<PAGE> 1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
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 Quarter Ended September 30, 1999 Commission File Number 333-33397
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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)
1221 Nicollet Mall, Minneapolis, Minnesota 55403
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(Address of principal executive officers) (Zip Code)
Registrant's telephone number, including area code (612) 373-5300
---------------------------
None
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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 11, 1999
---------------------- --------------------------------
Common Stock, $1.00 par value 1,000 Shares
All outstanding common stock of NRG Energy, Inc., is owned beneficially
and of record by Northern States Power Company, a Minnesota corporation.
The Registrant meets the conditions set forth in general instruction H
(1) (a) and (b) of Form 10-Q and is therefore filing this form with the reduced
disclosure format.
<PAGE> 2
INDEX
<TABLE>
<CAPTION>
PAGE NO.
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PART I
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<S> <C> <C>
Item 1 Consolidated Financial Statements and Notes
Consolidated Statements of Income 1
Consolidated Balance Sheets 2-3
Consolidated Statements of Stockholder's Equity 4
Consolidated Statements of Cash Flows 5
Notes to Consolidated Financial Statements 6-9
Item 2 Management's Discussion and Analysis of Financial
Condition and Results of Operations 10-12
PART II
-------
Item 1 Legal Proceedings 13
Item 6 Exhibits, Financial Statement Schedules, and Reports 14
on Form 8-K
SIGNATURES 15
</TABLE>
<PAGE> 3
CONSOLIDATED STATEMENTS OF INCOME
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
(Thousands of Dollars) 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 139,974 $ 25,047 $ 237,855 $ 74,829
Equity in earnings of unconsolidated affiliates 30,434 29,249 45,726 58,432
- ----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 170,408 54,296 283,581 133,261
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OPERATING COSTS AND EXPENSES
Cost of wholly-owned operations 79,147 13,079 148,211 39,384
Depreciation and amortization 12,663 4,511 23,688 12,560
General, administrative, and development 20,650 15,201 52,923 39,581
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Total operating costs and expenses 112,460 32,791 224,822 91,525
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OPERATING INCOME 57,948 21,505 58,759 41,736
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OTHER INCOME (EXPENSE)
Minority interest in earnings of consolidated subsidiaries (382) (492) (1,537) (1,652)
Write-down of investment in projects - (23,410) - (23,410)
Other income, net 2,196 1,206 5,504 3,105
Interest expense (30,760) (13,598) (57,607) (37,849)
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Total other expense (28,946) (36,294) (53,640) (59,806)
- ----------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES 29,002 (14,789) 5,119 (18,070)
INCOME TAX EXPENSE (BENEFIT) 1,395 (10,014) (23,889) (26,353)
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NET INCOME $ 27,607 $ (4,775) $ 29,008 $ 8,283
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</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,
(Thousands of Dollars) 1999 1998
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<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 25,236 $ 6,381
Restricted cash 2,122 4,021
Accounts receivable-trade, less allowance
for doubtful accounts of $110 and $100 84,721 15,223
Accounts receivable-affiliates 33,879 7,324
Current portion of notes receivable - affiliates 11,461 4,460
Current portion of notes receivable - 26,200
Income taxes receivable - 21,169
Inventory 59,535 2,647
Prepayments and other current assets 15,086 4,533
- ------------------------------------------------------------------------------------------------------------------
Total current assets 232,040 91,958
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PROPERTY, PLANT AND EQUIPMENT, AT ORIGINAL COST
In service 1,229,082 291,558
Under construction 17,173 5,352
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1,246,255 296,910
Less accumulated depreciation (116,019) (92,181)
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Net property, plant and equipment 1,130,236 204,729
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OTHER ASSETS
Investments in projects 894,106 800,924
Capitalized project costs 53,475 13,685
Notes receivable, less current portion - affiliates 96,589 101,887
Notes receivable, less current portion 5,324 3,744
Intangible assets, net of accumulated amortization of $4,292 and $2,984 49,743 22,507
Debt issuance costs, net of accumulated amortization of $4,545 and $1,675 15,543 7,276
Other assets, net of accumulated amortization of $8,395 and $7,350 49,305 46,716
- ------------------------------------------------------------------------------------------------------------------
Total other assets 1,164,085 996,739
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TOTAL ASSETS $ 2,526,361 $ 1,293,426
==================================================================================================================
</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,
1999 1998
- --------------------------------------------------------------------------------------------
<S> <C> <C>
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES
Current portion of long-term debt $ 26,707 $ 8,258
Revolving line of credit 208,000 -
Consolidated project-level, non-recourse debt 613,890 -
Accounts payable-trade 46,094 7,371
Income taxes payable 11,356 -
Accrued property and sales taxes 6,006 3,251
Accrued salaries, benefits and related costs 6,836 7,551
Accrued interest 18,202 7,648
Other current liabilities 22,662 8,289
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Total current liabilities 959,753 42,368
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MINORITY INTEREST 12,998 13,516
CONSOLIDATED PROJECT-LEVEL, LONG TERM, NONRECOURSE DEBT 122,348 113,437
CORPORATE LEVEL LONG-TERM DEBT, LESS CURRENT PORTION 675,000 504,781
DEFERRED INCOME TAXES 6,282 19,841
DEFERRED INVESTMENT TAX CREDITS 1,152 1,343
POSTRETIREMENT AND OTHER BENEFIT OBLIGATIONS 16,078 11,060
DEFERRED INCOME AND OTHER LONG-TERM OBLIGATIONS 10,507 7,748
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Total liabilities 1,804,118 714,094
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STOCKHOLDER'S EQUITY
Common stock; $1 par value; 1,000 shares authorized;
1,000 shares issued and outstanding 1 1
Additional paid-in capital 631,913 531,913
Retained earnings 159,023 130,015
Accumulated other comprehensive income (68,694) (82,597)
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Total Stockholder's Equity 722,243 579,332
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TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 2,526,361 $ 1,293,426
- --------------------------------------------------------------------------------------------
</TABLE>
See notes to consolidated financial statements.
3
<PAGE> 6
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
NRG ENERGY, INC. AND SUBSIDIARIES
(UNAUDITED)
<TABLE>
<CAPTION>
Accumulated
Additional Other Total
Common Paid-in Retained Comprehensive Stockholder's
(Thousands of Dollars) Stock Capital Earnings Income Equity
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<S> <C> <C> <C> <C> <C>
BALANCES AT JANUARY 1, 1998 $ 1 $ 431,913 $ 88,283 $ (69,499) $ 450,698
Net Income 8,283 8,283
Foreign currency translation adjustments (23,150) (23,150)
--------------
Comprehensive income (14,867)
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BALANCES AT SEPTEMBER 30, 1998 $ 1 $ 431,913 $ 96,566 $ (92,649) $ 435,831
--------------------------------------------------------------------------------------
BALANCES AT JANUARY 1, 1999 $ 1 $ 531,913 $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 $ 631,913 $159,023 $ (68,694) $ 722,243
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</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,
(Thousands of Dollars) 1999 1998
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 29,008 $ 8,283
Adjustments to reconcile net income to net cash
provided (used) by operating activities
Undistributed equity earnings of unconsolidated affiliates (1,363) (29,873)
Depreciation and amortization 23,688 12,560
Deferred income taxes and investment tax credits (13,750) (7,601)
Minority interest (518) -
Write-down of investment in projects - 23,410
Cash provided (used) by changes in certain working capital items,
net of acquisition effects
Accounts receivable (67,958) (197)
Accounts receivable-affiliates (26,555) 13,934
Income tax receivable 21,169 (3,692)
Inventory (16,945) -
Prepayments and other current assets (10,553) (3,043)
Accounts payable-trade 38,723 (8,636)
Income taxes payable 11,356 -
Accrued property and sales tax 2,755 (512)
Accrued salaries, benefits and related costs (857) 1,274
Accrued interest 10,554 4,430
Other current liabilities 2,260 1,742
Cash used by changes in other assets and liabilities (12,451) 2,808
- ----------------------------------------------------------------------------------------------------------
NET CASH (USED) PROVIDED BY OPERATING ACTIVITIES (11,437) 14,887
- ----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of liabilities assumed (930,185) -
Investments in projects (118,231) (124,903)
Divestiture of projects 1,000 9,219
Changes in notes receivable (net) 22,917 20,918
Purchase of plant, property and equipment (62,099) (23,265)
Decrease (increase) in restricted cash 1,899 (2,341)
- ----------------------------------------------------------------------------------------------------------
NET CASH USED BY INVESTING ACTIVITIES (1,084,699) (120,372)
- ----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions from parent 100,000 -
Revolving line of credit 84,000 103,000
Proceeds from issuance of note 613,890 -
Proceeds from issuance of long-term debt 326,713 22,658
Principal payments on long-term debt (9,612) (18,187)
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NET CASH PROVIDED BY FINANCING ACTIVITIES 1,114,991 107,471
- ----------------------------------------------------------------------------------------------------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 18,855 1,986
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,381 11,986
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CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 25,236 $ 13,972
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</TABLE>
See notes to consolidated financial statements.
5
<PAGE> 8
NRG ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company is a wholly owned subsidiary of Northern States Power Company (NSP),
a Minnesota corporation. Additional information regarding the Company can be
found in NSP's Form 10-Q for the nine months ended September 30, 1999.
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, 1998 (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 financial
statements contain all material adjustments necessary to present fairly the
consolidated financial position of the Company as of September 30, 1999 and
December 31, 1998, the results of its operations for the three and nine months
ended September 30, 1999 and 1998, and its cash flows and stockholders' equity
for the nine months ended September 30, 1999 and 1998.
1. BUSINESS DEVELOPMENTS
In February 1999, the Company purchased from Thermal Ventures, Inc. (TVI)
the remaining 50.1% limited partnership interests held by TVI in San
Francisco Thermal Limited Partnership and Pittsburgh Thermal Limited
Partnership for $12.3 million. In April 1999, NRG acquired TVI's 50% member
interest in North American Thermal Systems LLC (the entity holding the
general partnership interest in the San Francisco and Pittsburgh
partnerships) for $500,000.
In April 1999, the Company completed the acquisition of the Somerset power
station for approximately $55 million from the Eastern Utilities
Association (EUA). The Somerset station, located in Somerset,
Massachusetts, includes two coal-fired generating facilities and two
aeroderivative combustion turbine peaking units with a nominal capacity
rating of 160 MW.
In May 1999, the Company and Dynegy, through West Coast Power LLC,
completed the acquisition of the Encina generating station and 17
combustion turbines for approximately $356 million from San Diego Gas &
Electric Company. The facilities, which have a combined nominal capacity
rating of 1,218 MW, are located near Carlsbad and San Diego, California.
The Company and Dynegy each own a 50% interest in these facilities.
In June 1999, the Company completed its acquisition of the Huntley and
Dunkirk generating stations from Niagara Mohawk Power Corporation (NIMO)
for approximately $355 million. The two coal-fired power generation
facilities are located near Buffalo, New York, and have a combined summer
capacity rating of 1,360 MW.
In June 1999, the Company completed its acquisition of the Arthur Kill
generating station and the Astoria gas turbine site from Consolidated
Edison Company of New York, Inc. for approximately $505 million. These
facilities, which are located in the New York City area, have a combined
nominal capacity rating of 1,456 MW.
6
<PAGE> 9
The Company, together with its partner and the Creditor's committee, filed
a plan with the United States Bankruptcy Court for the Middle District of
Louisiana to acquire 1,708 MW of fossil generating assets from Cajun
Electric Power Cooperative of Baton Rouge, Louisiana (Cajun) for
approximately $1.0 billion. During the third quarter, the U.S. Bankruptcy
Judge confirmed the Company's Plan of Reorganization and the Company
exercised an option to purchase its partner's 50-percent interest in the
project. The Company expects to close the acquisition of the Cajun assets
at the end of the first quarter of 2000.
In August, the Company agreed to sell all but a 20 percent ownership
interest in Cogeneration Corporation of America (CogenAmerica) to Calpine
Corporation in connection with Calpine's acquisition of the remaining
shares of CogenAmerica. The Company currently owns approximately 45 percent
of CogenAmerica and upon the closing of the proposed transaction, all
outstanding shares of CogenAmerica common stock (other than those to be
retained by the Company) will be acquired by Calpine for a cash purchase
price of $25.00 per share. The Company will retain a 20-percent ownership
interest in CogenAmerica. The transaction is expected to close during the
fourth quarter of 1999.
In October 1999, the Company completed its acquisition of the Oswego
generating station from NIMO and Rochester Gas and Electric for
approximately $85 million. The oil and gas-fired power generating facility,
which has a nominal capacity rating of 1,700 MW is located on a 93-acre
site in Oswego, New York.
In October 1999, the Company entered into a Standard Offer Service
Wholesale Sales Agreement with Connecticut Light And Power Company (CL&P)
pursuant to which the Company will supply CL&P with 35% of its standard
offer service load during 2000, 40% during 2001 and 2002 and 45% during
2003. In July 1999, the Company executed an agreement to acquire four
fossil fuel generating stations and numerous remote gas turbines from CL&P
for approximately $460 million. These facilities have a combined nominal
capacity rating of 2,235 MW. The Company expects the transaction to close
during the fourth quarter of 1999.
2. CONTINGENT REVENUES
The Company and its partner Dynegy each own a 50% interest in the Long
Beach and El Segundo generating stations ("California Projects"). During
1998, the first year of deregulation of the state of California power
industry, the California Projects accrued certain receivables related to
contingent revenues. These revenues have been deferred pending resolution
of the contingency. Such amounts relate to items that are subject to
contract interpretations, compliance with processes and filed market
disputes. The California Projects are actively pursuing resolution and/or
collection of these amounts, which totaled approximately $40 million (the
Company's share approximates $20 million) as of September 30, 1999. No
assurance can be given that any of these deferred revenues will be
collected, however, if collected, such deferred revenues will be recognized
in the Company's equity income.
3. SUMMARIZED INCOME STATEMENT INFORMATION OF AFFILIATES
The Company has 20-50% investments in four companies 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:
7
<PAGE> 10
<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
(Thousands of Dollars) 1999 1998 1999 1998
------------------------ -----------------------
<S> <C> <C> <C> <C>
Net sales $ 186,573 $ 209,035 $ 506,994 $ 516,588
Other income (expense) (13,000) 712 - 179
Costs and expenses:
Cost of sales 143,674 146,539 381,077 390,340
Depreciation and amortization 7,785 2,049 7,785 4,079
General and administrative (31,745) 5,416 17,827 17,964
------------------------ -----------------------
119,714 154,004 406,689 412,383
------------------------ -----------------------
Income before income taxes 53,859 55,743 100,305 104,384
Income taxes 9,903 19,998 21,739 28,817
------------------------ -----------------------
Net income $ 43,956 $ 35,745 $ 78,566 $ 75,567
======================== =======================
Company's share of net income $ 16,572 $ 16,981 $ 31,167 $ 32,648
======================== =======================
</TABLE>
4. SHORT TERM BORROWINGS
At September 30, 1999, the Company had $613.9 million in short-term project
level borrowings at an average interest rate of 6.62% used for project
acquisitions. The Company has $686.6 million of available borrowing under
this credit facility. The Company plans to refinance this short-term
project-level borrowing with long-term project-level debt later this year.
As of September 30, 1999, the Company had $350 million in revolving credit
facilities under a commitment fee arrangement. These facilities provide
short-term financing in the form of bank loans and letters of credit. At
September 30, 1999, the Company has $208 million outstanding under its
revolving credit agreements.
5. LONG TERM DEBT
In March 1999, the Company filed a shelf registration statement with the
Securities and Exchange Commission for up to $500 million in debt
securities. The net proceeds will be used to finance the Company's equity
investments in connection with pending acquisitions and for general
corporate purposes, which may include financing the development and
construction of new facilities, working capital, debt reduction and capital
expenditures. In May 1999, the Company issued $300 million of 7.5% senior
notes due in 2009 under this registration statement. In September 1999, the
Company entered into a $200 million swap agreement effectively converting
the 7.5% fixed rate on these senior notes to a variable rate based on
LIBOR. In November 1999, the Company issued $240 million of Remarketable or
Redeemable Securities (ROARS) with an 8 percent coupon, a re-marketing date
of November 2003 and a final maturity of November 2013.
During the third quarter of 1999 NRG Northeast Generating LLC (N.E.
Generating), a wholly owned subsidiary of the Company, entered into $600
million of treasury locks at various interest rates. These treasury locks,
which expire in February of 2000, are an interest rate hedge of N.E.
Generating's anticipated bond offering in the first quarter of 2000. The
proceeds of any such bond offering will be used to pay off N.E.
Generating's currently existing short-term credit facility.
6. SEGMENT REPORTING
The Company 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 the Company
with separate operating results and management structures in place. 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, 1999 and 1998 are as follows:
8
<PAGE> 11
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30, 1999 INDEPENDENT
(Thousands of Dollars) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
affiliates 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
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30, 1998 INDEPENDENT
(Thousands of Dollars) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 307 $ 7,642 $ 13,293 $ 3,446 $ 24,688
Intersegment revenues - 359 - - 359
Equity in earnings of unconsolidated
affiliates 29,678 (361) 58 (126) 29,249
-----------------------------------------------------------------
Total operating revenues 29,985 7,640 13,351 3,320 54,296
-----------------------------------------------------------------
NET INCOME (LOSS) $ 14,077 $ 3,247 $ 1,553 $(23,653) $ (4,776)
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, 1999 INDEPENDENT
(Thousands of Dollars) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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 $ 4,682 $(38,320) $ 29,008
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, 1998 INDEPENDENT
(Thousands of Dollars) POWER ALTERNATIVE
GENERATION ENERGY THERMAL OTHER TOTAL
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES
Revenues from wholly-owned operations $ 1,165 $ 22,994 $ 39,946 $ 9,683 $ 73,788
Intersegment revenues - 1,041 - - 1,041
Equity in earnings of unconsolidated
affiliates 58,629 13 294 (504) 58,432
-----------------------------------------------------------------
Total operating revenues 59,794 24,048 40,240 9,179 133,261
-----------------------------------------------------------------
NET INCOME (LOSS) $ 35,324 $ 12,095 $ 4,490 $(43,626) $ 8,283
</TABLE>
7. FINANCIAL INSTRUMENTS
During the first quarter of 1999, the Company entered into a forward
contract to exchange approximately $10.5 million of U.S. dollars for
British pounds. This foreign exchange contract, which expires in December,
1999 is a hedge of the Company's equity commitment to the Enfield project
currently under construction in England.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." This statement requires that all
derivatives be recognized at fair value in the Balance Sheet, and that
changes in fair value be recognized either currently in earnings or
deferred as a component of Other Comprehensive Income, depending on the
intended use of the derivative, its resulting designation and its
effectiveness. The Company plans to adopt this standard in 2001, as
required. The Company has not determined the potential impact of
implementing this statement.
9
<PAGE> 12
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition is omitted
per conditions as set forth in General Instructions H (1) (a) and (b) of Form
10-Q for wholly owned subsidiaries. It is replaced with management's narrative
analysis of the results of operations as permitted by General Instructions H (2)
(a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format). This
analysis compares the Company's revenue and expense items for the nine months
ended September 30, 1999 with the nine months ended September 30, 1998.
RESULTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 1999 COMPARED TO NINE MONTHS
ENDED SEPTEMBER 30, 1998
Net income for the nine months ended September 30, 1999, was $29.0
million compared to $8.3 million for the same period in 1998. The increase in
net income of $20.7 million was due to the factors described below.
OPERATING REVENUES
For the nine months ended September 30, 1999, revenues were $283.6
million, an increase of $150.3 million, or 113%, over the same period in 1998.
The operating revenues from wholly owned operations for the nine months
ended September 30, 1999 were $237.9 million, an increase of $163.0 million, or
218%, over the same period in 1998. Approximately $115.5 million of the increase
relates to the Dunkirk, Huntley, Somerset, Astoria and Arthur Kill facilities
that were acquired during the second quarter of 1999. Approximately $41.3
million of the increase is from energy sales to Eastern Utilities Association
(EUA) under an agreement that went into effect on January 1, 1999. Under the
terms of the power sales agreement, the Company will provide various affiliates
of EUA with a fixed percentage of their energy needs for a period of 6.2 to 11
years. In addition, approximately $15.5 million of the increased revenues
relates to the Company's increased ownership in the Pittsburgh and San Francisco
Thermal operations as a result of the acquisition of the remaining 50% interest
in these projects in April, 1999. For the nine months ended September 30, 1999,
revenues from wholly owned operations consisted of revenue from electrical
generation (77%), heating, cooling and thermal activities (20%) and technical
services (3%).
Equity in earnings of unconsolidated affiliates was $45.7 million for
the nine months ended September 30, 1999, compared to $58.4 million for the nine
months ended September 30, 1998, a decrease of $12.7 million, or 22%. The
decrease was due to several factors, including a $6.8 million reduction in
earnings from the Mt. Poso project primarily due to curtailment revenues that
were recorded in 1998, a $3.9 million decrease in earnings from West Coast Power
LLC due to cooler weather conditions partially offset by earnings from the
Encina facility which was acquired during the second quarter of 1999. In
addition, there was a $2.1 million net decrease in equity earnings due to a
transaction adjustment related to the Kladno Project. A portion of the Kladno
project's debt is denominated in U.S. dollars and German deutsche marks, which
strengthened against the Czech koruna in the first six months of 1999. Under
SFAS No. 52, Foreign Currency Translation, the Kladno project records foreign
currency gains and losses through the income statement.
OPERATING COSTS AND EXPENSES
Cost of wholly owned operations was $148.2 million for the nine months
ended September 30, 1999. This is an increase of $108.8 million, or 276%, over
the same period in 1998. The increase is due to increased operating costs from
new acquisitions and energy purchases made to satisfy the EUA power sales
agreement.
10
<PAGE> 13
Depreciation and amortization costs were $23.7 million for the nine
months ended September 30, 1999, compared to $12.6 million for the nine months
ended September 30, 1998. The depreciation and amortization increase was due
primarily to the acquisition of new projects, including the Somerset, Dunkirk,
Huntley, Astoria and Arthur Kill facilities and depreciation from the Pittsburgh
and San Francisco thermal facilities that were previously recorded on the equity
method of accounting.
General, administrative and development costs were $52.9 million for
the nine months ended September 30, 1999, compared to $39.6 million for the nine
months ended September 30, 1998. The $13.3 million increase was due primarily to
increased business development activities, associated legal, technical, and
accounting expenses, labor and other costs resulting from expanded operations
and pending acquisitions. The Company's total assets increased from
approximately $1.3 billion to approximately $2.5 billion during the first nine
months of 1999.
OTHER INCOME (EXPENSE)
Other expense for the nine months ended September 30, 1999, was $53.6
million, a decrease of $6.2 million from $59.8 million for the same period in
1998. The decrease was due to a $23.4 million write-down that was recorded in
the third quarter of 1998 related to the West Java project in Indonesia and
other projects. This amount was partially offset by $19.8 million of additional
interest costs in 1999 related to the issuance of $300 million of 7.5% senior
notes in May 1999 and approximately $540 million of additional short-term debt.
INCOME TAX
The Company recognized an income tax benefit due to a pre-tax loss from
domestic operations and due to the recognition of certain tax credits. The net
income tax benefit for the nine months ended September 30, 1999, decreased by
$2.5 million to $23.9 million as compared to $26.4 million for the same period
during 1998. The decrease in tax benefits for the nine month period was due
primarily to increased earnings from domestic operations.
YEAR 2000 (Y2K) READINESS
To the extent allowed, the information in the following section is
designated as a "Year 2000 Readiness Disclosure." The Company continues to incur
costs to modify or replace existing technology, including computer software, for
uninterrupted operation in the year 2000 and beyond. A committee made up of
senior management is leading the Company's initiatives to identify Y2K related
issues and remediate business processes as necessary. The Company is also
partnering with its parent, Northern States Power Company, to ensure a
consistent overall company process in addressing the Y2K issue, as discussed in
the Company's 1998 Form 10-K.
The Company is on schedule for completion of its Y2K project based on the
following revised timetable.
- - Assessment/discovery/analysis - Completed
- - Final testing - Completed
- - Y2K Ready - November 15, 1999
The Company is currently updating contingency plans for all material
Y2K risks and is on track to meet the contingency planning schedule that has
been established. In addition to Y2K readiness, the Company's contingency
planning addresses the failure of key third party contracts to be Y2K compliant.
A Y2K readiness plan is obtained as part of all new acquisitions.
FORWARD-LOOKING STATEMENTS
This quarterly report on Form 10-Q includes forward-looking statements that
are subject to certain risks, uncertainties and assumptions. Such
forward-looking statements are intended to be identified in this document by the
words "anticipate," "estimate," "expect," "objective," "possible," "potential"
and similar expressions. Without limitation, forward-looking statements are
contained under the heading "business developments". In addition to any
assumptions and other factors referred to specifically in connection with such
forward looking statements, factors that could cause the actual results to
differ materially from those contemplated in any forward-looking statements
include among others the following: the failure to timely satisfy the closing
11
<PAGE> 14
conditions contained in definitive agreements for transactions not yet closed,
including obtaining all necessary regulatory approvals, many of which are beyond
the Company's control; limitations on the Company's ability to control projects
or transactions in which the Company has less than 100% interest; and other
business or investment considerations that may be disclosed from time to time in
the Company's Securities and Exchange Commission filings and in other publicly
disseminated written documents, including the Company's registration statement
number 333-74519, as amended, and all supplements thereto.
The Company undertakes no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. The foregoing review of factors should not be construed as
exhaustive.
12
<PAGE> 15
PART II
ITEM 1. LEGAL PROCEEDINGS
On or about July 12, 1999, Fortistar Capital, Inc. ("Fortistar") commenced
an action against the Company in Hennepin County (Minnesota) District
Court, seeking damages in excess of $100 million and an order restraining
the Company from consummating the acquisition of NIMO's Oswego generating
station. Fortistar's motion for a temporary restraining order was denied
and a temporary injunction hearing was held on September 27, 1999. The
acquisition of the Oswego generating station was closed on October 22, 1999
following notification to the Court of the closing date. The Company
intends to continue to vigorously defend the suit and believes Fortistar's
claims to be without merit. The Company has asserted numerous counterclaims
against Fortistar.
13
<PAGE> 16
PART II
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS
10.31 First Amendment to the Employment Agreement of David H.
Peterson, dated June 27, 1999.
10.32 Second Amendment to the Employment Agreement of David H.
Peterson, dated August 26, 1999.
10.33 Third Amendment to the Employment Agreement of David H.
Peterson, dated October 20, 1999.
10.34 [Swap] Master Agreement between Niagara Mohawk Power
Corporation and NRG Power Marketing, Inc., dated
June 11, 1999.
10.35 Standard Offer Service Wholesale Sales Agreement between
the Connecticut Light And Power Company and NRG Power
Marketing, Inc., dated October 29, 1999.
27 Financial data schedule for the period ended September 30,
1999.
(B) REPORTS ON FORM 8-K:
On July 8, 1999, NRG filed a Form 8-K reporting under Item 5 - Other
Events. NRG announced its acquisition of the Arthur Kill and Astoria
generating assets from the Consolidated Edison Company of New York,
Inc.
On July 16, 1999, NRG filed a Form 8-K reporting under Item 5 - Other
Events. NRG announced that earnings for the six months ended June 30,
1999 would be below expectations.
On September 14, 1999 NRG filed a Form 8-K reporting under Item 5 -
Other Events. NRG announced forecasted earnings for the twelve months
ending December 31, 1999 and 2000.
On October 14, 1999, NRG filed a Form 8-K reporting under Item 5 -
Other Events. NRG announced earnings for the nine months ended
September 30, 1999 and reduced its forecast for the twelve months
ending December 31, 1999.
On November 3, 1999 NRG filed a Form 8-K reporting under Item 5 - Other
Events. NRG filed certain exhibits relating to the offering of $240
million principal amount of the Company's 8.0% Remarketable or
Redeemable Securities (ROARS) due November 1, 2013 (Remarketing date
November 1, 2003).
14
<PAGE> 17
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/ David E. Ripka
----------------------------------
David E. Ripka
Vice President and Controller
(Principal Accounting Officer)
Date: November 12, 1999
------------------------
15
<PAGE> 1
EXHIBIT 10.31
FIRST AMENDMENT TO THE
EMPLOYMENT AGREEMENT OF DAVID H. PETERSON
WHEREAS, David H. Peterson (the "Executive") and NRG Energy Inc. ("NRG")
have previously entered into an Employment Agreement (the "Agreement") dated
June 28, 1995; and
WHEREAS, Section 3(c)(i) of the Agreement provides that Executive may
request a lump sum payment option of the benefit described therein provided
that Executive requests said lump sum payment not less than twelve (12) months
prior to Executive's termination of employment; and
WHEREAS, NRG and Executive wish to amend the Agreement to permit the
request to be made not less than ten (10) months prior to Executive's
termination of employment.
RESOLVED, that Section 3(c)(i) of the Agreement is hereby amended to
substitute the word "ten" for the word "twelve" in the second sentence thereof.
RESOLVED FURTHER, that the Agreement as amended, shall remain in
fullforce and effect.
/s/ David H. Peterson Date: 6/27/99
- ----------------------------- -------------------------
David H. Peterson
NRG Energy Inc.
By /s/ Gary R. Johnson Date: 6/25/99
-------------------------- -------------------------
Its Director
-------------------------
<PAGE> 1
EXHIBIT 10.32
NORTHERN STATES POWER COMPANY
825 Rice Street Cynthia L. Lesher
St. Paul, Minnesota 55117-6485 President
Telephone (651) 229-2592 NSP Gas
August 26, 1999
Dave Peterson
NRG Energy, Incorporated VIA FACSIMILE
Suite 700 AND U.S. MAIL
1221 Nicollet Mall
Minneapolis, Minnesota 55403
Dear Dave:
As you know, the period of time during which you may request a lump sum payment
under your employment agreement expires tomorrow. Due to the ongoing
discussions regarding the extension of your agreement and how to best
coordinate the extension with NCE, the NRG Board has approved granting you an
additional 30-day period during which you may elect a lump sum.
Sincerely,
Cyndi
<PAGE> 1
EXHIBIT 10.33
THIRD AMENDMENT TO THE
EMPLOYMENT AGREEMENT OF DAVID H. PETERSON
WHEREAS, David H. Peterson (the "Executive") and NRG Energy Inc.
("NRG") have previously entered into an Employment Agreement (the "Agreement")
dated June 28, 1995, amended on June 27, 1999 and further amended on August 26,
1999; and
WHEREAS, the parties wish to further amend the agreement to extend its
term for four (4) additional years, to provide a minimum severance benefit in
the event Executive's employment is terminated in connection with a change in
control, and to preserve certain 1999 retirement benefit calculation assumptions
if specific performance goals are achieved.
RESOLVED, that sections 1, 3(c)(i), and 5(a) of the Agreement are
hereby amended to read as follows:
1. Term. NRG shall employ the Executive, and the Executive shall serve NRG, on
the terms and conditions set forth in this Agreement, for the period (the
"Employment Period") commencing on June 28, 1995 (the "Effective Time") and
ending JUNE 27, 2004.
3. Compensation.
(c) Additional Benefits.
(i) Supplemental Retirement Benefits. During the
Employment Period, the Executive shall participate in a
supplemental executive retirement plan ("SERP") such that the
aggregate value of the retirement benefits that he and his
spouse will receive at the end of the Employment Period under
all defined benefit plans of NRG, NSP and their affiliates
(whether qualified or not) will be not less than the aggregate
value of the benefits he would have received had he continued,
through the end of the Employment Period to participate in the
NSP Deferred Compensation Plan, the NSP Excess Benefit Plan,
and the NSP Pension Plan; provided, that benefits under the
SERP, shall also include the amount, if any, that the NSP
Pension Plan's actuaries reasonably estimate is necessary to
compensate Executive for the monthly defined benefit payments
the Executive did not receive, but would have received during
the term of this Agreement and prior to the date of his actual
termination of employment if monthly benefit payments had
commenced at the end of the month following the month in which
the Executive first became eligible for Early Retirement under
the NSP Pension Plan. In addition, the SERP shall offer the
Executive the option to receive his benefits thereunder in a
single lump sum payment using actuarial assumptions that the
NSP Pension Plan's actuaries determine are reasonable in the
aggregate; provided, that such lump sum payment option shall
be subject to the consent of the Board in its sole discretion
and must be requested by the Executive not less than twelve
months prior to the Executive's termination of employment. IF
THE EXECUTIVE ELECTS A LUMP SUM PAYMENT, THE LUMP SUM SHALL BE
CALCULATED USING THE JOINT
<PAGE> 2
AND SURVIVOR ANNUITY FACTORS IN EFFECT FOR 1999 UNDER THE NSP
PENSION PLAN IF THE FOLLOWING PERFORMANCE GOALS HAVE BEEN
ACHIEVED PRIOR TO PAYMENT OF THE LUMP SUM: EARNINGS PER SHARE
(EPS) GROWTH OF 20 PERCENT PER YEAR (ASSUMING ADEQUATE EQUITY
FUNDING IS PROVIDED) AND NRG RETURN GUIDELINES OF UTILITY (NSP
AUTHORIZED RATE OF RETURN) PLUS 1 1/2 PERCENT LONG-TERM RETURN
ON EQUITY (ROE), ON AVERAGE, FOR NEW INVESTMENTS. IF THE ROE
GOAL IS NOT ACHIEVED, The ADDITIONAL BENEFIT DERIVED FROM THE
USE OF THE 1999 JOINT AND SURVIVOR ANNUITY FACTORS WILL BE
PRORATED PROVIDED THAT THE EPS GOAL IS MET AND AVERAGE ANNUAL
ROE IS AT LEAST 8 PERCENT. FOR EXAMPLE, IF, ON AVERAGE, 20
PERCENT EPS GROWTH AND A ROE OF UTILITY PLUS 1 1/2 PERCENT is
ACHIEVED, THE FULL JOINT AND SURVIVOR BENEFIT WILL BE
PROVIDED. IF AVERAGE ANNUAL ROE IS 8 PERCENT OR LESS, NO
BENEFIT BASED ON THE JOINT AND SURVIVOR ANNUITY FACTORS WILL
BE PROVIDED. Finally, if the Executive dies while employed, or
deemed pursuant to paragraph (a) of section 5 to be employed
by NRG, his surviving spouse (or, if, he has no surviving
spouse, his estate) shall be entitled to receive a benefit
equal in value to the difference between the pension benefit
that the Executive would have received if he had retired
(rather than died ) on the date of his death and received a
lump sum pension benefit and the lump sum value of the pension
payable in the absence of this provision; provided, that in
the case where the Executive has no surviving spouse, the
benefit pursuant to this sentence shall be paid in a lump sum;
and provided, further, that in the case where the Executive
has a surviving spouse, the benefit pursuant to this sentence
shall be paid in the form of a single life annuity for her
life unless she elects a single lump sum payment and the
Board, in its sole discretion, consents to the lump sum
payment. Notwithstanding anything in the preceding sentence to
the contrary, if despite reasonable efforts NRG is unable to
obtain insurance on the life of the Executive with a death
benefit equal to the anticipated after-tax cost to NRG of the
benefit described in the preceding sentence at an average
annual premium cost of less than $7,000, then the value of
such benefit payable to Executive's surviving spouse or estate
shall be reduced so that its after-tax cost to NRG does not
exceed the amount of insurance on the life of the Executive
that NRG could obtain at such cost.
5. Obligations of NRG upon Termination.
(a) By NRG Other Than for Cause or Disability; By the
Executive for Good Reason. If, during the Employment Period, NRG
terminates the Executive's employment, other than for Cause or
Disability, or the Executive terminates employment for Good Reason, NRG
shall continue to provide the Executive with the compensation and
benefits set forth in Section 3 as if he had remained employed by NRG
pursuant to this Agreement through the end of the Employment Period and
then retired (at which time he will be treated as eligible for all
retiree welfare benefits and other benefits provided to retired senior
executives, as set forth in Section 3(b) and (c)); PROVIDED THAT IF THE
TERMINATION IS A RESULT OF A CHANGE OF CONTROL, AS THAT TERM IS DEFINED
IN THE NRG OFFICER EQUITY PLAN, THE COMPENSATION AND BENEFITS SHALL BE
CONTINUED FOR THE LONGER OF THIRTY (30) MONTHS OR THROUGH THE END OF
THE EMPLOYMENT PERIOD; provided, that the Incentive
2
<PAGE> 3
Compensation for such period shall be equal to the greater of the
target Incentive Compensation that the Executive would have been
eligible to earn for such period or the Incentive Compensation awarded
for the last complete incentive plan year ending prior to Executive's
Termination of Employment; provided, further, that in lieu of
stock-based or equity-based awards, the Executive shall be paid cash
equal to the fair market value at the time of grant, if any,
(determined without regard to any restrictions) of the awards that
would otherwise have been granted; and provided, finally, that during
any period when the Executive is eligible to receive benefits of the
type described in paragraph (b) (i) of Section 3 under another
employer-provided plan the benefits provided by NRG under this
paragraph (a) of Section 5 may be made secondary to those provided
under such other plan. The payments and benefits provided pursuant to
this paragraph (a) of Section 5 are intended as liquidated damages for
a termination of the Executive's employment by NRG other than for Cause
or Disability or for the actions of NRG leading to a termination of the
Executive's employment by the Executive for Good Reason, and shall be
the sole and exclusive remedy therefor.
RESOLVED FURTHER, that the Agreement as amended, shall remain in full
force and effect.
/s/ David H. Peterson Date: 20 Oct. 1999
- --------------------------------- -------------------
David H. Peterson
NRG ENERGY, INCORPORATED
By /s/ Cynthia L. Lesher Date: 20 Oct. 1999
------------------------------- -------------------
Its Director
------------------------------
3
<PAGE> 1
EXHIBIT 10.34
DATE: June 11, 1999
TO: NRG POWER MARKETING INC.
ATTENTION:
FAX NO:
FROM: NIAGARA MOHAWK POWER CORPORATION
RE: SWAP TRANSACTION
- --------------------------------------------------------------------------------
Dear Ladies and Gentlemen:
The purpose of this letter agreement (this "Confirmation") is to
confirm the terms and conditions of the Transaction entered into between us on
the Trade Date specified below (the "Transaction").
This Confirmation constitutes a "Confirmation" as referred to herein,
and supplements, forms a part of and is subject to, the ISDA Master Agreement,
dated as of June 11, 1999 as amended and supplemented from time to time (the
"Agreement"), between NRG Power Marketing Inc. ("PRODUCER") and Niagara Mohawk
Power Corporation ("NIAGARA MOHAWK"). All provisions contained in the Agreement
govern this Confirmation except as expressly modified below.
The terms of the Transaction to which this Confirmation relates are as
follows:
THE OBLIGATIONS INCURRED PURSUANT TO THIS TRANSACTION SHALL REQUIRE CASH
PAYMENTS AND SHALL IN NO EVENT BE INTERPRETED TO REQUIRE THE PURCHASE OR SALE OF
ELECTRICITY.
1. General Terms:
Trade Date: June 11, 1999
Effective Date: The later of (i) the Closing Date, as such term is
defined in the Asset Sales agreement between Niagara
Mohawk and NRG Energy, Inc., or (ii) first day of the
month following the month in which the later of (i)
the NYISO goes into operation, or (ii) Niagara
Mohawk's senior notes of the series having the
longest maturity then outstanding have been rated
investment grade by (a) S&P and Moody's or (b) S&P or
Moody's and at least one other rating
-1-
<PAGE> 2
agency.
Termination Date: The fourth anniversary of the Closing Date.
Business Day: Any day other than Saturday, Sunday and any day
which is a legal holiday or a day on which banking
institutions in New York City are authorized by law
or other governmental action to close; and a
Business Day shall open at 8:00 a.m. and close at
5:00 p.m. Eastern Standard (or Daylight) time.
Calculation Agent: NIAGARA MOHAWK.
2. Payments:
Settlement Dates: The last day of each calendar month during the Term
of this Transaction.
Settlement Periods: With respect to each Settlement Date means the
period from (but excluding) the immediately
preceding Settlement Date (or, in the case of the
first Settlement Date, from and including the
Effective Date) to (and including) such Settlement
Date (or, in the case of the last Settlement Date,
to and including the Termination Date).
Payment Dates: With respect to each Settlement Date or Settlement
Period means the 25th day of the calendar month
immediately after such Settlement Date or Settlement
Period, as the case may be, subject to adjustment in
accordance with the Following Business Day
Convention.
Payment Calculations: Not less than 5 Business Days prior to each
Payment Date, the Calculation Agent shall calculate
the amounts payable by each party on such Payment
Date and shall notify the other party thereof
(including reasonable detail with respect to such
calculation).
-2-
<PAGE> 3
Payment Amounts: On each Payment Date: (i) NIAGARA MOHAWK shall pay
to PRODUCER one-twelfth of the Call Fee - Stage 1 for
the preceding Settlement Period, and (ii) PRODUCER
shall pay to NIAGARA MOHAWK an amount equal to the
sum of (A) the aggregate Capacity Payment for each
Interval during such Settlement Period and (B) the
Ancillary Services Payment for such Settlement
Period.
In addition to the foregoing, if NIAGARA MOHAWK has
exercised the Call Option with respect to any
Interval during a Settlement Period, then on the
Payment Date immediately after such Settlement Period
(i) NIAGARA MOHAWK shall pay to PRODUCER the sum of
(A) the aggregate Call Fee-Stage 2 for each such
Interval, and (B) the aggregate NIAGARA MOHAWK Call
Amount for each such Interval, and (ii) PRODUCER
shall pay to NIAGARA MOHAWK the aggregate PRODUCER
Call Amount for each such Interval.
3. Call Option Exercise:
Call Option: With respect to each Interval, NIAGARA MOHAWK shall
have the right, but not the obligation, to specify a
quantity of electricity (the "Call Quantity") as to
which the PRODUCER Call Amount and the NIAGARA Call
Amount will be calculated and will become due in
accordance with this Transaction. Notwithstanding
the foregoing, PRODUCER shall retain the right to
refuse the portion of a Call Quantity for a Unit if
the Unit is unexpectedly forced off-line or derated
sufficiently to be unable to fulfill the portion of
the Call Quantity. Any such refusal with respect to
a Call Quantity, for each Settlement Period, shall
be limited to the Decline Quantity Cap. In the
event the Decline Quantity Cap is reached, the
Interval Call Quantity schedule shall immediately
become effective in full force, PRODUCER shall
immediately notify NIAGARA MOHAWK of any such
refusal, the reason for such refusal and the Call
Quantity refused. In the event of refusal due to
-3-
<PAGE> 4
unavailability NIAGARA Mohawk shall not be required
to take the Minimum Capacity quantity. At the request
of NIAGARA MOHAWK, PRODUCER shall provide evidence of
such Unit unavailability or derate. Any exercise
which is refused in accordance herewith shall be
deemed not to have been exercised to the extent of
the Call Quantity so refused.
Call Quantities shall be subject to the following
limitations: (i) no individual Unit Call Quantity
nomination schedule can change by more than its
response rate (set forth in Schedule A hereto); (ii)
Minimum Capacity and Minimum Down Time Times (set
forth in Schedule A hereto), must be adhered to in
the nomination for Call Quantities (e.g. to adhere to
the Minimum Down Time, if a Call Quantity is
scheduled to zero, the Call Quantity cannot exceed
zero again until the Minimum Down Time is met, (iii)
the Call Quantity for an Interval is limited to the
Maximum Capacity set forth in Schedule A hereto, (iv)
the aggregate calendar year Call Quantity limit
cannot exceed the amount set forth in Schedule B.
Call Option
Exercise Procedure:
Schedule D shall be deemed to be the Call Quantity.
For Settlement Periods beyond September 2001, NIAGARA
MOHAWK shall have the right to amend Schedule D for
each Capability Period with a written notice one
month prior to each Capability Period. Such Schedule
D amendment shall not change the aggregate Call
Quantity for (i) any Capability Period (ii) any
calendar year.
For any Call Quantity refused by producer NIAGARA
MOHAWK shall have the right to make up such
quantities by the following procedure. NIAGARA MOHAWK
may exercise the Call Option with respect to any
Interval by delivery of an exercise notice to
PRODUCER (which may be delivered orally, including by
telephone). Any such notice shall specify the
relevant Interval and Call Quantity (in MWh), and
shall be given prior to 5:00 PM (New York time) on
the Friday preceding the
-4-
<PAGE> 5
week in which such Interval occurs. A week shall
consist of the period commencing with the hour ending
at 0100 on Monday, New York time and ending with the
hour ending at 2400 on Sunday, New York time.
If any notice is delivered orally, NIAGARA MOHAWK
will execute and deliver a written confirmation
confirming the substance of that notice within two
Business Days of that notice. Failure to provide
that written confirmation will not affect the
validity of that oral notice.
4. Definitions:
"Ancillary Services Payment": For each Settlement Period means an
amount equal to a Portion (as defined below) of the payments which NIAGARA
MOHAWK makes to the NYISO during such Settlement Period for Ancillary services
(including, specifically, reactive supply and voltage support, regulation and
frequency response, and operating reserves). The Portion of such payments for
each Settlement Period shall be equal to the product of (X) the ratio of the
Call Quantity during such Settlement Period divided by the public sales of
NIAGARA MOHAWK times (Y) the payments which NIAGARA MOHAWK makes to the NYISO
for such ancillary services.
"Call Amount": Shall have the meaning defined in PRODUCER Call Amount
and NIAGARA Call Amount.
"Call Fee - Stage 1": For each Settlement Period means an amount for
the applicable Unit and Settlement Period determined by the Calculation Agent
based on Schedule C hereto.
"Call Fee - Stage 2": For each Interval during which the Call Option is
exercised, an amount for the applicable Unit and Interval determined by the
Calculation Agent based on Schedule C hereto; provided that (i) a warm start
Call Fee - Stage 2 shall apply, and a cold start Call Fee shall not apply, with
respect to an Interval if the Call Option has been exercised and the Call
Quantity was zero for the preceding Intervals but was greater than zero for any
Interval during the preceding 10 Intervals, and (ii) a cold start Call Fee -
Stage 2 shall apply, and warm start Call Fee - Stage 2 shall not apply, if the
Call Option has been exercised and the Call Quantity was zero for the
preceding 10 Intervals. Notwithstanding the above, a Call Fee - Stage 2 shall
not apply if the Call Option was exercised in the preceding interval.
"Call Quantity": Shall have the meaning described in Article 3 on page
3.
-5-
<PAGE> 6
"Capability Period": Shall mean each of two six-month intervals whereby
the winter capability period includes the calendar months of November through
April and the summer capability period includes the calendar months of May
through October.
"Capacity": For each Interval means the amount of capacity set forth in
Schedule A hereto under the column entitled Max Capacity.
"Capacity Payment": For each Interval means the Market Capacity Price
in $/MW multiplied by the Capacity for such Interval.
"Decline Quantity Cap": For each Settlement Period, the PRODUCER's
right to decline the Call Quantity due to unexpected forced outage or derate
shall be limited on a previous six-Scheduled Quantity Month basis. The Decline
Quantity Cap is defined as the Maximum Capacity set forth in Schedule A times
the Intervals that make up the previous six Scheduled Quantity Months (adjusted
for leap year) times the Equivalent Forced Outage Rate ("EFOR") set forth in
Schedule A. The declined quantity shall be calculated on a rolling Interval
basis during the previous six-Scheduled Quantity Months (for example, hour
ending 1400 on February 15, last year through hour ending 1300 February 15, this
year including all of the Scheduled Quantity Months). Furthermore, it is
understood that on the Closing Date, it shall be deemed that the previous
six-Scheduled Quantity Months have an EFOR as listed in Schedule A.
"Interval": one hour.
"Market Capacity Price": Shall equal zero at any time when (i) no
separate market for capacity exists, or (ii) capacity obligations for load
serving entities cease to exist in the NYISO Tariff. Commencing on the first
day of the month following the calendar month in which the NYISO is initially
established and operating and only if there then exists a separate market for
capacity, the Market Capacity Price shall mean the price paid to producers or
by load serving entities for capacity at the respective generator plant bus-
bar location, established by the most recent NYISO capacity auction.
N
E [P(i) * V(i))/H(i)]
|-|
$/MWh(1) = ___________
_________________________
(1) As an example, consider three tranches: (1) 2,100 MW at $1,000/MW
per month, (2) 2,000 MW at $2,700/MW per 3-month, (3) 6,000 MW at $6,600/MW per
6-month. The resultant price is equal to the following:
$/MWh = { ($1,000/MW*2,100 MW)/720 hr =$1.43/MWh
+ ($2,700/MW*2,000 MW)/2,160 hr
+ ($6,600/MW*6,000 MW)/4,380 hr}
_________________________
-6-
<PAGE> 7
N
E [V(i)]
|-|
where:
"N" is the number of individual Capacity Tranches sold at auction;
"P(i)", is the sales price (in S/MW) of the ith Capacity Tranche sold
at auction;
"H(i)", is the capacity entitlement (in hours) corresponding to the
ith Capacity Tranche sold at auction;
"V(i)", is volume of Capacity (in MW) in the Capacity Tranche sold at
auction; and
"Capacity Tranche" means an individual block of auction dates and hours
of capacity entitlement.
Prior to the establishment of the Market Capacity Price, and if
capacity obligations for load serving entities exist in the NYISO Tariff then
NIAGARA MOHAWK shall retain the right to claim the Capacity, and PRODUCER must
provide such Capacity, for NIAGARA MOHAWK's capacity requirements to the NYISO.
In the event the PRODUCER is unable to provide Capacity acceptable to the NYISO
in the amount claimed by NIAGARA MOHAWK from its own sources, the PRODUCER must
procure the CAPACITY from the market and provide it to NIAGARA MOHAWK at no cost
to NIAGARA MOHAWK. In the event the PRODUCER fails to provide such Capacity,
PRODUCER shall be charged a penalty equivalent to the greater of (i) the penalty
rate assessed by the NYISO, or (ii) the capacity rate component of NIAGARA
MOHAWK's Service Classification Number 6 Tariff.
"Market Price": Means for any Interval commencing on the first day of
the month following the calendar month in which the NYISO Establishment Date
occurs, the day ahead locational based market price ("LBMP") paid to producers
for energy, at the Unit's bus bar or the region in which the Unit's bus bar is
located, specified and published by the NYISO.
"NIAGARA MOHAWK Call Amount": For each Interval during which the Call
Option is exercised, an amount equal to the product of the Call Quantity for
such Interval multiplied by the Fixed Price ("P") for such Interval set forth in
Schedule C hereto.
"NYISO" is the New York Independent System Operator which operates the
bulk power electric system pursuant to the FERC approved tariff which was filed
by the
- --------------------------------------------------------------------------------
(2,100 MW + 2,000 MW + 6,000 MW)
-7-
<PAGE> 8
members of the New York Power Pool on December 19, 1998.
"PRODUCER Call Amount": For any Interval during which the Call Option
is exercised, an amount equal to the product of the Call Quantity for such
Interval multiplied by the Market Price for such Interval.
"PSC": Shall mean the New York Public Service Commission.
"Scheduled Quantity Month": Shall mean any calendar month in which a
Call Quantity is pre-scheduled pursuant to Schedule D; specifically the calendar
months of June, July, August, December, January, February, and the month of
March during the year 1999, and 2000 for Huntley, but excluding the month of
December during the year 2002 for Dunkirk.
"Unit": Shall be PRODUCER's electric generating units as shown in
Schedule A.
5. Further Assurances
Subject to the terms and conditions contained herein, upon the request
from time to time of either party hereto, the other party shall promptly execute
and deliver or use its reasonable best efforts to cause to be executed and
delivered, such consents, approvals and other instruments, including, without
limitation, assignments of this Transaction as collateral, estoppel certificates
and utility certificates, in form and substance reasonably satisfactory to both
parties and their respective counsel to implement any financing or other
material business transaction undertaken by the requesting party.
6. Account Details:
Account Details of NIAGARA MOHAWK:
Bank name: Citibank
Address: 399 Park Avenue
New York, New York 10022
ABA #:
Account name: Niagara Mohawk Power Corporation
Account #:
Account Details of PRODUCER:
Bank name: LaSalle National Bank
Address: Chicago, IL
ABA #:
Account name: NNRG Power Marketing Inc.
Account #:
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<PAGE> 9
Please confirm that the foregoing correctly sets forth the terms of our
agreement by executing the copy of this Confirmation enclosed for that purpose
and returning it to us or by sending to us.
Yours sincerely,
NIAGARA MOHAWK POWER CORPORATION
By: Clement Nadeau
---------------------------------------
Name: CLEMENT NADEAU
Title: Vice President
Confirmed as of the
date first above written:
NRG POWER MARKETING INC.
By: James J. Bender
---------------------------
Name: James J. Bender
Title: Vice President
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<PAGE> 1
EXHIBIT 10.35
STANDARD OFFER SERVICE
WHOLESALE SALES AGREEMENT
THIS STANDARD OFFER SERVICE WHOLESALE SALES AGREEMENT ("Agreement")
dated as of October 29, 1999, is by and between THE CONNECTICUT LIGHT AND POWER
COMPANY ("CL&P" or "Buyer") and NRG POWER MARKETING INC. ("Seller"). The Seller
and Buyer together are the Parties and each individually is a Party to this
Agreement.
WITNESSETH:
WHEREAS, pursuant to Section 20(b) of Public Act 98-28, An Act
Concerning Electric Restructuring ("Act"), the Buyer must procure generation for
the purpose of providing Standard Offer Service to those end use consumers of
electricity within its traditional retail service area ("Retail Customers") that
do not or are unable to choose an Electric Supplier (as defined in Section 1(30)
of the Act);
WHEREAS, by Order dated July 7, 1999, in Docket No. 99-03-36, the
Connecticut Department of Public Utility Control ("DPUC") approved, with certain
modifications, the Buyer's proposal to issue a competitive bid solicitation, or
Request For Proposals, for generation service to supply fifty percent of the
Buyer's Standard Offer Service Load ("the RFP");
WHEREAS, the DPUC has retained J.P. Morgan Securities, Inc. ("J.P.
Morgan") to act as the exclusive agent to the DPUC to conduct the RFP;
WHEREAS, J.P. Morgan carefully evaluated the responses to the RFP,
including the response submitted by the Seller, and advised that the Seller is a
qualified bidder pursuant to the RFP, and that the Seller's offer to supply a
portion of the Standard Offer Service Load meets the standards for selection in
the RFP, subject to negotiating an acceptable agreement to supply Standard Offer
Service;
WHEREAS, this Agreement sets forth the rates, terms and conditions
under which the Seller will supply firm all-requirements service as necessary to
serve a specified share of the Buyer's aggregate retail load that takes Standard
Offer Service during the term of this Agreement;
NOW, THEREFORE, in consideration of the premises and of the mutual
agreements herein contained, the Parties to this Agreement covenant and agree as
follows:
1. DEFINITIONS
<PAGE> 2
As used throughout this Agreement, the following terms shall have the
definitions set forth in this Article 1.
1.1 "BACK-UP SERVICE" means generation services provided to any
Retail Customer that has entered into a service contract with
an alternative supplier who, in turn, fails to provide
generation services to such Retail Customer other than due to
the Retail Customer's failure to pay for such services.
1.2 "CONTRACT LOAD QUANTITY" means the portion of the Standard
Offer Service Load, defined as a monthly total, for which the
Seller is obligated to supply SOS Requirements Power pursuant
to Section 3.5 of this Agreement. The Contract Load Quantity
shall be calculated in accordance with Appendix A.
1.3 "DELIVERY POINT" means any point on the NEPOOL PTF, or one or
more other points of interconnection between the Buyer's
transmission or distribution system and generating assets
owned or contracted for by the Seller, where Seller delivers
SOS Requirements Power to the Buyer, and at which point title
to and liability for electricity passes from the Seller to the
Buyer; provided, however, that the Seller shall assume all of
the risk that it will not obtain NEPOOL credit for power that
is not delivered to the NEPOOL PTF; and provided further that,
from the standpoint of the rights and benefits received by the
Buyer under this Agreement, all power delivered hereunder
shall be treated in the same manner as if the power had been
delivered to the NEPOOL PTF.
1.4 "DELIVERY SERVICES" means the combination of Regional Network
Service ("RNS") over NEPOOL PTF acquired pursuant to the
NEPOOL Transmission Tariff, Local Network Service ("LNS") over
the Buyer's Non-Pool Transmission Facilities pursuant to the
NU Operating Companies open access transmission tariff, and
firm distribution services under the Buyer's distribution
service tariff that are provided by the Buyer for the delivery
of SOS Requirements Power for the Contract Load Quantity.
Delivery Services shall not include losses, congestion
charges, ancillary services or any ISO charges associated with
SOS Requirements Power, all of which shall be the
responsibility of the Seller.
1.5 "ISO" means ISO New England, Inc., the Independent System
Operator for the NEPOOL Control Area, or any successor
thereto.
1.6 "MATERIAL ADVERSE EFFECT" as used in Sections 10.1 and 10.2
means any change in, or effect on the Buyer or Seller after
the date of this Agreement and prior to the Effective Date
that is materially adverse to any of the transactions
contemplated hereby, other than (i) any change or effect
resulting from changes in the international, national,
regional or local wholesale or retail markets for electric
power; (ii) any change or effect
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<PAGE> 3
resulting from changes in the international, national,
regional or local wholesale or retail markets for any fuel
used by the Seller; (iii) any change or effect resulting from
changes in the North American, national, regional or local
electric transmission systems; (iv) any change or effect
resulting from any action or inaction by a legislative or
regulatory authority, other than failure of any state or
federal governmental authority or commission to give any
consent or approval.
1.7 "NEPOOL" means the New England Power Pool, the power pool
created by and operated pursuant to the provisions of the
Restated NEPOOL Agreement, as such agreement may be amended
from time to time.
1.8 "NEPOOL CONTROL AREA" means the geographic area in which the
ISO is responsible for maintaining transmission lines within
established security limits and for balancing the sum of
internal generation and net interchange with the control area
load at all times in order to maintain system stability,
reliability and frequency within acceptable limits.
1.9 "NEPOOL PTF" means the facilities categorized as Pool
Transmission Facilities as defined in the Restated NEPOOL
Agreement.
1.10 "SOS REQUIREMENTS POWER" means the firm wholesale power that
Seller is obligated to deliver as defined in Section 3.1.
1.11 "SOS SUPPLIER BILLING AMOUNT" means the monthly billing
quantity as determined in accordance with Appendix A.
1.12 "STANDARD OFFER SERVICE" OR "SOS" means the electric service
provided in accordance with Section 20(b) of the Act and the
implementing rules and regulations of the DPUC to those Retail
Customers of the Buyer that do not purchase electricity from
an Electric Supplier.
1.13 "STANDARD OFFER SERVICE LOAD" means the aggregate consumption
of all of CL&P's Standard Offer Service customers plus the
aggregate electric losses for delivery from a Delivery Point
to the end-use meters of all such customers as determined in
accordance with Appendix A.
1.14 "TERM" means the period during which the Seller is obligated
to supply SOS Requirements Power pursuant to this Agreement.
The Term shall be for four (4) calendar years commencing at
the hour ending 0100 on January 1, 2000, and terminating at
the hour ending at 2400 on December 31, 2003, unless this
Agreement is terminated earlier pursuant to its terms.
1.15 "TRANSITION AGREEMENT" means the Agreement for Transition
Power Supply between and among The Connecticut Light And Power
Company, NRG Energy, Inc., NRG Power Marketing Inc., Montville
Power LLC,
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<PAGE> 4
Middletown Power LLC, Devon Power LLC, Norwalk Power LLC, and
Connecticut Jet Power LLC, pursuant to which the parties to
such agreement have arranged for the Buyer to acquire rights
to power between the date of closing of the sale of certain of
the Seller's generating assets to NRG Energy, Inc. and the
commencement of SOS, or for the Seller to acquire rights to
power from the date of commencement of SOS to the date of
closing of the sale of such CL&P generating assets to NRG
Energy, Inc.
2. EFFECTIVE DATE AND FILING
2.1 This Agreement shall be binding on the Parties as of the date
it is executed by both Parties ("Effective Date"); provided
that the provision of SOS Requirements Power by the Seller
shall be subject to obtaining necessary regulatory
authorizations for providing such service. Promptly after
execution hereof, the Seller shall file this Agreement with
the Federal Energy Regulatory Commission ("FERC") and shall
request that the FERC accept this Agreement for filing without
modification or condition, with service hereunder to be
effective commencing on January 1, 2000. The Buyer shall
support such filing. In addition, the Buyer shall, promptly
after execution hereof, submit this Agreement to the DPUC for
its approval as set forth in the RFP. The Seller shall bear
the cost of the FERC filing described above except for the
costs associated with the Buyer's intervention. The Buyer
shall bear the cost of the DPUC filing described above except
for the cost of the Seller's intervention. In each case, the
Party responsible for filing this Agreement shall request that
the regulatory agency give confidential treatment to the
pricing terms of this Agreement, which are the result of a
competitive solicitation held by the Buyer.
2.2 In the event that the FERC or the DPUC grants conditional
approval of this Agreement, compliance with which would create
a material adverse economic impact on a Party, the adversely
affected Party may seek to negotiate such changes to this
Agreement as may be necessary to restore the balance of
consideration hereunder while simultaneously complying with
the FERC and DPUC orders. If the Parties are unable to
negotiate such changes that are satisfactory to each Party
within five (5) business days after the FERC or DPUC order,
either Party shall have the right to terminate this Agreement
by giving five (5) days written notice to the other Party, in
which event the Agreement shall be null and void and of no
further force and effect from and after the date of
termination. In the event that the FERC or the DPUC does not
accept the changes negotiated by the Parties hereunder, either
Party shall have the right to terminate this Agreement upon
thirty (30) days' written notice to the other Party, in which
event the Agreement shall be null and void and of no further
force and effect from and after the date of termination.
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<PAGE> 5
2.3 The applicable provisions of this Agreement shall continue in
effect after expiration of the Term (or earlier termination as
provided herein) to the extent necessary to provide for final
accounting, final billing, billing adjustments, resolution of
any billing dispute, resolution of any court or administrative
proceeding and final payments.
3. SALE AND PURCHASE OF SOS REQUIREMENTS POWER
3.1 SOS Requirements Power is the wholesale power delivered at the
Delivery Point(s) that is supplied at all times and in
quantities reflecting the full requirements for power of
Retail Customers purchasing Standard Offer Service from CL&P.
SOS Requirements Power shall be firm and shall vary in
quantity from minute to minute, hour to hour, day to day and
month to month based on the consumption patterns of Retail
Customers. SOS Requirements Power includes power supply and
ancillary services, in such amounts as are required for the
Buyer to serve the Contract Load Quantity plus losses at all
times throughout the Term. SOS Requirements Power includes all
of the power supply and ancillary services that are or may be
necessary to serve electrical load under the Restated NEPOOL
Agreement during the Term, including Energy, Installed
Capability, Operable Capability, Operating Reserves, Automatic
Generation Control, electrical losses, congestion charges
imposed under the NEPOOL Transmission Tariff, charges of the
ISO associated with NEPOOL membership and with serving the
Contract Load Quantity, and any future additions, deletions or
changes to the seven NEPOOL products (Energy, Installed
Capability, Operable Capability, 30-minute Non-Spinning
Operating Reserves, 10-Minute Spinning Reserves, 10-Minute
Non-Spinning Reserves, and Automatic Generation Control) that
are required for entities serving electrical load in NEPOOL.
SOS Requirements Power shall also include such transmission
and distribution delivery services as may be required for the
Seller to deliver SOS Requirements Power to the Delivery
Point(s). SOS Requirements Power shall not include any current
or future requirement to meet a renewable energy portfolio
standard in the State of Connecticut.
3.2 The Seller shall deliver and sell to Buyer at a Delivery Point
the Contract Load Quantity. The billing determinants on which
payment to Seller is based shall be determined in accordance
with Appendix A.
3.3 The Buyer shall receive and purchase power delivered by Seller
in accordance with this Section 3.
3.4 The Seller shall own or procure sufficient firm power supplies
and ancillary services to provide SOS Requirements Power
throughout the Term, and shall schedule all such power
supplies and ancillary services with the ISO
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<PAGE> 6
for use by the Buyer in accordance with the provisions of the
Restated NEPOOL Agreement (including future amendments
thereto) and the applicable operating procedures of the ISO.
The Seller shall be responsible for all transmission and
distribution delivery costs, if any, required to deliver SOS
Requirements Power to the Delivery Point(s).
3.5 The Contract Load Quantity shall be equal to thirty-five (35)
percent of the Standard Offer Service Load during calendar
year 2000, forty (40) percent of the Standard Offer Service
Load during calendar years 2001 and 2002, and forty-five (45)
percent of the Standard Offer Service Load during calendar
year 2003.
3.6 The Buyer shall procure or arrange for Delivery Services in
order to accomplish the firm delivery of SOS Requirements
Power from the Delivery Point(s) to the Retail Customers
taking SOS Requirements Power throughout the Term; provided
that the Buyer's obligation to supply Delivery Services at and
from the Delivery Point(s) with respect to any particular
generating resource of the Seller shall be subject to the
availability of transmission service for such delivery under
the NEPOOL Transmission Tariff.
3.7 For the entire Term, the Seller shall either (1) be a member
of NEPOOL with its own load and settlement account established
in accordance with the rules of the ISO, or (2) contract with
a NEPOOL member for such member to include the Seller's load
in its own load and settlement account.
3.8 The Seller and Buyer shall comply with the procedures, rules
and regulations of the ISO and NEPOOL and the requirements of
the Restated NEPOOL Agreement as they may apply to the
purchase, sale and delivery of SOS Requirements Power.
3.9 The Seller shall be responsible for forecasting the Contract
Load Quantity for purposes of meeting its supply obligation
hereunder on a monthly, daily and hourly basis, for the full
Term of the Agreement. The Buyer's most recent forecasts of
energy sales and peak demand for its service area are set
forth in Appendix B for informational purposes. The Buyer will
supply the Seller with (1) any updates or material changes to
such forecasts made during the Term, (2) on a weekly basis,
the actual number of customers on Standard Offer Service
broken down by customer segment to the extent known, for the
previous week, and (3) within 37 hours after the close of the
day, the same supplier hourly loads the Buyer submitted to the
ISO on behalf of the Seller.
3.10 The Seller shall be responsible for and shall pay all ISO and
NEPOOL charges and expenses associated with the provision of
SOS Requirements Power, except for any such ISO or NEPOOL
charges that
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<PAGE> 7
are imposed directly on the Buyer in connection with the
provision of Delivery Services by the Buyer.
3.11 The Seller shall be responsible for and shall pay all taxes,
fees, and levies that may be assessed by any entity in
connection with the provision of SOS Requirements Power except
for (1) such taxes, fees and levies that Buyer is allowed to
collect directly from the Retail Customers, and (2) such
taxes, fees and levies that are assessed directly to the Buyer
in connection with the provision of Delivery Services.
3.12 If and to the extent that, at any time during the Term, the
congestion management scheme in effect under the NEPOOL
Transmission Tariff provides for the automatic assignment of
rights to rebates of transmission congestion charges to retail
loads of the Buyer, the Seller shall be entitled to a portion
of such congestion rebate rights based on the ratio between
the Contract Load Quantity and the Buyer's retail load that is
subject to the automatic assignment of such rights.
4. CHARGE PROVISIONS
4.1 For and in consideration of the sale by the Seller to the
Buyer of SOS Requirements Power, the Buyer shall pay the per
unit charges set forth in the Table below for all SOS
Requirements Power supplied to Retail Customers during the
Term of this Agreement. The monthly quantity of SOS
Requirements Power to which the unit charges set forth herein
shall be applied for billing purposes, shall be the SOS
Supplier Billing Amount:
NRG POWER MARKETING
Table of Load Percentages and Charges
<TABLE>
<CAPTION>
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
5% LOAD 2000 2001 2002 2003
SHARE* (CENTS PER KWH) (CENTS PER KWH) (CENTS PER KWH) (CENTS PER KWH)
<S> <C> <C> <C> <C>
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
1ST
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
2ND
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
3RD
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
4TH
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
</TABLE>
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<PAGE> 8
<TABLE>
<S> <C> <C> <C> <C>
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
5TH
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
6TH
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
7TH
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
8TH -
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
9TH - - -
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
10TH - - - -
- ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
</TABLE>
4.2 The charges set forth in Section 4.1 are the result of a
competitive bid solicitation and shall apply for the entire
Term unless both Parties agree to a change in charges set
forth in a written amendment to the Agreement that is accepted
for filing by the FERC. Nothing in this Section 4.2 is
intended to modify Sections 2.2, 4.5, or 9.3 of this
Agreement.
4.3 It is the intent of the Parties that, except as provided in
Sections 4.5 and 9.3, or as the Parties otherwise agree,
neither the Seller and its affiliates nor the Buyer and its
affiliates shall have the unilateral right to make a filing
with the FERC under any Section of the Federal Power Act, or
with the DPUC, seeking to change the charges or any other
terms or conditions set forth in this Agreement for any
reason.
4.4 Neither Party shall instigate or cooperate with any effort of
third parties to petition the FERC or the DPUC to change any
term of the Agreement (which includes the charges and
quantities). If any third party nevertheless petitions the
FERC or the DPUC to establish a proceeding under Section 206
of the Federal Power Act, both Parties shall cooperate to seek
to dismiss such proceeding and to uphold the Agreement without
change. It is the intention of the Parties that any authority
of the FERC or the DPUC to change the Agreement be strictly
limited to that which applies when the contracting parties
have irrevocably waived their right to seek to have the FERC
or the DPUC change any term of this Agreement.
4.5 In the event that the DPUC modifies the rules relating to the
provision of Standard Offer Service during the Term, or
Connecticut enacts legislation that has the affect of
modifying the provisions of the Act relating to Standard Offer
Service, and such DPUC or legislative modifications would
materially adversely affect the rights and responsibilities of
either Party under this Agreement, the Party that believes it
would be materially adversely affected by such modifications
may request that the DPUC take action to protect the interests
of such Party. If the DPUC does not provide relief
satisfactory to such Party within sixty (60) days from the
date of filing of the request, the Parties shall enter into
good faith negotiations to amend this Agreement in a manner
designed to restore the original
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<PAGE> 9
balance of consideration set forth herein. In the event that
the Parties are unable to reach agreement on such revisions to
this Agreement: (1) the Seller, if it is the adversely
affected Party, shall have the right unilaterally to make a
filing with the FERC pursuant to Section 205 of the Federal
Power Act and the FERC's rules and regulations thereunder, and
(2) the Buyer, if it is the adversely affected Party, shall
have the right to make a filing under Section 206 of the
Federal Power Act, seeking such changes to this Agreement,
including termination hereof, as such Party deems necessary
due solely to the DPUC's change or the new legislation. In the
case of any such filing, the other Party shall have the right
to intervene in opposition to the filing.
4.6 Upon request of the Buyer, the Seller shall, within three (3)
business days, submit a firm price quote for no less than a
pro rata share of the Buyer's Back-Up Service requirements,
with such pro rata share based on the ratio of the Contract
Load Quantity to the Buyer's Standard Offer Service Load, and
which quote shall be binding on the Seller for a period of no
less than a calendar month. If the Buyer accepts the Seller's
price quote during such calendar month period for any portion
of the amount of Back-Up Service covered by the quote, the
Seller shall supply additional SOS Requirements Power in
accordance with its price quote and the remaining terms and
conditions of this Agreement.
5. BILLING AND PAYMENT
5.1 As soon as practicable after the end of each month during the
Term, the Buyer shall supply the Seller its estimate of the
SOS Supplier Billing Amount for purposes of billing hereunder.
Within ten (10) days thereafter, the Seller shall submit a
bill to the Buyer for all applicable charges hereunder based
on such estimates.
5.2 Each bill rendered under this Agreement shall be subject to
adjustment in order to true-up charges based on estimated SOS
Supplier Billing Amount data to the adjusted SOS Supplier
Billing Amount, as defined in Appendix A. Promptly after the
adjustment to SOS Supplier Billing Amount has been determined,
the Buyer shall supply the adjusted SOS Supplier Billing
Amount to the Seller in order to enable the Seller to
calculate the final bill for SOS Requirements Power for each
month during the Term. The Seller shall prepare and send to
the Buyer an adjusted bill within ten (10) days after
receiving the adjusted SOS Supplier Billing Amount data from
the Buyer. All refunds or surcharges owed to either Party as a
result of differences between the estimated and adjusted SOS
Supplier Billing Amounts shall include the payment of interest
calculated in accordance with the regulations of the FERC
applicable to the payment of interest on
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<PAGE> 10
refunds for the entire period between payment under the
original estimated bill and the final bill.
5.3 All bills, including any adjusted bills, shall bear the date
of rendering and be due and payable not later than thirty (30)
days after the date of rendering. Any amount remaining unpaid
after such thirty (30) days shall bear interest at the rate
set forth in the regulations of the FERC for interest payments
on refunds, from the due date to the date of payment by the
Buyer. All payments sent by the Buyer to the Seller shall be
by wire transfer or by certified check delivered using
overnight mail.
5.4 If the Buyer disputes the amount of any bill, it shall so
notify the Seller in writing. The Buyer shall pay to the
Seller any undisputed amount of the bill when due. The
disputed amount may, at the discretion of the Buyer, be held
by the Buyer until the dispute has been resolved; provided
that the Buyer shall be responsible to pay interest on any
withheld amounts that are determined to have been properly
billed, which shall be calculated in the same manner as
interest on late payments under Section 5.3. Neither Party
shall have the right to challenge any monthly bill or to bring
any court or administrative action of any kind questioning the
propriety of any bill after a period of twenty four (24)
months from the date the bill was due; provided, however, that
in the case of a bill based on estimates, such twenty-four
month period shall run from the due date of the final adjusted
bill.
5.5 In the event that the Buyer fails to pay the amount due by the
due date, the Seller may notify the Buyer that, unless payment
is received, it will be in default of its obligations under
this Agreement. The Buyer shall have thirty (30) days from the
date of receipt of such notification from the Seller to cure
its default. In the event that the default is not cured within
such 30 day period, the Seller, in addition to any other legal
or equitable remedies it may have, shall have the right to
terminate this Agreement upon five (5) days written notice to
the Buyer.
6. BILLING DETERMINANTS/SUPPLY OBLIGATION
6.1 The Buyer shall maintain meters capable of measuring the
energy use of Retail Customers taking SOS in accordance with
rules prescribed by the DPUC. The accuracy of all metering
equipment will be in accordance with the Buyer's normal
practices and DPUC requirements applicable to the Buyer's
retail distribution loads. The Seller hereby acknowledges and
accepts that Buyer does not maintain meters capable of
interval measurement for some of its retail load that will be
served under the SOS. The price, risk and other terms of this
Agreement have been negotiated based upon these conditions and
Buyer shall not be obligated to install
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<PAGE> 11
interval metering equipment as a result of this Agreement. The
Parties agree that the obligation of the Buyer to pay for
power delivered and the obligation of the Seller to deliver a
specified quantity at an authorized Delivery Point shall be
determined in accordance with Appendix A.
7. LIABILITY FOR DELIVERY AND FORCE MAJEURE
7.1 The Seller shall be responsible for scheduling with or
purchasing from NEPOOL a sufficient amount of SOS Requirements
Power to satisfy its service obligations hereunder at all
times during the Term. To the extent that the Seller does not
own or has not acquired sufficient resources to satisfy this
obligation at any time during the Term, the Seller shall
purchase any deficiency from NEPOOL. Under no circumstances
shall the Buyer be responsible for acquiring power or
ancillary services to meet any portion of the Seller's SOS
Requirements Power supply obligation hereunder at any time
during the Term.
7.2 In the event that the Seller defaults on its material
obligations to the Buyer or NEPOOL in connection with this
Agreement at any time during the Term, and the Seller does not
cure such default within a time period allowed by NEPOOL and
ISO-NE (but not to exceed ten (10) days if there is no
explicit NEPOOL or ISO-NE period for curing the default), the
Buyer shall have the option to terminate or suspend all or a
portion of service under this Agreement upon no less than
twenty four (24) hours notice and obtain an alternative source
of supply of SOS Requirements Power from the open market for
the remaining Term. In such event, the Seller shall be liable
to the Buyer for the entire difference between the cost of
such alternative source of supply obtained in the open market
and the cost of purchasing SOS Requirements Power under this
Agreement, plus all other costs reasonably incurred by the
Buyer to replace the Seller. The Parties hereby stipulate that
purchases by the Buyer at the applicable ISO-NE spot market
prices will be deemed commercially reasonable open market
prices for this purpose. Nothing in this Section 7.2 shall be
deemed as a waiver of any other legal or equitable remedies
that the Buyer may have against the Seller for breach of this
Agreement.
7.3 In the event that the Buyer defaults on its material
obligations to the Seller or NEPOOL in connection with this
Agreement at any time during the Term, and the Buyer does not
cure such default within a time period allowed by NEPOOL and
ISO-NE (but not to exceed ten (10) days if there is no
explicit NEPOOL or ISO-NE period for curing the default), the
Seller shall have the option to terminate or suspend all or a
portion of service under this Agreement upon no less than
twenty four (24) hours notice and thereafter sell any of the
resources it has obtained in order to meet its obligations
under this Agreement in the open market. In such event, the
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<PAGE> 12
Buyer shall be liable to the Seller for the entire difference
between the prices obtained by the Seller in the open market
and the price the Seller would have obtained for selling SOS
Requirements Power under this Agreement. The Parties hereby
stipulate that sales by the Seller at the applicable ISO-NE
spot market prices will be deemed commercially reasonable open
market prices for this purpose. Nothing in this Section 7.3
shall be deemed as a waiver of any other legal or equitable
remedies that the Seller may have against the Buyer for breach
of this Agreement.
7.4 Notwithstanding any other provision of this Agreement, neither
Party shall be liable to the other Party in the event that,
due to a cause beyond the reasonable control of, and without
the fault or negligence of the Party seeking to limit its
liability hereunder ("Force Majeure"), NEPOOL experiences
unplanned-for emergency system conditions, including but not
limited to a shortage of available electric generating
capacity or an insufficiency of transmission or distribution
facilities required for the delivery of SOS Requirements
Power, such that NEPOOL either must suspend the supply of one
or more of the products required to serve load in NEPOOL or
must curtail or interrupt all or a portion of the Standard
Offer Service Load.
7.5 For purposes of Section 7.4, "Force Majeure" shall include,
without limitation, sabotage, strikes, riots or civil
disturbance, acts of God, act of a public enemy, drought,
earthquake, flood, explosion, fire, lightning, landslide, or
any similar cataclysmic occurrence, or the appropriation or
diversion of electricity by sale or order of any governmental
authority having jurisdiction thereof. Under no circumstances
shall Force Majeure include an occurrence or event that merely
increases the costs of or causes an economic hardship to a
Party, or any occurrence or event that was caused by or
contributed to by the Party claiming Force Majeure.
7.6 Except as otherwise specifically provided for herein, neither
Party shall be liable to the other Party for any special,
indirect, incidental, consequential, or punitive damages of
any kind, including but not limited to loss of use, out of
pocket expenses and lost profits (past or future).
8. BUYER CREDIT/SECURITY ASSURANCES
8.1 NRG Energy, Inc. has provided the Buyer a certificate executed
by an officer of NRG Energy, Inc. certifying that NRG Energy,
Inc. has entered into a firm wholesale entitlements contract
("Entitlement Agreement") with the Seller for the full Term of
this Agreement, pursuant to which the Seller has acquired from
NRG Energy, Inc. firm, first-call entitlement rights to no
less than 1,600 MW of generating capacity located in the
NEPOOL control area that are owned or controlled by NRG
Energy, Inc. and has obtained, or will obtain, any regulatory
or other approvals required to put
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<PAGE> 13
the Entitlement Agreement into effect as of the commencement
of the Term. Entitlements in generating units obtained by NRG
Energy, Inc. pursuant to the Transition Agreement shall be
considered generating capacity owned and controlled by the
Seller for purposes of the prior sentence. The Entitlement
Agreement shall provide the Seller with all of the rights to
capacity, energy and ancillary services available from the
generating units such that the Seller can satisfy its
obligation to supply SOS Requirements Power for the full Term
of this Agreement; provided, however, that the Seller may
terminate the Entitlement Agreement if, during the Term, the
Seller achieves an Unsecured Investment Grade Rating of "Baa3"
or better from Moody's Investors Service or "BBB-" or better
from Standard & Poors Corporation, or an equivalent credit
rating by another nationally recognized rating service
reasonably acceptable to the Buyer; and provided further, if
the Seller is unable to maintain such Investment Grade Rating
during the Term, it shall either promptly re-instate the
Entitlement Agreement or promptly deliver to the Buyer a
written parent guarantee, in a form acceptable to the Buyer,
by NRG Energy, Inc. of the Seller's performance under this
Agreement for the remaining Term hereof.
8.2 The Parties hereby acknowledge that NRG Energy, Inc. or
another affiliate of Seller with an Unsecured Investment Grade
Rating of "Baa3" or better from Moody's Investors Service or
"BBB-" or better from Standard & Poors Corporation, or an
equivalent credit rating by another nationally recognized
rating service reasonably acceptable to the Buyer, has
provided the Buyer a corporate guarantee in the amount of $37
million, which is equal to ten (10) percent of the dollar
value for the first year of the awarded bid. The Seller shall
cause NRG Energy, Inc. or another qualifying affiliate of
Seller (as applicable) to keep such corporate guarantee in
place for the full Term.
8.3 By no later than the date of commencement of the Term, the
Buyer shall provide the Seller a performance or surety bond or
other similar financial instrument in a form and from an
issuer reasonably acceptable to the Seller in the amount of
$37 million, unless the Buyer shall have obtained an Unsecured
Investment Grade Rating of "Baa3" or better from Moody's
Investors Service or "BBB-" or better from Standard & Poors
Corporation, or an equivalent credit rating by another
nationally recognized rating service reasonably acceptable to
the Buyer, by such service commencement date. The Buyer shall
be entitled to terminate such surety bond or other similar
financial instrument immediately upon obtaining a Unsecured
Investment Grade Rating of "Baa3" or better from Moody's
Investors Service or "BBB-" or better from Standard & Poors
Corporation, or an equivalent credit rating by another
nationally recognized rating service reasonably acceptable to
the Buyer. If the Buyer is unable to maintain such Unsecured
Investment Grade Rating during the Term, it
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<PAGE> 14
shall promptly re-instate such performance or surety bond or
other financial instrument.
9. CONDITIONS
9.1 Conditions to Obligation of the Seller. The obligations of the
Seller under this Agreement are subject to the fulfillment and
satisfaction, on or prior to the Effective Date as defined in
Section 2.1, of each of the following conditions, any one or
more of which may be waived only in writing, in whole or in
part, by the Seller:
(a) Representations, Warranties and Covenants True at the
Effective Date. (i) All representations and warranties of
Buyer contained in this Agreement shall be true and
correct in all material respects as of the date when made
and at and as of the Effective Date as though such
representations and warranties had been made or given on
such date (except to the extent such representations and
warranties specifically pertain to an earlier date),
except (x) for changes contemplated by this Agreement and
(y) where the failure to be true and correct will not
have a Material Adverse Effect on the business, property,
financial condition, results of operations or prospects
of Buyer, or on the Seller's rights under this Agreement;
(ii) Buyer shall have performed and complied with, in all
material respects, its obligations that are to be
performed or complied with by it prior to or on the
Effective Date; and
(b) No Material Adverse Effect. No Material Adverse Effect
shall exist.
9.2 Conditions to Obligation of Buyer. The obligations of Buyer
under this Agreement are subject to the fulfillment and
satisfaction, on or prior to the Effective Date as defined in
Section 2.1, of each of the following conditions, any one or
more of which may only be waived in writing, in whole or in
part, by Buyer:
(a) Representations, Warranties and Covenants True at the
Effective Date. (i) All representations and warranties of
the Seller contained in this Agreement shall be true and
correct in all material respects when made and at and as
of the Effective Date as though such representations and
warranties had been made or given on such date (except to
the extent such representations and warranties
specifically pertain to an earlier date), except (x) for
changes contemplated by this Agreement and (y) where the
failure to be true and correct will not have a Material
Adverse Effect on the business, property, financial
condition, results of operations or prospects of the
Seller or Buyer's rights under this Agreement; (ii) the
Seller shall have performed and
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complied with, in all material respects, its obligations
that are to be performed or complied with by prior to or
on the Effective Date; and
(b) Absence of Material Adverse Effect. No Material Adverse
Effect shall exist.
9.3 Special Condition Regarding Retail Rates. The DPUC has issued
an order stating that it will set the General Services
Component ("GSC") rates for Retail Customers taking Standard
Offer Service after the negotiation of this Agreement, and
that such GSC rates will be established by retail rate class.
The Parties have agreed that the level of the GSC rates and
distribution to each retail rate class could affect the
Seller's expectations in submitting the prices set forth in
Section 4.1 in response to the RFP. Accordingly, the Parties
agree that, if the DPUC establishes GSC rates at levels which
include an adjustment above the weighted average Standard
Offer price that are in excess of the maximum rate adjustments
set forth in the table below, the Seller shall have the right
to seek to renegotiate the prices set forth in Section 4.1,
solely as necessary to reflect the GSC rate adjustment
exceeding the amounts in the table set forth below. The
Parties agree that these adjustments in the table below
reflect both a retail adder and a wholesale rate specific
adjustment. The Parties further specifically agree that the
Seller's right to seek a renegotiation of the prices set forth
in Section 4.1 shall apply solely in the circumstance where
the DPUC approves GSC rates for any rate class that are in
excess of the weighted average Standard Offer price, plus the
maximum rate adjustments set forth in the table below, and
that this Section 9.3 creates no other right or remedy on
behalf of the Seller. In retail restructuring proceedings
before the DPUC, CL&P (1) shall not advocate the adoption of
GSC rates that include adders above the weighted average
Standard Offer price that are not cost-based, and (2)
consistent with (1) above, shall request and advocate that the
DPUC adopt retail GSC rates that include adders that are below
those set forth in this Section 9.3.
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Table:
- ------------------------- ----------------------
CL&P's Rate Proposed GSC
Schedule No. Maximum Rate
Adjustment
- ------------------------- ----------------------
1
- ------------------------- ----------------------
5
- ------------------------- ----------------------
7
- ------------------------- ----------------------
18
- ------------------------- ----------------------
27
- ------------------------- ----------------------
29
- ------------------------- ----------------------
30
- ------------------------- ----------------------
35
- ------------------------- ----------------------
40
- ------------------------- ----------------------
41
- ------------------------- ----------------------
55
- ------------------------- ----------------------
56
- ------------------------- ----------------------
57
- ------------------------- ----------------------
58
- ------------------------- ----------------------
115
- ------------------------- ----------------------
116
- ------------------------- ----------------------
117
- ------------------------- ----------------------
985
- ------------------------- ----------------------
119
- ------------------------- ----------------------
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<PAGE> 17
10. REPRESENTATIONS AND WARRANTIES
10.1 Each Party hereby represents and warrants to the other that:
(a) It is duly organized, validly existing and in good
standing under the laws of its jurisdiction of
organization and is duly qualified to do business in all
jurisdictions where such qualification is required.
(b) It has full power and authority to enter this Agreement
and perform its obligations hereunder. The execution,
delivery and performance of this Agreement have been duly
authorized by all necessary corporate action and do not
and will not contravene its organizational documents or
conflict with, result in a breach of, or entitle any
Party (with due notice or lapse of time or both) to
terminate, accelerate or declare a default under, any
agreement or instrument to which it is a party or by
which it is bound. The execution, delivery and
performance by it of this Agreement will not result in
any violation by it of any law, rule or regulation
applicable to it. It is not a party to, nor subject to or
bound by, any judgment, injunction or decree of any court
or other governmental entity which may restrict or
interfere with the performance of this Agreement by it.
This Agreement is its valid and binding obligation,
enforceable against it in accordance with its terms,
except as (i) such enforcement may be subject to
bankruptcy, insolvency, reorganization, moratorium or
other similar laws now or hereafter in effect relating to
creditors' rights generally and (ii) the remedy of
specific performance and injunctive relief may be subject
to equitable defenses and to the discretion of the court
before which any proceeding therefor may be brought.
(c) Except as otherwise specifically provided in this
Agreement, no consent, waiver, order, approval,
authorization or order of, or registration, qualification
or filing with, any court or other governmental agency or
authority is required for the execution, delivery and
performance by such Party of this Agreement and the
consummation by such Party of the transactions
contemplated hereby and no consent or waiver of any party
to any contract to which such Party is a party or by
which it is bound is required for the execution, delivery
and performance by such Party of this Agreement.
(d) There is no action, suit, grievance, arbitration or
proceeding pending or, to the knowledge of such Party,
threatened against or affecting such Party at law or in
equity, before any federal, state, municipal or other
governmental court, department, commission, board,
arbitrator, bureau, agency or instrumentality that
prohibits or impairs its ability to execute and deliver
this Agreement. Such Party has not received written
notice of any such pending or threatened investigation,
inquiry or review by any governmental entity.
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10.2 The Buyer hereby represents that it has not asserted and will
not take during the term any position before the DPUC or FERC
that is inconsistent with the rights and obligations of the
Parties under this Agreement, provided that the foregoing will
not prevent the Buyer from asserting or taking any position
before such agencies which it reasonably believes is necesarry
for it to meet applicable legal requirements.
11. ASSIGNMENT
11.1 Neither Party shall assign, pledge or transfer this Agreement
without the prior written consent of the other Party, which
consent shall not be unreasonably withheld. When assignable,
this Agreement shall be binding upon, shall inure to the
benefit of, and may be performed by, the successors and
assignees of the Parties, except that no assignment, pledge or
other transfer of this Agreement by either Party shall operate
to release the assignor, pledgor, or transferor from any of
its obligations under this Agreement unless the other Party
(or its successors or assigns) consents in writing to the
assignment, pledge or other transfer and expressly releases
the assignor, pledgor, or transferor from its obligations
hereunder. Notwithstanding the foregoing, either Party may
transfer or assign its interest hereunder to an affiliate, or
to a successor in interest of such Party by virtue of a
merger, acquisition or other similar corporate transaction
involving all or substantially all of the assets of the
assigning Party, without obtaining the consent of the other
Party, provided that the assignee has a credit status at the
time of such transfer or assignment which, in the
non-assigning Party's reasonable opinion, is at least as sound
as that of the assignor. Nothing in the foregoing shall be
construed as limiting the Seller's right to assign or
otherwise transfer a security interest in the revenues
generated under this Agreement to a third party, and Buyer
expressly consents to such assignment for security interest
purposes, provided that such assignment or transfer shall not
limit in any way the Seller's obligations to the Buyer
hereunder.
12. ACCOUNTS AND RECORDS
12.1 The Seller and Buyer each shall keep complete and accurate
accounts and records with respect to its performance under
this Agreement and shall maintain such data for a period of at
least one (1) year after final billing for audit by the other
Party; provided, however, that in the event of any billing
dispute or pending accounting, all such accounts and records
pertaining to any bill or charge in dispute or pending
accounting shall be maintained until such later time as the
billing dispute is resolved or the accounting is completed. If
an accounting or billing dispute establishes
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<PAGE> 19
that any bill submitted to and paid by Buyer was for an amount
greater than properly chargeable under this Agreement, Seller
shall refund to Buyer the excess amount collected together
with interest calculated in accordance with the FERC's
regulations governing interest on refunds. If such accounting
or billing dispute establishes that any bill submitted to and
paid by Buyer was for an amount less than properly chargeable
under this Agreement, Buyer shall make such additional payment
to bring its account into balance, together with interest
calculated in accordance with the FERC's regulations governing
interest on refunds. The Parties agree to individually and
jointly request from NEPOOL or the ISO, or other appropriate
source, any data or information which either Party believes is
reasonably necessary for purposes of a requested accounting or
resolution of a billing dispute. Each Party shall have the
right, during normal business hours and at its own expense, to
examine, inspect and make copies of all such accounts and
records insofar as may be necessary for the purpose of
ascertaining the reasonableness and accuracy of all relevant
data, estimates or statement of charges submitted hereunder.
The records supplied by the Buyer to the Seller for auditing
purposes hereunder shall include the Buyer's hourly
calculation of its Standard Offer Service Load.
13. INDEMNIFICATION
13.1 Indemnification by Buyer. Buyer shall indemnify, defend and
hold harmless the Seller and the Seller's board members,
officers, trustees, directors, agents, employees and
affiliates from and against any and all claims, demands,
liabilities (including reasonable attorney's fees), and
judgments, fines, settlements and other amounts ("Damages")
arising from any and all civil, criminal, administrative or
investigative proceedings ("Claims") relating to or arising
out of:
(a) any failure of Buyer to observe or perform any material
term or provision of this Agreement;
(b) any failure of any representation or warranty made by
Buyer herein to be true in any material respect;
(c) any Claim of any third party to the extent arising from
the acts or omissions of Buyer or any of its agents or
employees except to the extent such acts or omissions are
caused by the Seller or its affiliates; and
(d) any bodily injury, death or damage to person or property
caused by the Buyer and its affiliates and their
respective board members, officers, managers, employees
or agents or caused by their facilities,
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in each case in connection with or resulting from Buyer's
performance or non-performance of this Agreement except
to the extent caused by an act of negligence or willful
misconduct of the Seller.
13.2 Indemnification by Seller. Seller shall indemnify, defend and
hold harmless the Buyer and the Buyer's board members,
officers, trustees, directors, agents, employees and
affiliates from and against any and all claims, demands,
liabilities (including reasonable attorney's fees), and
judgments, fines, settlements and other amounts ("Damages")
arising from any and all civil, criminal, administrative or
investigative proceedings ("Claims") relating to or arising
out of:
(a) any failure of Seller to observe or perform any material
term or provision of this Agreement;
(b) any failure of any representation or warranty made by
Seller herein to be true in any material respect;
(c) any Claim of any third party to the extent arising from
the acts or omissions of Seller or any of its agents or
employees except to the extent such acts or omissions are
caused by the Buyer or its affiliates; and
(d) any bodily injury, death or damage to person or property
caused by the Seller and its affiliates and their
respective board members, officers, managers, employees or
agents or caused by their facilities, in each case in
connection with or resulting from Seller's performance or
non-performance of this Agreement except to the extent
caused by an act of negligence or willful misconduct of
the Buyer.
14. NOTICES
14.1 Any notice, demand, or request permitted or required under
this Agreement shall be delivered in person or mailed by
certified mail, postage prepaid, return receipt requested, or
otherwise confirm receipt to a Party at the applicable address
set forth below.
To Buyer:
Director, Regulatory Policy and Planning
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
To Seller:
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<PAGE> 21
Executive Director, Power Markets
NRG Power Marketing Inc.
1221 Nicollet Mall, Suite 700
Minneapolis, MN 55403
Such addresses may be changed from time to time by written notice by
either Party to the other Party without a need for an amendment to this
Agreement.
15. INTERPRETATION
15.1 The interpretation and performance of this Agreement shall be
according to and controlled by the Federal Power Act and
regulations and orders of the FERC thereunder and, to the
extent not controlled thereby, by the laws of the State of
Connecticut.
16. RESOLUTION OF DISPUTES
16.1 Any dispute between the Parties involving service under this
Agreement shall be referred to representatives of the Buyer
and Seller designated by the Parties for resolution on an
informal basis as promptly as practicable. In the event the
designated representatives are unable to resolve the dispute
within thirty (30) days, or such other period as the Parties
may jointly agree upon, such dispute may, by mutual agreement
of the Parties, be submitted to arbitration and resolved in
accordance with the arbitration procedure set forth in the
NEPOOL Transmission Tariff. If they do not agree to
arbitration, each Party shall be free to pursue any legal and
equitable remedies to which it may be entitled under this
Agreement and the applicable law before a court or government
agency with jurisdiction over the dispute.
17. MISCELLANEOUS
17.1 Each Party shall prepare, execute, and deliver to the other
Party any documents reasonably required to implement any
provision hereof.
17.2 Any number of counterparts of this Agreement may be executed
and each shall have the same force and effect as the original.
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<PAGE> 22
17.3 Failure of either Party to enforce any provision of this
Agreement or to require performance by the other Party of any
of the provisions hereof shall not be construed as a waiver of
such provisions or affect the validity of this Agreement, any
part hereof, or the right of either Party to thereafter
enforce each and every provision.
17.4 This Agreement is made subject to all lawful orders of those
state or federal regulatory bodies having jurisdiction hereof.
17.5 Nothing in this Agreement shall be construed as creating any
relationship between the Parties other than that of
independent contractor for the sale and purchase of
electricity.
17.6 The captions to sections throughout this Agreement are
intended solely to facilitate reading and reference to all
sections and provisions of this Agreement. Such captions shall
not affect the meaning or interpretation of this Agreement.
17.7 The invalidity or unenforceability of any provision of this
Agreement shall not affect the other provisions hereof. If any
provision of this Agreement is held to be invalid, such
provision shall not be severed from this Agreement; instead,
the scope of the rights and duties created thereby shall be
reduced by the smallest extent necessary to conform such
provision to the applicable law, preserving to the greatest
extent the intent of the Parties to create such rights and
duties as set out herein. If necessary to preserve the intent
of the Parties hereto, the Parties shall negotiate in good
faith to amend this Agreement, adopting a substitute provision
for the one deemed invalid or unenforceable that is legally
binding and enforceable.
17.8 The Buyer shall use reasonable efforts to supply the Seller
with any orders of the DPUC that may affect the Seller's
rights and obligations under this Agreement. Such orders shall
be provided to the individual designated for receipt of
notices pursuant to Section 14.1.
18. AMENDMENT
18.1 This Agreement may be amended only by a written agreement signed
by the Parties.
19. COMPLETE AND FULL AGREEMENT
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<PAGE> 23
19.1 This Agreement constitutes the entire agreement between the
Parties and supersedes all previous offers, negotiations,
discussions, communications and correspondence.
20. NOTICE OF TERMINATION
20.1 Upon expiration of the Term of this Agreement, Buyer will not
oppose and, if Seller requests, Buyer will support, any notice
of termination which Seller may be required to file under FERC
regulations.
21. EARLY TERMINATION
21.1 In the event that the Transition Agreement terminates pursuant
to and in accordance with Section 2.2 thereof prior to the
expiration of the Term of this Agreement, this Agreement shall
likewise terminate as of the date of termination of the
Transition Agreement in accordance with Section 2.2 thereof.
IN WITNESS WHEREOF, the undersigned Parties have caused this Agreement to be
executed in their names by their respective duly authorized officials, as of the
29th day of October, 1999.
The Connecticut Light and Power Company
By: /s/ James R. Shuckerow, Jr.
------------------------------------------
James R. Shuckerow, Jr.
Director, Wholesale Power Contracts
NRG Power Marketing Inc.
By: /s/ James J. Bender
------------------------------------------
James J. Bender
Vice President
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<PAGE> 24
APPENDIX A
CALCULATION OF THE STANDARD OFFER SUPPLIER'S
BILLING DETERMINANTS
The Contract Load Quantity will be determined in accordance with the
methodology accepted by the DPUC for the calculation of the load
responsibilities of competitive retail service suppliers in the competitive
retail markets in Connecticut and the settlement rules adopted by NEPOOL and the
NEPOOL ISO. The methodology set forth below is based on CL&P's proposed
methodology to the DPUC for calculating such retail load responsibilities and
current NEPOOL settlement rules, and shall apply unless such methodology is
changed pursuant to lawful action of NEPOOL or the DPUC. In the event that the
DPUC or NEPOOL implement any such changes, the Buyer shall promptly notify the
Seller in writing of such changes.
1. Determination of the System Retail Load.
On an hourly basis, the Buyer will calculate the aggregate load of its
Retail Customers, ( the "System Retail Load"). The System Retail Load will be
computed for each hour based on the total metered output of all generation
connected to the Buyer's system below the tie meters at which NEPOOL measures
net interchange between the Buyer's system and NEPOOL,and adding to that figure
the net imports into the Buyer's system (or subtracting net exports from the
system) as measured by the tie meters at or below the NEPOOL PTF, less
non-retail loads (e.g. wholesale load served to municipalities).
2. Determination of retail customer Hourly Loads.
For each hour, the Buyer will calculate the actual or estimated loads
of each of its Retail Customers using one of the following two methods:
a) In circumstances where the Customer has an interval
recording meter (capable of recording pulses in 15 minute, or other
intervals), the retail customer's initial hourly load is determined by
these interval pulses translated or
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<PAGE> 25
aggregated into hourly consumption quantities. The Buyer will use the
actual recorded meter readings, increased to account for losses on the
Buyer's system between the Delivery Point and end-use meters in
accordance with a study entitled, "Determination of Loss Factors for
the Northeast Utilities System" conducted by Northeast Utilities'
Transmission Planning Department dated October 1, 1989, to determine
the hourly loads of the Retail Customers.
b) In circumstances where Retail Customers do not have
interval meters capable of recording hourly consumption quantities, the
Buyer will determine the hourly loads of the Retail Customers using the
load estimation technique filed with the DPUC for purposes of
calculating retail load responsibilities of competitive suppliers under
the Connecticut retail choice program. The load estimation technique
will be based on load profile statistics developed for different retail
customer classes and segments, and for each calendar month, days and
time periods, based on statistical sampling of consumption patterns of
Retail Customers with interval recording meters. The average load
profiles so developed will be scaled for individual Retail Customers
using a usage factor that is calculated based on the relationship
between the individual Retail Customer's usage over the prior billing
period and the average retail class segment usage estimated over the
same time period, and increased to account for losses on the Buyer's
system between the Delivery Point and end-use meters in accordance with
a study entitled, "Determination of Loss Factors for the Northeast
Utilities System" conducted by Northeast Utilities' Transmission
Planning Department dated October 1, 1989.
3. Determination of Competitive Supplier Hourly Loads.
The hourly loads of each Competitive Supplier serving retail load on
the Buyer's system will be estimated using the following two step process:
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<PAGE> 26
a) Each retail customer will be assigned a Competitive
Supplier Code based on the identity of its Competitive Supplier. Those
Customers that have not designated a Competitive Supplier will be
assigned the Standard Offer Service Supplier Code. The retail customer
hourly loads, calculated in accordance with section 2(a) and (b) above,
associated with the Retail Customers that have been assigned the same
Competitive (or Standard Offer Service) Supplier Code, will be summed
for each hour.
b) Determination of Residual. The difference between the
System Retail Load (as determined in section 1 above) and the sum of
the load responsibilities of all Competitive Suppliers (including
Standard Offer Service load), determined in accordance with section
3(a), will constitute the "Residual". The Residual will be allocated to
each Competitive Supplier (and to the Standard Offer Service load) in
proportion to the ratio of the estimated part of the Supplier's
assigned retail customer load (as calculated in section 2(b) to the sum
of the estimated part of the retail customer loads of all Competitive
Suppliers, as calculated in section 2(b), including the Standard Offer
Service load.
4. Determination of SOS Total Hourly Loads.
The Standard Offer Service hourly load will be determined in accordance
with section 3 based on the calculated or estimated hourly loads, including
Residual allocations to estimated hourly loads, for all Retail Customers
assigned the Standard Offer Service Supplier Code.
5. Allocation of SOS Supplier Hourly Loads.
The total Standard Offer Service hourly load will be allocated among
each of the Sellers of Standard Offer Service based on the percentage of the
total Standard Offer Service Load assigned to that Seller in Section 3.5 of that
Seller's Standard Offer Service Agreement with the Buyer.
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<PAGE> 27
6. Reporting of SOS Supplier Hourly Loads to the ISO.
a) In accordance with the rules of NEPOOL, the Buyer will report to the
ISO the hourly loads, determined in accordance with section 5 of this Appendix
A, for each Seller of Standard Offer Service (or the NEPOOL participant
responsible for that Seller's load under NEPOOL rules), within 37 business hours
after the close of each day. Each Seller of Standard Offer Service, or the
NEPOOL participant designated by such Seller to assume the Seller's load
responsibility in NEPOOL, will have sole responsibility for all charges assessed
by the ISO based on the hourly loads reported by the Buyer.
b) The Contract Load Quantity for each Seller of Standard Offer Service
will be equal to the aggregate of the Standard Offer Service hourly loads of
such Seller, summed over the calendar month, as reported to NEPOOL in accordance
with section 6(a) of Appendix A.
7. Determination of SOS Supplier Billing Amount.
The SOS Supplier Billing Amount is equal to the Contract Load Quantity
multiplied by a delivery efficiency factor of 0.9238. This amount will be
submitted to Seller for purposes of billing hereunder. The delivery
efficiency factor set forth above shall not be subject to change during the
Term.
8. Determination of adjusted SOS Supplier Billing Amount.
In accordance with the requirements of NEPOOL Market Rules & Procedures
No. 18, the Buyer will submit to the ISO, within 90 days after the end of each
month, revised monthly energy quantities for each NEPOOL participant for such
month. The adjusted Contract Load Quantity for each Seller of Standard Offer
Service will be based on a 90 day true-up for that month submitted to NEPOOL by
the Buyer. The adjusted SOS Supplier Billing Amount will be the adjusted
Contract Load Quantity multiplied by a delivery efficiency factor of 0.9238.
-27-
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
SEPTEMBER 30, 1999 FINANCIAL STATEMENTS INCLUDED IN THE COMPANY'S FORM 10-Q AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FORM 10-Q.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<CASH> 25,236
<SECURITIES> 0
<RECEIVABLES> 84,831
<ALLOWANCES> 110
<INVENTORY> 59,535
<CURRENT-ASSETS> 232,040
<PP&E> 1,246,255
<DEPRECIATION> 116,019
<TOTAL-ASSETS> 2,526,361
<CURRENT-LIABILITIES> 959,753
<BONDS> 797,348
0
0
<COMMON> 1
<OTHER-SE> 722,242
<TOTAL-LIABILITY-AND-EQUITY> 2,526,361
<SALES> 237,855
<TOTAL-REVENUES> 283,581
<CGS> 148,211
<TOTAL-COSTS> 224,822
<OTHER-EXPENSES> 53,640
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 57,607
<INCOME-PRETAX> 5,119
<INCOME-TAX> (23,889)
<INCOME-CONTINUING> 29,008
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 29,008
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
