 1999, primarily due to the
recognition of a gain on the disposition of a partnership interest in the third
quarter of 1999.
INCOME TAX
Income tax expense for the three and nine months ended September 30, 2000
was $54.6 million and $82.7 million respectively. These are increases of $56.0
million and $106.6 million compared to the same periods in 1999. The increases
in income tax expense of $56.0 million and $106.6 million for the three and nine
months ended September 30, 2000 as compared to the same periods in 1999 were due
primarily to higher domestic taxable income. These increases were partially
offset by additional Section 29 energy credits.
18
<PAGE> 21
For the nine months ended September 30, 2000, the Company's overall effective
income tax rate was approximately 37.0%, after recognition of certain tax
credits (primarily Section 29 energy credits) which account for an income tax
benefit of approximately 10.5%. The Company's effective tax rate before Section
29 energy credits is 47.5%. This rate is higher than a combined federal and
Minnesota statutory rate because a significant portion of the Company's income
is generated in New York City, an area with very high state and local tax rates.
In addition, the Company has recorded a valuation allowance on certain state and
foreign tax losses, also increasing the effective tax rate.
LIQUIDITY AND CAPITAL RESOURCES
During the nine months ended September 30, 2000, the Company's cash balance
increased $133.9 million to $165.4 million. During this period, the Company's
financing activities have provided cash totaling $2.0 billion. The Company's
financing activities raised $3.0 billion of gross proceeds from the issuance of
long-term debt partially offset by $1.1 billion of principal repayments and $0.3
billion of reductions in the Company's revolving line of credit balance. The
Company also raised $453.7 million of net proceeds through its initial public
offering of 32,395,500 shares of common stock. In addition to the Company's
financing activities, the Company generated $0.3 billion in cash from
operations. The Company utilized $1.9 billion of cash to complete the
acquisition of the Killingholme A and Cajun Electric Power Cooperative, Inc.,
Flinders Power electric generating assets, the recently acquired thermal
operations and to fund other capital expenditures.
During the nine month period ended September 30, 2000, the Company and its
subsidiaries completed the following long term financing activities. For a
discussion of short term borrowings, see Note 3 to the Financial Statements:
o In February 2000, NRG Northeast Generating LLC, a subsidiary of the
Company, issued $750 million of senior secured bonds to refinance
short-term project borrowings and for general funding purposes. The
bond offering included three tranches: $320 million with an interest
rate of 8.065% due in 2004, $130 million with an interest rate of
8.842% due in 2015 and $300 million with an interest rate of 9.292%
due in 2024.
o In March 2000, the Company issued (pound)160 million (approximately
$250 million at the time of issuance) of 7.97% reset senior notes due
2020, principally to finance its equity investment in the Killingholme
facility. On March 15, 2005, these senior notes may be remarketed by
Bank of America, N.A. at a fixed rate of interest through the maturity
date or, at a floating rate of interest for up to one year and then at
a fixed rate of interest through 2020. Interest is payable
semi-annually on these securities beginning September 15, 2000 through
March 15, 2005, and then at intervals and interest rates established
in the remarketing process.
o In March 2000, NRG South Central Generating LLC, a subsidiary of the
Company, issued $800 million of senior secured bonds in a two-part
offering. The first tranche was for $500 million with a coupon of
8.962 percent and a maturity of 2016. The second tranche was for $300
million with a coupon of 9.479 percent and a maturity of 2024. The
proceeds of these bonds were used to finance the Company's investment
in the Cajun generating facilities.
o In March 2000, three of the Company's foreign subsidiaries entered
into a (pound)325 million (approximately $471.2 million at October 31,
2000) secured borrowing facility agreement with Bank of America
International Limited, as arranger. Under this facility, the financial
institutions made available to our subsidiaries various term loans
totaling (pound)235 million (approximately $340.7 million at October
31, 2000) for the purpose of financing the acquisition of the
Killingholme facility and (pound)90 million ($130.5 million at October
31, 2000) of revolving credit and letter of credit facilities to
provide working capital for operating the Killingholme facility. The
final maturity date of the facility is the earlier of June 30, 2019,
or the date on which all borrowings and commitments under the largest
tranche of the term facility have been repaid or cancelled.
o During the second quarter of 2000, the Company completed an initial
public offering of 32,395,500 shares of its common stock priced at $15
per share. The net proceeds were $453.7 million. $300 million of the
proceeds were used to repay the Company's short-term bridge loan that
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was used to finance a portion of the acquisition of the Cajun
facilities. The remaining proceeds were used for general corporate
purposes including the reduction of the outstanding balance of the
Company's revolving line of credit.
In September 2000, the Company issued $350 million of senior secured bonds,
with an interest rate of 8.25% due in 2010. Interest is payable semi-annually on
these securities beginning March 15, 2001. The proceeds from these bonds were
used for repayment of short-term indebtedness incurred to fund acquisitions,
primarily Flinders Power and for investments and general corporate purpose.
The Company borrowed $40 million under a floating rate working capital
facility in which NRG South Central Generating LLC, an indirect wholly owned
subsidiary of the Company entered into in April 2000, the facility terminates in
March 2001.
The Company has entered into agreements for the purchase of certain
generating assets from Conectiv for approximately $800 million. Subject to
receipt of required regulatory approvals and satisfaction of other closing
conditions, this transaction is expected to close in early 2001. The Company
intends to finance this purchase with a combination of project-level and
corporate level debt. The Company has contracted to purchase 19 turbine
generators from General Electric for approximately $700 million, payable over
five years, as well as two turbines from Great River Energy for approximately
$43 million. In addition, the Company has signed a purchase agreement for a 50%
interest in the 522 MW coal-fired North Valmy Generating Station in Valmy,
Nevada and a 100% interest in 25 MW of peaking units near Valmy Station for
approximately $273.3 million in the first quarter of 2001. The Company also
signed a purchase agreement to acquire a 5,691 MW portfolio of operating
projects and projects in construction and advanced development from LS Power,
LLC for approximately $658 million during the first quarter of 2001.
The Company expects to finance its future capital requirements with a
combination of project-level debt, internally generated funds, corporate level
debt and additional equity. The Company's ability to arrange future financing is
dependent on a number of factors. To the extent the Company is unable to raise
additional capital on attractive terms either at the corporate level or on a
non-recourse project level, it would have a material adverse effect of the
Company's ability to grow.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." In June 2000, SFAS No. 138 was issued
which includes several amendments to SFAS No. 133. This new standard is
effective for all fiscal quarters of all fiscal years beginning after June 15,
2000. The Company plans to adopt this standard effective January 1, 2001,
as required.
The new standard requires that all derivatives be reported on the balance
sheet at their fair values. For derivative instruments designated as fair value
hedges, changes in the fair value of the derivative instrument will generally
be offset on the income statement by changes in the fair value of the hedged
item. For derivative instruments designated as cash flow hedges, the effective
portion of any hedge is reported in other comprehensive income until it is
cleared to earnings during the same period in which the hedged item affects
earnings. The ineffective portion of all hedges will be recognized in current
earnings each period. Changes in the fair value of derivative instruments that
are not designated as a hedge will be recorded each period in current earnings.
The Company has entered into certain transactions in accordance with its
risk management policy to mitigate the variability of its earnings. The
Company's risk management policy specifies that no more than 50% of the
uncommitted energy or capacity of any facility will be sold forward without
appropriate approvals. In accordance with its risk management policy, the
Company has entered into long-term contracts of more than one-year including:
power purchase agreements with utilities and other third parties, standard
offer agreements to provide load serving entities with a percentage of their
requirements and transition power purchase agreements with the former owners of
acquired facilities. The Company also enters into short-term contracts or other
commitments of one year or less and spot sales including: spot market and other
sales into various wholesale power markets and bilateral contracts with third
parties. In addition to energy and capacity sales agreements the Company enters
into transactions for the physical delivery of commodities used to generate
electricity. These physical delivery transactions may take the form of fixed
price, floating price or indexed sales or purchases and options on physical
transactions such as puts, calls, basis transactions and swaps. Contracts for
the transmission and transportation of these commodities are also entered into
as needed to meet physical delivery requirements and obligations.
The Company may also use derivative financial instruments to mitigate the
impact of changes in foreign currency exchange rates on its international
project cash flows and the impact of changes in interest rates on its cost of
borrowing.
The Company has identified certain of these transactions as potentially
being derivatives under SFAS No. 133. However, due to the uncertainties
involved in the interpretation of the application of SFAS No. 133, as amended
by SFAS No. 138, the Company has not yet determined what the impact might be of
the adoption of the standard on the Company's results of operations and
statement of financial position as of and for the period ended September 30,
2000. The Company believes that once additional clarifying guidance is made
available to the industry the potential impact of adopting the standard will be
more readily determinable.
ENVIRONMENTAL AND OTHER CONTINGENCIES
Air quality in the northeastern region of the United States is affected by
air pollution transported within and into the region by prevailing winds. In
September 1994, 11 Northeastern states and the District of Columbia signed a
memorandum of understanding (the MOU) establishing a regional plan for reducing
NOx emissions from utility and large industrial boilers. NOx contributes to the
formation of ozone. The 12 jurisdictions signing this MOU fall within the Ozone
Transport Region (the OTR), created under the Clean Air Act in recognition of
the regional ozone problem facing the northeastern United States. In addition to
the MOU, the EPA has issued a regulation requiring 22 states in the eastern half
of the United States to make significant NOx emission reductions by May 1, 2003,
and to subsequently cap those emissions (the SIP Call). The NOx emissions
reductions required by the SIP Call are comparable to the reductions required by
the MOU. By order of the United States Court of Appeals for the District of
Columbia Circuit, the compliance date for the SIP Call has been extended until
May 31, 2004.
NOx regulations for New York, Massachusetts and Connecticut to implement
the MOU have been promulgated through the year 2002, New York, Massachusetts and
Connecticut have also promulgated regulations to implement the SIP Call and the
MOU for the years 2003 and beyond. Consistent with the MOU and the SIP Call,
emissions reductions are to be achieved through a cap on ozone season NOx
emissions from the largest sources of NOx, including our facilities. Under
formulas established in the regulations, each source will be allocated a number
of "allowances," with each allowance representing one ton of NO that the source
is allowed to emit. The allowances can be bought and sold through regional
trading.
The Commonwealth of Massachusetts is seeking additional emissions
reductions beyond current requirements. The Massachusetts Department of
Environmental Protection has issued proposed regulations that would require
significant emissions reductions from certain coal-fired power plants in the
state, including the Company's Somerset facility. The Massachusetts Department
of Environmental Protection has proposed that such facilities comply with
stringent limits on emissions of nitrogen oxides by December 1, 2003; on
emissions of sulfur dioxides commencing on December 1, 2003, with further
reductions required by December 1, 2005; and on emissions of carbon dioxide by
December 1, 2005. In addition to output based limits (that is, a standard which
limits emissions to a certain rate per net megawatt hour), the proposed
regulations also would limit by December 1, 2005 the total emissions of nitrogen
oxides and sulfur dioxide at the Somerset facility to no more than 75% of the
average annual emissions from the Somerset facility for 1997-1999. Finally, the
proposed regulations require the Massachusetts Department of Environmental
Protection to evaluate, by December 31, 2002, the technical and economic
feasibility of controlling or eliminating mercury emissions by the year 2010,
and to propose mercury emission standards within 18 months of completion of the
feasibility evaluation. Compliance with these proposed regulations, if such
regulations become effective, could have a material impact on the operation of
the Company's Somerset facility. The Company believes that the annual average
carbon dioxide emission rate identified in the draft regulations cannot be met
by the Somerset facility. The public comment period for these rules closed in
August 2000. While we participated in this public process and provided comments
on August 4, 2000, there is no assurance that our positions will be adopted.
On May 17, 2000, Governor Rowland of Connecticut issued an Executive Order
to the Connecticut Department of Environmental Protection (CDEP) that requires
the CDEP to develop regulations, applicable to power plants and other major
sources of air pollution, to further reduce emissions of nitrogen oxides and
sulfur dioxides by May 2003. The Executive Order requires reductions of sulfur
dioxides by an amount that is 30% to 50% greater than current commitments and
reductions of nitrogen oxides that are 20% to 30% greater than current
commitments. The Executive Order provides that the CDEP should use market-based
incentives and a system of creditable emissions allowances or credits to foster
cost effective reductions. In August 2000, the CDEP issued proposed regulations
to implement the Executive Order. Although we are actively participating in the
CDEP's rulemaking process, there is no assurance that our positions will be
adopted.
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REGULATORY ISSUES
The independent system operators who oversee most of the wholesale power
markets in which the Company operates have in the past imposed, and may in the
future continue to impose, price limitations and other mechanisms to address
some of the volatility in these markets. These types of price limitations and
other mechanisms may adversely impact the profitability of our generation
facilities that sell energy into the wholesale power markets. Given the extreme
volatility and lack of meaningful long-term price history in many of these
markets, the Company cannot quantify the impact on profitability with any
certainty. The Company will attempt to adjust its business operations to
mitigate the future impact of such limitations.
On November 1, 2000, the FERC issued an order resulting from its
investigation of Summer 2000 wholesale markets in California (Docket EL00-95).
As part of the order, the FERC made certain jurisdictional wholesale sales made
under market-based rate authority subject to possible refund for a period of up
to 24 months. The Company owns all or portions of certain generating plants in
California which make wholesale sales at market-based rates subject to FERC
jurisdiction, and could be affected by the refund condition. The FERC order,
which is subject to potential requests for rehearing or appeals, thus could
affect future revenues and margins from wholesale sales into the California
market.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company uses derivative financial instruments to mitigate the impact of
changes in foreign currency exchange rates on its international project cash
flows, electricity and fuel prices on margins and interest rates on the cost of
borrowing.
The fair value of the Company's interest rate hedging contracts is
sensitive to changes in interest rates. As of September 30, 2000 a 10 percent
increase in interest rates from then prevailing market rates would have
increased the market value of the Company's interest rate hedging contracts by
approximately $22.3 million. Conversely, a 10 percent decrease in interest rates
from the prevailing market rates would have decreased the market value by
approximately $24.5 million. See Note 5 to the Financial Statements under Item 1
for further discussion of this matter.
O The Company entered into a swap agreement effectively converting the
7.5% fixed rate on $200 million of our Senior Notes due 2007 to a
variable rate based on the London Interbank Offered Rate. The swap
expires on June 1, 2009.
O A second swap effectively converts a $16 million issue of non-recourse
variable rate debt into a fixed rate debt. The swap expires on
September 30, 2002 and is secured by the Camas Power Boiler assets.
O A third swap converts $177 million of non-recourse variable rate debt
into fixed rate debt. The swap expires on December 17, 2014 and is
secured by the Crockett Cogeneration assets.
O A fourth swap converts (pound)188 million of non-recourse variable
rate debt into fixed rate debt. The swap expires on June 30, 2019 and
is secured by the Killingholme assets.
O A fifth swap converts AUD 105 million of non-recourse variable rate
debt into fixed rate debt. The swap expires on September 8, 2012 and
is secured by the Flinders Power assets.
The Company has an investment in the Kladno project in the Czech Republic.
Statement of Financial Accounting Standard (SFAS) No. 52, Foreign Currency
Translation, requires foreign currency gains and losses to flow through the
income statement if settlement of an obligation is in a currency other than the
local currency of the entity. A portion of the Kladno project debt is in a
non-local currency (U.S. dollars and German deutsche marks). As of September 30,
2000, if the value of the Czech koruna decreases by 10 percent in relation to
the U.S. dollar and the German deutsche mark, the Company would record a $4.9
million loss (after tax) on the currency transaction adjustment. If the value of
the Czech koruna increased by 10 percent, the Company would record a $4.9
million gain (after tax) on the currency transaction adjustment. These currency
fluctuations are inherent to the debt structure of the project and not
indicative of the long-term earnings potential of the investment. Kladno is the
only project the Company has at this time with this type of debt structure.
FORWARD-LOOKING STATEMENTS
Certain statements included in this quarterly report are forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. While the Company believes
that the expectations expressed in such forward-looking statements are
reasonable, it can give no assurances that these expectations will prove to have
been correct. In addition to any assumptions and other factors referred to
specifically in connection with such forward-looking statements, factors that
could cause the Company's actual results to differ materially from those
contemplated in any forward-looking statements include, among others, the
following:
o Economic conditions including inflation rates and monetary
fluctuations;
o Trade, monetary, fiscal, taxation, and environmental policies of
governments, agencies and similar organizations in geographic areas
where we have a financial interest;
o Customer business conditions including demand for their products or
services and supply of labor and materials used in creating their
products and services;
o Financial or regulatory accounting principles or policies imposed by
the Financial Accounting Standards Board, the Securities and Exchange
Commission, the Federal Energy Regulatory Commission and similar
entities with regulatory oversight;
o Availability or cost of capital such as changes in: interest rates;
market perceptions of the power generation industry, the Company or
any of its subsidiaries; or security ratings;
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o Factors affecting power generation operations such as unusual weather
conditions; catastrophic weather-related damage; unscheduled
generation outages, maintenance or repairs; unanticipated changes to
fossil fuel, or gas supply costs or availability due to higher demand,
shortages, transportation problems or other developments;
environmental incidents; or electric transmission or gas pipeline
system constraints;
o Employee workforce factors including loss or retirement of key
executives, collective bargaining agreements with union employees, or
work stoppages;
o Increased competition in the power generation industry;
o Cost and other effects of legal and administrative proceedings,
settlements, investigations and claims;
o Technological developments that result in competitive disadvantages
and create the potential for impairment of existing assets;
o Factors associated with various investments including conditions of
final legal closing, foreign government actions, foreign economic and
currency risks, political instability in foreign countries,
partnership actions, competition, operating risks, dependence on
certain suppliers and customers, domestic and foreign environmental
and energy regulations;
o Limitations on our ability to control the development or operation of
projects in which the Company has less than 100% interest;
o Other business or investment considerations that may be disclosed from
time to time in the Company's Securities and Exchange Commission
filings or in other publicly disseminated written documents, including
the Company's Registration Statement No. 333-35096, as amended.
The Company undertakes no obligation to 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 the Company's actual results to
differ materially from those contemplated in any forward-looking statements
included in this quarterly report should not be construed as exhaustive.
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PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
On or about July 12, 1999, Fortistar Capital Inc., a Delaware corporation, filed
a complaint in District Court (Fourth Judicial District, Hennepin County) in
Minnesota against the Company asserting claims for injunctive relief and for
damages as a result of the Company's alleged breach of a confidentiality letter
agreement with Fortistar relating to the Oswego facility.
The Company disputed Fortistar's allegations and has asserted numerous
counterclaims. The Company has counterclaimed against Fortistar for breach of
contract, fraud and negligent misrepresentations and omissions, unfair
competition and breach of the covenant of good faith and fair dealing. The
Company seeks, among other things, dismissal of Fortistar's complaint with
prejudice and rescission of the letter agreement.
A temporary injunction hearing was held on September 27, 1999. The acquisition
of the Oswego facility was closed on October 22, 1999, following notification to
the court of Oswego Power LLC's and Niagara Mohawk Power Corporation's intention
to close on that date. On January 14, 2000, the court denied Fortistar's request
for a temporary injunction. In April 2000, the Company filed a summary judgement
motion to dispose of the litigation. A hearing on this motion has not yet been
scheduled. The Company intends to continue to vigorously defend the suit and
believes Fortistar's complaint to be with out merit. No trial date has been set.
On May 25, 2000 the New York Department of Environmental Conservation issued a
Notice of Violation to the Company and the prior owner of the Huntley and
Dunkirk facilities relating to physical changes made at those facilities prior
to our assumption of ownership. The Notice of Violation alleges that these
changes represent major modifications undertaken without obtaining the required
permits. Although the Company has a right to indemnification by the previous
owner for fines, penalties, assessments, and related losses resulting from the
previous owner's failure to comply with environmental laws and regulations, if
these facilities did not comply with the applicable permit requirements, the
Company could be required, among other things, to install specified pollution
control technology to further reduce air emissions from the Dunkirk and Huntley
facilities and the Company could become subject to fines and penalties
associated with the current and prior operation of the facilities.
On May 31, 2000, FERC approved a request of the New York Independent System
Operator, to impose price limitations on one ancillary service, Ten Minute
Non-synchronized Reserves, on a prospective basis only, effective March 28,
2000; the date the NYISO began capping bids for that service. FERC rejected the
NYISO's request for authority to adjust the market clearing prices for that
service on a retroactive basis. As a result of the FERC order (unless the NYISO
or another party successfully appeals the order), the Company will retain the
approximately $8.0 million of revenues collected in February 2000 and
approximately $8.2 million included in revenues, but not collected, for March
2000. The NYISO sought reconsideration of the FERC order on June 30, 2000.
There are no other material legal proceedings pending, other than ordinary
routine litigation incidental to the Company's business, to which the Company is
a party. There are no material legal proceedings to which an officer or director
is a party or has a material interest adverse to the Company or its
subsidiaries. There are no other material administrative or judicial proceedings
arising under environmental quality or civil rights statutes pending or known to
be contemplated by governmental agencies to which the Company is or would be a
party.
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ITEM 5. OTHER
As of September 30, 2000, Minnesota Methane LLC, a 50% owned equity investment
and NEO Landfill Gas Inc., a wholly owned subsidiary of the Company, were in
technical default of certain debt covenants under two separate loan agreements
with United Capital, a division of Hudson United Bank. There have been no
financial ratios or payment defaults. As of September 30, 2000, Minnesota
Methane and NEO Landfill Gas owe $50.7 million and $26.7 million, respectively,
under these loan agreements. On October 5, 2000 and November 6, 2000, Minnesota
Methane and NEO Landfill Gas received waivers of default. These waivers are
effective as long as Minnesota Methane and NEO Landfill Gas continue to use
their best efforts to achieve compliance with the terms of the waivers.
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ITEM 6. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(A) EXHIBITS
27 Financial Data Schedule for the period ended September 30, 2000.
(B) REPORTS ON FORM 8-K:
On September 7, 2000, the Company filed a Form 8-K reporting under Item 5.
Other Events.
The Company filed certain exhibits relating to its September 7, 2000
prospectus supplement dated September 6, 2000 related to the offering
of $350 million principal amount of the Company's 8.25% Senior notes
due 2010.
On September 13, 2000, the Company filed a Form 8-K reporting under Item 5.
Other Events.
The Company filed certain exhibits relating to the completion of its
offering $350 million principal amount of the Company's 8.25% Senior
notes due 2010.
On September 25, 2000, the Company filed a Form 8-K reporting under Item 5.
Other Events.
The Company announced acquisition of the Flinders Power assets.
On September 27, 2000, the Company filed a Form 8-K reporting under Item 5.
Other Events.
The Company announced that it expected earnings for the third quarter
of 2000 to be approximately 45 cents per share and expects calendar
year earnings to be $1.00 per share.
On October 31, 2000, the Company filed a Form 8-K reporting under Item 5.
Other Events.
The Company reported its financial results for the three and nine
months ended September 30, 2000.
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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/ Leonard A. Bluhm
-----------------------------------------
Leonard A. Bluhm
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
/s/ William T. Pieper
-----------------------------------------
William T. Pieper
Controller
(Principal Accounting Officer)
Date: November 14, 2000
27
