SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDING MARCH 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
------------- ----------------
Commission file number 1-6788
THE UNITED ILLUMINATING COMPANY
(Exact name of registrant as specified in its charter)
Connecticut 06-0571640
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)
157 Church Street, New Haven, Connecticut 06506
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 203-499-2000
None
(Former name, former address and former fiscal year, if changed
since last report.)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
The number of shares outstanding of the issuer's only class of common
stock, as of March 31, 1998, was 14,334,922.
- 1 -
<PAGE>
INDEX
Part I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three months ended
March 31, 1998 and 1997. 3
Consolidated Balance Sheet as of March 31, 1998 and
December 31, 1997. 4
Consolidated Statement of Cash Flows for the three months ended
March 31, 1998 and 1997. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 8
- Rate-Related Regulatory Proceedings 9
- Short-term Credit Arrangements 9
- Income Taxes 11
- Supplementary Information 12
- Fuel Financing Obligations and Other Lease Obligations 13
- Commitments and Contingencies 13
- Capital Expenditure Program 13
- Nuclear Insurance Contingencies 13
- Other Commitments and Contingencies 14
- Connecticut Yankee 14
- Hydro-Quebec 14
- Property Taxes 14
- Site Decontamination, Demolition and Remediation Costs 15
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 15
- Subsequent Event 16
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 17
- Major Influences on Financial Condition 17
- Capital Expenditure Program 19
- Liquidity and Capital Resources 20
- Subsidiary Operations 21
- Results of Operations 21
- Looking Forward 23
Part II. OTHER INFORMATION
Item 1. Legal Proceedings. 28
Item 5. Other Information. 28
Item 6. Exhibits and Reports on Form 8-K. 29
SIGNATURES 31
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<PAGE>
<TABLE>
PART I: FINANCIAL INFORMATION
ITEM I: FINANCIAL STATEMENTS
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF INCOME
(Thousands except per share amounts)
(Unaudited)
<CAPTION>
Three Months Ended
March 31,
1998 1997
---- ----
<S> <C> <C>
OPERATING REVENUES (NOTE G) $162,474 $180,325
------------- -------------
OPERATING EXPENSES
Operation
Fuel and energy 40,541 54,921
Capacity purchased 6,222 10,917
Other 33,309 37,290
Maintenance 11,033 9,235
Depreciation 20,806 17,092
Amortization of cancelled nuclear project and deferred return 3,440 3,440
Income taxes (Note F) 11,487 11,315
Other taxes (Note G) 12,959 13,965
------------- -------------
Total 139,797 158,175
------------- -------------
OPERATING INCOME 22,677 22,150
------------- -------------
OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 30 204
Other-net (Note G) 445 781
Non-operating income taxes 83 1,417
------------- -------------
Total 558 2,402
------------- -------------
INCOME BEFORE INTEREST CHARGES 23,235 24,552
------------- -------------
INTEREST CHARGES
Interest on long-term debt 13,523 16,372
Interest on Seabrook obligation bonds owned by the company (1,818) (1,691)
Other interest (Note G) 844 766
Allowance for borrowed funds used during construction (129) (486)
------------- -------------
12,420 14,961
Amortization of debt expense and redemption premiums 650 678
------------- -------------
Net Interest Charges 13,070 15,639
------------- -------------
MINORITY INTEREST IN PREFERRED SECURITIES 1,203 1,203
------------- -------------
NET INCOME 8,962 7,710
Discount on preferred stock redemptions - (19)
Dividends on preferred stock 51 51
------------- -------------
INCOME APPLICABLE TO COMMON STOCK $8,911 $7,678
============= =============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 13,987 14,101
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 13,997 14,101
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $0.64 $0.54
CASH DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.72 $0.72
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
<CAPTION>
March 31, December 31,
1998 1997*
---- ----
(Unaudited)
<S> <C> <C>
Utility Plant at Original Cost
In service $1,875,676 $1,867,145
Less, accumulated provision for depreciation 662,263 644,971
--------------- ---------------
1,213,413 1,222,174
Construction work in progress 22,448 25,448
Nuclear fuel 25,049 25,990
--------------- ---------------
Net Utility Plant 1,260,910 1,273,612
--------------- ---------------
Other Property and Investments 33,119 32,451
--------------- ---------------
Current Assets
Cash and temporary cash investments 16,261 32,002
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 54,071 57,231
Other 24,735 27,914
Accrued utility revenues 22,903 25,269
Fuel, materials and supplies, at average cost 22,915 19,147
Prepayments 6,365 3,397
Other 87 67
--------------- ---------------
Total 147,337 165,027
--------------- ---------------
Deferred Charges
Unamortized debt issuance expenses 9,518 6,611
Other 4,520 5,727
--------------- ---------------
Total 14,038 12,338
--------------- ---------------
Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 224,387 228,992
Connecticut Yankee 49,995 51,313
Deferred return - Seabrook Unit 1 22,024 25,171
Unamortized redemption costs 22,648 23,027
Unamortized cancelled nuclear projects 11,832 12,125
Uranium enrichment decommissioning cost 1,302 1,312
Other 6,008 6,357
--------------- ---------------
Total 338,196 348,297
--------------- ---------------
$1,793,600 $1,831,725
=============== ===============
</TABLE>
*Derived from audited financial statements
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
<CAPTION>
March 31, December 31,
1998 1997*
---- ----
(Unaudited)
<S> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $292,006 $288,730
Paid-in capital 1,850 1,349
Capital stock expense (2,182) (2,182)
Unearned employee stock ownership plan equity (10,922) (11,160)
Retained earnings 161,047 162,226
--------------- ---------------
441,799 438,963
Preferred stock 4,351 4,351
Minority interest in preferred securities 50,000 50,000
Long-term debt
Long-term debt 737,479 746,058
Investment in Seabrook obligation bonds (92,860) (101,388)
--------------- ---------------
Net long-term debt 644,619 644,670
--------------- ---------------
Total 1,140,769 1,137,984
--------------- ---------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 39,196 40,821
Pensions accrued 38,271 39,149
Nuclear decommissioning obligation 18,352 17,538
Obligations under capital leases 16,769 16,853
Other 5,823 5,507
--------------- ---------------
Total 118,411 119,868
--------------- ---------------
Current Liabilities
Current portion of long-term debt 74,574 100,000
Notes payable 45,120 37,751
Accounts payable 42,648 68,699
Dividends payable 10,140 10,051
Taxes accrued 16,085 4,166
Interest accrued 12,794 10,266
Obligations under capital leases 342 340
Other accrued liabilities 34,623 37,471
--------------- ---------------
Total 236,326 268,744
--------------- ---------------
Customers' Advances for Construction 1,888 1,878
--------------- ---------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 16,195 16,385
Other 2,357 2,356
--------------- ---------------
Total 18,552 18,741
--------------- ---------------
Deferred Income Taxes (future tax liabilities owed 277,654 284,510
to taxing authorities)
Commitments and Contingencies (Note L)
--------------- ---------------
$1,793,600 $1,831,725
=============== ===============
</TABLE>
* Derived from audited financial statements
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<CAPTION>
Three Months Ended
March 31,
1998 1997
---- ----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $8,962 $7,710
------------- ------------
Adjustments to reconcil net income
to net cash provided by operating activities:
Depreciation and amortization 21,851 18,354
Deferred income taxes (2,251) (3,228)
Deferred investment tax credits - net (190) (190)
Amortization of nuclear fuel 1,265 1,568
Allowance for funds used during construction (159) (690)
Amortization of deferred return 3,147 3,147
Changes in:
Accounts receivable - net 6,339 12,677
Fuel, material and supplies (3,768) (75)
Prepayments (2,968) 3,214
Accounts payable (26,051) (19,143)
Interest accrued 2,528 2,394
Taxes accrued 11,919 10,529
Other assets and liabilities (2,792) 742
------------- ------------
Total Adjustments 8,870 29,299
------------- ------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 17,832 37,009
------------- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 4,015 -
Long-term debt 99,780 -
Notes payable 7,369 43,624
Securities redeemed and retired:
Long-term debt (133,976) (32,585)
Preferred stock - (40)
Discount on preferred stock redemption - 19
Expense of issue (800) -
Lease obligations (82) (76)
Dividends
Preferred stock (51) (52)
Common stock (10,000) (10,153)
------------- ------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES (33,745) 737
------------- ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (8,356) (14,452)
Investment in debt securities 8,528 -
------------- ------------
NET CASH USED IN INVESTING ACTIVITIES 172 (14,452)
------------- ------------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (15,741) 23,294
BALANCE AT BEGINNING OF PERIOD 32,002 6,394
------------- ------------
BALANCE AT END OF PERIOD $16,261 $29,688
============= ============
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $10,626 $11,005
============= ============
Income taxes $2,900 $3,700
============= ============
</TABLE>
The accompanying Notes to Consolidated Financial
Statements are an integral part of the financial statements.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The consolidated financial statements of the Company and its wholly-owned
subsidiary, United Resources, Inc., have been prepared pursuant to the rules and
regulations of the Securities and Exchange Commission. The statements reflect
all adjustments that are, in the opinion of management, necessary to a fair
statement of the results for the periods presented. All such adjustments are of
a normal recurring nature. Certain information and footnote disclosures normally
included in financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such rules and
regulations. The Company believes that the disclosures are adequate to make the
information presented not misleading. These consolidated financial statements
should be read in conjunction with the consolidated financial statements and the
notes to consolidated financial statements included in the annual report on Form
10-K for the year ended December 31, 1997. Such notes are supplemented as
follows:
(A) STATEMENT OF ACCOUNTING POLICIES
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
The weighted average AFUDC rate applied in the first three months of 1998
and 1997 was 8.0% on a before-tax basis.
CASH AND TEMPORARY CASH INVESTMENTS
For cash flow purposes, the Company considers all highly liquid debt
instruments with a maturity of three months or less at the date of purchase to
be cash and temporary cash investments. The Company records outstanding checks
as accounts payable until the checks have been honored by the banks.
NUCLEAR DECOMMISSIONING TRUSTS
External trust funds are maintained to fund the estimated future
decommissioning costs of the nuclear generating units in which the Company has
an ownership interest. These costs are accrued as a charge to depreciation
expense over the estimated service lives of the units and are recovered in rates
on a current basis. The Company paid $645,000 and $643,000 in the first three
months of 1998 and 1997, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 1998, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$13.0 million and $5.4 million for Seabrook Unit 1 and Millstone Unit 3,
respectively. These fund balances are included in "Other Property and
Investments" and the accrued decommissioning obligation is included in
"Noncurrent Liabilities" on the Company's Consolidated Balance Sheet.
INTEREST RATE AND FUEL PRICE MANAGEMENT
The Company utilizes interest rate and fuel oil price management
instruments to manage interest rate and fuel oil price risk. Interest rate swap
agreements have been entered into that effectively convert the interest rates on
$225 million of variable rate term loan borrowings to fixed rate borrowings.
Amounts receivable or payable under these swap agreements are accrued and
charged to interest expense. The Company enters into basic fuel oil price
management instruments to help minimize fuel oil price risk by fixing the future
price for fuel oil used for generation. Amounts receivable or payable under
these instruments are recognized in income when realized.
As of March 31, 1998, the Company had entered into swap agreements for 1998
for 950,000 barrels of fuel oil at a weighted average price of $15.821 per
barrel and had call options for 350,000 barrels of fuel oil at a weighted
average price of $18.56 per barrel.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(B) CAPITALIZATION
(a) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at March 31, 1998, of which 321,315 shares were unallocated shares
held by the Company's Employee Stock Ownership Plan ("ESOP") and not recognized
as outstanding for accounting purposes.
In 1990, the Company's Board of Directors and the shareowners approved a
stock option plan for officers and key employees of the Company. The plan
provides for the awarding of options to purchase up to 750,000 shares of the
Company's common stock over periods of from one to ten years following the dates
when the options are granted. The Connecticut Department of Public Utility
Control (DPUC) has approved the issuance of 500,000 shares of stock pursuant to
this plan. The exercise price of each option cannot be less than the market
value of the stock on the date of the grant. Options to purchase 3,500 shares of
stock at an exercise price of $30 per share, 7,800 shares of stock at an
exercise price of $39.5625 per share, and 5,000 shares of stock at an exercise
price of $42.375 per share have been granted by the Board of Directors and
remained outstanding at March 31, 1998. Options to purchase 14,299 shares of
stock at an exercise price of $30 per share, 54,500 shares of stock at an
exercise price of $30.75 per share, 4,000 shares of stock at an exercise price
of $35.625 per share, and 25,999 shares of stock at an exercise price of
$39.5625 per share were exercised during the first quarter of 1998.
The Company has entered into an arrangement under which it loaned $11.5
million to The United Illuminating Company ESOP. The trustee for the ESOP used
the funds to purchase shares of the Company's common stock in open market
transactions. The shares will be allocated to employees' ESOP accounts, as the
loan is repaid, to cover a portion of the Company's required ESOP contributions.
The loan will be repaid by the ESOP over a twelve-year period, using the Company
contributions and dividends paid on the unallocated shares of the stock held by
the ESOP. As of March 31, 1998, 321,315 shares, with a fair market value of
$15.5 million, had been purchased by the ESOP and had not been committed to be
released or allocated to ESOP participants.
(b) RETAINED EARNINGS RESTRICTION
The indenture under which $200 million principal amount of Notes are issued
places limitations on the payment of cash dividends on common stock and on the
purchase or redemption of common stock. Retained earnings in the amount of
$102.9 million were free from such limitations at March 31, 1998.
(c) PREFERRED STOCK
In April 1998, the Company purchased at a discount on the open market, and
canceled, 524 shares of its $100 par value 4.35%, Series A preferred stock. The
shares, having a par value of $52,400 were purchased for $31,440, creating a net
gain of $20,960.
(e) LONG-TERM DEBT
On January 13, 1998, the Company issued and sold $100 million principal
amount of 6.25% four-year and eleven-month Notes. The yield on the Notes, which
were issued at a discount, is 6.30%; and the Notes will mature on December 15,
2002. The proceeds from the sale of the Notes were used to repay $100 million
principal amount of 7 3/8% Notes, which matured on January 15, 1998.
In March 1998, the Company repurchased $33,798,000 principal amount of
6.20% Notes, at a premium of $178,000, plus accrued interest.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(C) RATE-REGULATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28, a massive and complex
statute designed to restructure the State's electric utility industry. The
business of generating and supplying electricity to consumers will be opened to
competition and will be separated from the business of delivering electricity to
consumers, beginning in the year 2000. The business of delivering electricity
will remain with the incumbent franchised utility companies (including the
Company). Beginning in 2000, each retail consumer of electricity in Connecticut
(excluding consumers served by municipal electric systems) will be able to
choose his, her or its supplier of electricity from among competing suppliers,
for delivery over the wire system of the franchised electric utility
(Distribution Company). Commencing no later than mid-1999, Distribution
Companies will be required to separate on consumers' bills the charge for
electricity generation services from the charge for delivering the electricity
and all other charges. The DPUC is directed to issue an order, by August 1,
1998, relative to this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will not otherwise be
recoverable in a competitive generation and supply market. These costs include
above-market long-term purchased power contract obligations, regulatory asset
recovery, above-market investments in power plants (stranded costs), and the
costs of systems benefits and conservation programs. They will be recovered by
the Distribution Companies from all consumers of electricity on a going-forward
basis, commencing in 2000. Because it is expected that many fossil-fueled power
plants may have market values in excess of their net historic costs, the
restructuring legislation requires that, in order for a Distribution Company to
recover the stranded costs associated with its power plants, its fossil-fueled
plants must be auctioned prior to 2000 and the excess proceeds used to mitigate
its recoverable stranded costs, and its nuclear-fueled power plants must be
auctioned prior to 2004.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4% of this decrease through rate reductions in 1997. The
1997 through 2001 rate plan agreed to between the DPUC and the Company in 1996
anticipated sufficient income in 2000 to accelerate amortization of regulatory
assets of about $50 million, equivalent to about 8% of retail revenues.
Substantially all of this accelerated amortization may have to be eliminated to
provide for the additional standard offer price reduction requirement and added
costs imposed by the restructuring legislation, although the legislation does
prescribe certain bases for adjusting the price of standard offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the 1996 five-year rate
plan, beginning in the year 2000.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
fluctuating interest rate determined by the prime lending market in New York,
and also permits the Company to borrow money for fixed periods of time specified
by the Company at fixed interest rates determined by either the Eurodollar
interbank market in London, or by bidding, at the Company's option. If a
material adverse change in the business, operations, affairs, assets or
condition, financial or otherwise, or prospects of the Company and its
subsidiaries, on a consolidated basis, should occur, the banks may decline to
lend additional money to the Company under this revolving credit agreement,
although borrowings outstanding at the time of such an occurrence would not then
become due and payable. As of March 31, 1998, the Company had $43 million of
short-term borrowings outstanding under this facility.
In addition, as of March 31, 1998, one of the Company's indirect
subsidiaries, American Payment Systems, Inc., had borrowings of $2.1 million
outstanding under a bank line of credit agreement.
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(F) INCOME TAXES
<CAPTION>
Three Months Ended
March 31,
1998 1997
---- ----
(000's)
<S> <C> <C>
Income tax expense consists of:
Income tax provisions:
Current
Federal $10,719 $10,066
State 3,126 3,250
------------- -------------
Total current 13,845 13,316
------------- -------------
Deferred
Federal (1,551) (2,054)
State (700) (1,174)
------------- -------------
Total deferred (2,251) (3,228)
------------- -------------
Investment tax credits (190) (190)
------------- -------------
Total income tax expense $11,404 $9,898
============= =============
Income tax components charged as follows:
Operating expenses $11,487 $11,315
Other income and deductions - net (83) (1,417)
------------- -------------
Total income tax expense $11,404 $9,898
============= =============
The following table details the components
of the deferred income taxes:
Seabrook sale/leaseback transaction ($2,181) ($2,586)
Conservation and load management (2,007) (930)
Accelerated depreciation 1,534 1,459
Tax depreciation on unrecoverable plant investment 1,212 1,232
Pension benefits 600 57
Unit overhaul and replacement power costs (398) (1,203)
Postretirement benefits (102) (144)
Deferred fossil fuel costs - (686)
Other - net (909) (427)
------------- -------------
Deferred income taxes - net ($2,251) ($3,228)
============= =============
</TABLE>
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<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(G) SUPPLEMENTARY INFORMATION
<CAPTION>
Three Months Ended
March 31,
1998 1997
---- ----
(000's)
<S> <C> <C>
Operating Revenues
- ------------------
Retail $146,545 $150,481
Wholesale - capacity 3,426 2,257
- energy 11,389 27,078
Other 1,114 509
--------------- ---------------
Total Operating Revenues $162,474 $180,325
=============== ===============
Sales by Class(MWH's)
- ---------------------
Retail
Residential 488,329 498,271
Commercial 564,789 540,458
Industrial 265,628 269,134
Other 12,173 12,277
--------------- ---------------
1,330,919 1,320,140
Wholesale 508,317 930,235
--------------- ---------------
Total Sales by Class 1,839,236 2,250,375
=============== ===============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $5,621 $5,732
Local real estate and personal property 5,482 6,137
Payroll taxes 1,856 2,096
--------------- ---------------
12,959 13,965
Nonoperating and other accounts 148 93
--------------- ---------------
Total Other Taxes $13,107 $14,058
=============== ===============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $320 $620
Equity earnings from Connecticut Yankee 307 446
Earnings (Loss) from subsidiary companies 195 (533)
Miscellaneous other income and (deductions) - net (377) 248
--------------- ---------------
Total Other Income and (Deductions) - net $445 $781
=============== ===============
Other Interest Charges
- ----------------------
Notes Payable $518 $577
Other 326 189
--------------- ---------------
Total Other Interest Charges $844 $766
=============== ===============
</TABLE>
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
(K) FUEL FINANCING OBLIGATIONS AND OTHER LEASE OBLIGATIONS
The Company has a Fossil Fuel Supply Agreement with a financial institution
providing for financing up to $37.5 million of fossil fuel purchases. Under this
agreement, the financing entity may acquire and/or store natural gas, coal and
fuel oil for sale to the Company, and the Company may purchase these fossil
fuels from the financing entity at a price for each type of fuel that reimburses
the financing entity for the direct costs it has incurred in purchasing and
storing the fuel, plus a charge for maintaining an inventory of the fuel
determined by reference to the fluctuating interest rate on thirty-day,
dealer-placed commercial paper in New York. The Company is obligated to insure
the fuel inventories and to indemnify the financing entity against all
liabilities, taxes and other expenses incurred as a result of its ownership,
storage and sale of fossil fuel to the Company. This agreement currently extends
to May 1999. At March 31, 1998, approximately $17.1 million of fossil fuel
purchases were being financed under this agreement.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $167.7 million, excluding AFUDC, for 1998 through 2002.
NUCLEAR INSURANCE CONTINGENCIES
The Price-Anderson Act, currently extended through August 1, 2002, limits
public liability resulting from a single incident at a nuclear power plant. The
first $200 million of liability coverage is provided by purchasing the maximum
amount of commercially available insurance. Additional liability coverage will
be provided by an assessment of up to $75.5 million per incident, levied on each
of the nuclear units licensed to operate in the United States, subject to a
maximum assessment of $10 million per incident per nuclear unit in any year. In
addition, if the sum of all public liability claims and legal costs resulting
from any nuclear incident exceeds the maximum amount of financial protection,
each reactor operator can be assessed an additional 5% of $75.5 million, or
$3.775 million. The maximum assessment is adjusted at least every five years to
reflect the impact of inflation. With respect to each of the three nuclear
generating units in which the Company has an interest, the Company will be
obligated to pay its ownership and/or leasehold share of any statutory
assessment resulting from a nuclear incident at any nuclear generating unit.
Based on its interests in these nuclear generating units, the Company estimates
its maximum liability would be $23.2 million per incident. However, any
assessment would be limited to $3.1 million per incident per year.
The NRC requires each nuclear generating unit to obtain property insurance
coverage in a minimum amount of $1.06 billion and to establish a system of
prioritized use of the insurance proceeds in the event of a nuclear incident.
The system requires that the first $1.06 billion of insurance proceeds be used
to stabilize the nuclear reactor to prevent any significant risk to public
health and safety and then for decontamination and cleanup operations. Only
following completion of these tasks would the balance, if any, of the segregated
insurance proceeds become available to the unit's owners. For each of the three
nuclear generating units in which the Company has an interest, the Company is
required to pay its ownership and/or leasehold share of the cost of purchasing
such insurance. Although each of these units has purchased $2.75 billion of
property insurance coverage, representing the limits of coverage currently
available from conventional nuclear insurance pools, the cost of a nuclear
incident could exceed available insurance proceeds. Under those circumstances,
the nuclear insurance pools that provide this coverage may levy assessments
against the insured owner companies if pool losses exceed the accumulated funds
available to the pool. The maximum potential assessments against the Company
with respect to losses occurring during current policy years are approximately
$5.0 million.
- 13 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
OTHER COMMITMENTS AND CONTINGENCIES
CONNECTICUT YANKEE
On December 4, 1996, the Board of Directors of the Connecticut Yankee
Atomic Power Company (Connecticut Yankee) voted unanimously to retire the
Connecticut Yankee nuclear plant (the Connecticut Yankee Unit) from commercial
operation. The Company has a 9.5% stock ownership share in Connecticut Yankee
and had relied on the Connecticut Yankee Unit for approximately 3.7% of the
Company's 1995 total generating resources. The power purchase contract under
which the Company has purchased its 9.5% entitlement to the Connecticut Yankee
Unit's power output permits Connecticut Yankee to recover 9.5% of all of its
costs from UI. Connecticut Yankee has filed revised decommissioning cost
estimates and amendments to the power contracts with its owners with the Federal
Energy Regulatory Commission (FERC). The estimate of the sum of future payments
for the closing, decommissioning and recovery of the remaining investment in the
Connecticut Yankee Unit was approximately $606 million at December 31, 1997.
Based on regulatory precedent, Connecticut Yankee believes it will continue to
collect from its owners its decommissioning costs, the unrecovered investment in
the Connecticut Yankee Unit and other costs associated with the permanent
shutdown of the Connecticut Yankee Unit. UI expects that it will continue to be
allowed to recover all FERC-approved costs from its customers through retail
rates. The Company's estimate of its remaining share of costs, including
decommissioning, less return of investment (approximately $10.8 million) and
return on investment (approximately $6.0 million) at March 31, 1998, is
approximately $39.2 million. This estimate, which is subject to ongoing review
and revision, has been recorded by the Company as a regulatory asset and an
obligation on the Consolidated Balance Sheet.
HYDRO-QUEBEC
The Company is a participant in the Hydro-Quebec transmission intertie
facility linking New England and Quebec, Canada. Phase I of this facility, which
became operational in 1986 and in which the Company has a 5.75% participating
share, has a 690 megawatt equivalent capacity value; and Phase II, in which the
Company has a 5.45% participating share, increased the equivalent capacity value
of the intertie from 690 megawatts to a maximum of 2000 megawatts in 1991. A
ten-year Firm Energy Contract, which provides for the sale of 7 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, became effective on July 1, 1991. Additionally, the Company
is obligated to furnish a guarantee for its participating share of the debt
financing for the Phase II facility. As of March 31, 1998, the Company's
guarantee liability for this debt was approximately $7.3 million.
PROPERTY TAXES
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8
- 14 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
million. On March 7, 1997, the Company received notices of assessment changes
relative to the assessed value of the Company's personal property for the tax
year 1997-1998, which notices purport to increase said assessed value by
approximately 54% over the valuations declared by the Company and are expected
to generate tax claims of approximately $3.7 million. The Company has vigorously
contested each of these actions by the City's tax assessor. In January 1996, the
Connecticut Superior Court granted the Company's motion for summary judgment
against the City relative to the earliest tax year at issue, 1991-1992, ruling
that, after January 31, 1992, the tax assessor had no statutory authority to
revalue personal property listed and valued on the Company's tax list for the
tax year 1991-1992. This Superior Court decision, which would also have been
applicable to and defeated the assessor's valuation increases for the two
subsequent tax years, 1992-1993 and 1993-1994, was appealed by the City. On
April 11, 1997, the Connecticut Supreme Court reversed the Superior Court's
decisions in this and two other companion cases involving other taxpayers,
ruling that the tax assessor had a three-year period in which to audit and
revalue personal property listed and valued on the Company's tax list for the
tax year 1991-1992. On May 8, 1998, the City and the Company reached a
comprehensive settlement of all of the Company's contested personal property tax
assessments and tax bills for the tax years 1991-1992 through 1997-1998 and the
Company's personal property tax assessments for the tax year 1998-1999 and
subsequent years. Under the terms of this settlement, the Company will pay the
City $14.025 million, subject to Superior Court approval of the settlement and
conditioned on the Company receiving authorization from the DPUC to recover the
settlement amount from its retail customers.
SITE DECONTAMINATION, DEMOLITION AND REMEDIATION COSTS
The Company has estimated that the total cost of decontaminating and
demolishing its Steel Point Station and completing requisite environmental
remediation of the site will be approximately $11.3 million, of which
approximately $8.3 million had been incurred as of March 31, 1998, and that the
value of the property following remediation will not exceed $6.0 million. As a
result of a 1992 DPUC retail rate decision, beginning January 1, 1993, the
Company has been recovering through retail rates $1.075 million of the
remediation costs per year. The remediation costs, property value and recovery
from customers will be subject to true-up in the Company's next retail rate
proceeding based on actual remediation costs and actual gain on the Company's
disposition of the property.
The Company is presently remediating an area of PCB contamination at a
site, bordering the Mill River in New Haven, that contains transmission
facilities and deactivated generation facilities. Remediation will include the
repair and/or replacement of approximately 560 linear feet of sheet piling. The
total cost of the remediation and sheet piling repair is presently estimated at
$15 million.
(M) NUCLEAR FUEL DISPOSAL AND NUCLEAR PLANT DECOMMISSIONING
New Hampshire has enacted a law requiring the creation of a
government-managed fund to finance the decommissioning of nuclear generating
units in that state. The New Hampshire Nuclear Decommissioning Financing
Committee (NDFC) has established $473 million (in 1998 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $83 million. This estimate assumes the prompt removal and
dismantling of the unit at the end of its estimated 36-year energy producing
life. Monthly decommissioning payments are being made to the state-managed
decommissioning trust fund. UI's share of the decommissioning payments made
during the first quarter of 1998 was $523,000. UI's share of the fund at March
31, 1998 was approximately $13.0 million.
Connecticut has enacted a law requiring the operators of nuclear generating
units to file periodically with the DPUC their plans for financing the
decommissioning of the units in that state. The current decommissioning cost
estimate for Millstone Unit 3 is $557 million (in 1998 dollars), of which the
Company's share would be approximately $21 million. This estimate assumes the
prompt removal and dismantling of the unit at the end of its estimated 40-year
energy producing life. Monthly decommissioning payments, based on these cost
estimates, are being made to a decommissioning trust fund managed by Northeast
Utilities (NU). UI's share of the Millstone Unit 3 decommissioning
- 15 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
payments made during the first quarter of 1998 was $122,000. UI's share of the
fund at March 31, 1998 was approximately $5.4 million. The decommissioning trust
fund for the Connecticut Yankee Unit is also managed by NU. For the Company's
9.5% equity ownership in Connecticut Yankee, decommissioning costs of $589,000
were funded by UI during the first quarter of 1998, and UI's share of the fund
at March 31, 1998 was $26.8 million. The current decommissioning cost estimate
for the Connecticut Yankee Unit, assuming the prompt removal and dismantling of
the unit commencing in 1997, is $456 million, of which UI's share would be $43
million.
(Q) SUBSEQUENT EVENT
The Company's largest unregulated subsidiary, American Payment Systems, is
in the process of investigating potential errors in its accounting records, the
extent of which cannot be accurately determined at this time. It is the present
opinion of the Company that any adjustments resulting from the investigation
will not be material to the 1998 consolidated results of operations. The
investigation should be completed during the second quarter of 1998.
- 16 -
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
MAJOR INFLUENCES ON FINANCIAL CONDITION
The Company's financial condition will continue to be dependent on the
level of its retail and wholesale sales and the Company's ability to control
expenses. The two primary factors that affect sales volume are economic
conditions and weather. Annual growth in total operation and maintenance
expense, excluding one-time items and cogeneration capacity purchases, has
averaged less than 1.5% during the past 5 years. The Company hopes to continue
to restrict this average to less than the rate of inflation in future years (see
"Looking Forward").
The Company's financial status and financing capability will continue to be
sensitive to many other factors, including conditions in the securities markets,
economic conditions, interest rates, the level of the Company's income and cash
flow, and legislative and regulatory developments, including the cost of
compliance with increasingly stringent environmental legislation and regulations
and competition within the electric utility industry.
On December 31, 1996, the DPUC completed a financial and operational
review of the Company and ordered a five-year incentive regulation plan for the
years 1997 through 2001. The DPUC did not change the existing retail base rates
charged to customers; but its order increased amortization of the Company's
conservation and load management program investments during 1997-1998, and
accelerated the recovery of unspecified regulatory assets during 1999-2001 if
the Company's common stock equity return on utility investment exceeds 10.5%
after recording the increased conservation and load management amortization. The
order also reduced the level of conservation adjustment mechanism revenues in
retail prices, provided a reduction in customer prices through a surcredit in
each of the five plan years, and accepted the Company's proposal to modify the
operation of the fossil fuel clause mechanism. The Company's authorized return
on utility common stock equity during the period is 11.5%. Earnings above 11.5%,
on an annual basis, are to be utilized one-third for customer price reductions,
one-third to increase amortization of regulatory assets, and one-third retained
as earnings. As a result of the DPUC's order, customer prices were required to
be reduced, on average, by 3% in 1997 compared to 1996. Retail revenues actually
decreased by approximately $30 million, or 4.6%, in 1997 due to customer price
reductions. Also as a result of the order, customer prices are required to be
reduced by an additional 1% in 2000, and another 1% in 2001, compared to 1996.
By its terms, the DPUC's 1996 order should be reopened in 1998 to determine the
regulatory assets to be subjected to accelerated recovery in 1999, 2000 and
2001.
In April 1998, Connecticut enacted Public Act 98-28, a massive and complex
statute designed to restructure the State's electric utility industry. The
business of generating and supplying electricity to consumers will be opened to
competition and will be separated from the business of delivering electricity to
consumers, beginning in the year 2000. The business of delivering electricity
will remain with the incumbent franchised utility companies (including the
Company). Beginning in 2000, each retail consumer of electricity in Connecticut
(excluding consumers served by municipal electric systems) will be able to
choose his, her or its supplier of electricity from among competing suppliers,
for delivery over the wire system of the franchised electric utility
(Distribution Company). Commencing no later than mid-1999, Distribution
Companies will be required to separate on consumers' bills the charge for
electricity generation services from the charge for delivering the electricity
and all other charges. The DPUC is directed to issue an order, by August 1,
1998, relative to this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will not otherwise be
recoverable in a competitive generation and supply market. These costs include
above-market long-term purchased power contract obligations, regulatory asset
recovery, above-market investments in power plants (stranded costs), and the
costs of systems benefits and conservation programs. They will be recovered by
the Distribution Companies from all consumers of electricity on a going-forward
basis, commencing in 2000. Because
- 17 -
<PAGE>
it is expected that many fossil-fueled power plants may have market values in
excess of their net historic costs, the restructuring legislation requires that,
in order for a Distribution Company to recover the stranded costs associated
with its power plants, its fossil-fueled plants must be auctioned prior to 2000
and the excess proceeds used to mitigate its recoverable stranded and social
policy costs.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4% of this decrease through rate reductions in 1997. The
DPUC's 1996 order anticipated sufficient income in 2000 to accelerate
amortization of regulatory assets of about $50 million, equivalent to about 8%
of retail revenues. Substantially all of this accelerated amortization may have
to be eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the 1996 order, beginning in
the year 2000.
Currently, the Company's electric service rates are subject to regulation
and are based on the Company's costs. Therefore, the Company, and most regulated
utilities, are subject to certain accounting standards (Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS No. 71)) that are not applicable to other businesses in
general. These accounting rules allow a regulated utility, where appropriate, to
defer the income statement impact of certain costs that are expected to be
recovered in future regulated service rates and to establish regulatory assets
on its balance sheet for such costs. The effects of competition or a change in
the cost-based regulatory structure could cause the operations of the Company,
or a portion of its assets or operations, to cease meeting the criteria for
application of these accounting rules. While the Company expects to continue to
meet these criteria in the foreseeable future, if the Company, or a portion of
its assets or operations, were to cease meeting these criteria, accounting
standards for businesses in general would become applicable and immediate
recognition of any previously deferred costs, or a portion of deferred costs,
would be required in the year in which the criteria are no longer met, if such
deferred costs are not recoverable in that portion of the business that
continues to meet the criteria for the application of SFAS No. 71. If this
change in accounting were to occur, it would have a material adverse effect on
the Company's earnings and retained earnings in that year and could have a
material adverse effect on the Company's ongoing financial condition as well.
- 18 -
<PAGE>
CAPITAL EXPENDITURE PROGRAM
The Company's 1998-2002 capital expenditure program, excluding allowance
for funds used during construction (AFUDC) and its effect on certain
capital-related items, is presently budgeted as follows:
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002 Total
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Production (1) $7,800 $14,000 $4,500 $2,000 $2,500 $30,800
Distribution and Transmission 26,100 23,000 21,500 15,000 15,000 100,600
Other 3,300 3,400 1,000 1,000 1,000 9,700
------ ------ ------ ------ ------ -------
SUBTOTAL 37,200 40,400 27,000 18,000 18,500 141,100
Nuclear Fuel 8,300 800 8,500 6,000 3,000 26,600
------ ------ ------ ------ ------ -------
Total Expenditures $45,500 $41,200 $35,500 $24,000 $21,500 $167,700
====== ====== ====== ====== ====== =======
Rate Base and Other Selected Data:
- ---------------------------------
Depreciation
Book Plant 57,200 58,200 45,900 46,700 47,300
Conservation Assets 10,309 5,390 0 0 0
Decommissioning 2,700 2,800 2,900 3,000 3,100
Additional Required
Amortization (pre-tax)(2)
Conservation Assets 13,000 0 0 0 0
Other Regulatory Assets 0 20,300 0 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 12,586 0 0 0
Estimated Rate Base
(end of period) 1,106,000 1,043,000
</TABLE>
(1) Reflects divestiture of fossil fueled generation plant in 1999. Remaining
Production is nuclear generation plant, excluding nuclear fuel.
(2) Additional amortization of pre-1997 conservation costs and other
unspecified regulatory assets, as ordered by the DPUC in its December 31,
1996 Order, provided that, as expected, common equity return on utility
investment exceeds 10.5% after recording the additional amortization.
Note: Capital Expenditures and their effect on certain capital-related items
are estimates subject to change due to future events and conditions that
may be substantially different than those used in developing the
projections. In particular, the recently enacted legislation to
restructure Connecticut's electric utility industry will require the
Company to divest itself of its fossil-fueled generating plants prior to
January 1, 2000 and to attempt to divest itself of its ownership
interests in nuclear-fueled generating units prior to January 1, 2004.
- 19 -
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 1998, the Company had $16.3 million of cash and temporary cash
investments, a decrease of $15.7 million from the balance at December 31, 1997.
The components of this decrease, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
Balance, December 31, 1997 $32.0
-----
Net cash provided by operating activities 17.8
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (23.7)
- Dividend payments (10.0)
Net cash provided by investing activities, excluding
investment in plant 8.5
Cash invested in plant, including nuclear fuel (8.3)
----
Net Change in Cash (15.7)
-----
Balance, March 31, 1998 $16.3
=====
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year $ 32.0 $ - $ - $ - $ -
Internally Generated Funds less Dividends 114.0 120.0 89.0 90.0 95.0
----- ----- ---- ---- ----
Subtotal 146.0 120.0 89.0 90.0 95.0
Less:
Capital Expenditures 45.5 41.2 35.5 24.0 21.5
----- ----- ---- ---- ----
Cash Available to pay Debt Maturities and Redemptions 100.5 78.8 53.5 66.0 73.5
Less:
Maturities and Mandatory Redemptions 104.2 69.6 150.4 75.3 100.3
Optional Redemptions 33.8 - - - -
----- ----- ----- ---- -----
External Financing Requirements (Surplus) $ 37.5 $(9.2) $96.9 $ 9.3 $ 26.8
===== ===== ===== ==== =====
</TABLE>
Note:Internally Generated Funds less Dividends, Capital Expenditures and
External Financing Requirements are estimates based on current earnings and
cash flow projections, including the implementation of the legislative
mandate to achieve a 10% price reduction from 1996 average price levels by
the year 2000. All of these estimates are subject to change due to future
events and conditions that may be substantially different from those used
in developing the projections. In particular, the recently enacted
legislation to restructure Connecticut's electric utility industry will
require the Company to divest itself of its fossil-fueled generating plants
prior to January 1, 2000 and to attempt to divest itself of its ownership
interests in nuclear-fueled generating units prior to January 1, 2004.
- 20 -
<PAGE>
All of the Company's capital requirements that exceed available cash will
have to be provided by external financing. Although the Company has no
commitment to provide such financing from any source of funds, other than a $75
million revolving credit agreement with a group of banks, described below, the
Company expects to be able to satisfy its external financing needs by issuing
additional short-term and long-term debt, and by issuing preferred stock or
common stock, if necessary. The continued availability of these methods of
financing will be dependent on many factors, including conditions in the
securities markets, economic conditions, and the level of the Company's income
and cash flow.
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 9, 1998. The borrowing limit of this facility is
$75 million. The facility permits the Company to borrow funds at a fluctuating
interest rate determined by the prime lending market in New York, and also
permits the Company to borrow money for fixed periods of time specified by the
Company at fixed interest rates determined by either the Eurodollar interbank
market in London, or by bidding, at the Company's option. If a material adverse
change in the business, operations, affairs, assets or condition, financial or
otherwise, or prospects of the Company and its subsidiaries, on a consolidated
basis, should occur, the banks may decline to lend additional money to the
Company under this revolving credit agreement, although borrowings outstanding
at the time of such an occurrence would not then become due and payable. As of
March 31, 1998, the Company had $43 million of short-term borrowings outstanding
under this facility.
SUBSIDIARY OPERATIONS
UI has one wholly-owned subsidiary, United Resources, Inc. (URI), that
serves as the parent corporation for several unregulated businesses, each of
which is incorporated separately to participate in business ventures that will
complement and enhance UI's electric utility business and serve the interests of
the Company and its shareholders and customers.
URI has four wholly-owned subsidiaries. The largest URI subsidiary,
American Payment Systems, Inc., manages a national network of agents for the
processing of bill payments made by customers of other utilities. Another
subsidiary of URI, Thermal Energies, Inc., is participating in the development
of district heating and cooling facilities in the downtown New Haven area,
including the energy center for an office tower and participation as a 52%
partner in the energy center for a city hall and office tower complex. A third
URI subsidiary, Precision Power, Inc., provides power-related equipment and
services to the owners of commercial buildings and industrial facilities. URI's
fourth subsidiary, United Bridgeport Energy, Inc., is participating in a
merchant wholesale electric generating facility being constructed on land leased
from UI at its Bridgeport Harbor Station generating plant.
RESULTS OF OPERATIONS
FIRST QUARTER OF 1998 VS. FIRST QUARTER OF 1997
- -----------------------------------------------
Earnings for the first quarter of 1998 were $8.9 million, or $.64 per share
(on both a basic and diluted basis), up $1.2 million, or $.10 per share, from
the first quarter of 1997. There were no one-time items in either quarter.
Retail operating revenues decreased by about $3.9 million in the first
quarter of 1998 compared to the first quarter of 1997:
. A retail kilowatt-hour sales increase of 0.8% from the prior year
increased retail revenues by $1.2 million and sales margin (revenue less
fuel expense and revenue-based taxes) by $1.0 million. The Company believes
that "real" (i.e. not attributable to abnormal weather, workdays or
holidays) kilowatt-hour sales increased by about 2.0% in the first quarter
of 1998 compared to the first quarter of 1997. This increase seems
unusually high relative to the recent past and could indicate a lack of
sensitivity in the Company's weather correction methodology, although this
is the second consecutive quarter of strong real growth. Retail
kilowatt-hour sales decreased by about 1.5% due to warm weather (both
quarters were warmer than
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<PAGE>
normal, but the first quarter of 1998 was warmer than the first quarter of
1997). There was one less holiday in the first quarter of 1998 (Good Friday
was in April).
. Reductions in customer prices decreased retail revenues by about $5.2
million. About $1.9 million of this was due to suspension of the fossil
fuel adjustment clause (FAC) (this revenue reduction was offset by a $1.8
million expense reduction from lower fuel and energy prices). There will be
no further FAC revenue variances in future quarters. About $1.5 million of
the decreased revenues was due to customer price reductions, as agreed to
by the Company and the Connecticut Department of Public Utility Control in
December 1996; but this first quarter impact is due to timing issues (some
of the price reductions began in March 1997), so that this variance should
reverse over the remaining months of 1998. The remaining $1.8 million of
decreased revenues was due to rate mix and individual customer contract
pricing.
Retail fuel and energy expenses increased by $0.6 million in the first
quarter of 1998 compared to the first quarter of 1997. Retail fuel and energy
expenses increased by $1.0 million due to the need to purchase more expensive
energy to replace generation by the Seabrook nuclear generating unit, which was
taken out of service on December 5, 1997 to repair a pipe leak and problems with
control room air conditioning and air pressure. The unit resumed generation on
January 17, 1998. Other retail fuel and energy expenses decreased due to lower
fuel prices.
Net wholesale margin (wholesale revenue less wholesale expense) changed
only slightly in the first quarter of 1998 compared to the first quarter of
1997.
Operating expenses for operations, maintenance and purchased capacity
charges decreased by $6.9 million in the first quarter of 1998 compared to the
first quarter of 1997:
. Purchased capacity expense decreased $4.7 million. Expense decreased $2.1
million at the Connecticut Yankee nuclear unit as it continued a ramp down
of expenses into a decommissioning mode, and $2.6 million from avoided
power purchase payments due to a cogeneration facility being out of service
for about twenty-eight days in the first quarter of 1998. For more on the
status of the operation of the Connecticut Yankee unit, see the LOOKING
FORWARD section.
. Operation and maintenance expense decreased by $2.2 million. Pension
expense decreased by $1.4 million due to investment performance and changes
in actuarial assumptions and methodologies. Personnel reductions saved
about $1.3 million. These reductions were partly offset by $0.6 million of
increases at the Seabrook and Millstone nuclear generation units.
Depreciation expense increased by $0.4 million in the first quarter of 1998
compared to the first quarter of 1997.
Accelerated amortization increased by $3.3 million in the first quarter of
1998 compared to the first quarter of 1997, reflecting one quarter of the 1998
accelerated amortization requirements of the five-year rate plan implemented in
1997, and the Company's expectation that all of the required accelerated
amortization for 1998 will be recorded and that the Company will still achieve
at least a 10.5 percent return on utility common stock equity from earnings from
utility operations. (All of the accelerated amortization in 1997 was recorded in
the second quarter of that year as a result of a one-time gain recorded in that
quarter.)
Other net income increased slightly in the first quarter of 1998 compared
to the first quarter of 1997, due to higher unregulated subsidiary earnings that
were partly offset by lower interest income. The Company's largest unregulated
subsidiary, American Payment Systems (APS), earned about $161,000 (after-tax) in
the first quarter of 1998 compared to a loss of $241,000 (after-tax) in the
first quarter of 1997. For more on the status of the operations of APS, see Part
II. Other Information - Item 5. Other Information.
- 22 -
<PAGE>
Interest charges continued on their downward trend, decreasing by $2.9
million in the first quarter of 1998 compared to the first quarter of 1997, as a
result of the Company's refinancing program and strong cash flow.
LOOKING FORWARD
(THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS, WHICH ARE SUBJECT
TO UNCERTAINTIES THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE
CURRENTLY EXPECTED. READERS ARE CAUTIONED THAT THE COMPANY REGARDS SPECIFIC
NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF POSSIBLE VALUES.)
Five-year rate plan
- -------------------
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year regulatory
framework that would reduce the Company's retail prices and accelerate the
recovery of certain "regulatory assets," beginning with deferred conservation
costs. The Order's schedule of price reductions and accelerated amortizations
was based on a DPUC pro-forma financial analysis that anticipated the Company
would be able to implement such changes and earn an allowed return on common
stock equity invested in utility assets of 11.5% over the period 1997 through
2001. The Order established a set formula to share any income that would produce
a return above the 11.5% level: one-third would be applied to customer bill
reductions, one-third would be applied to additional amortization of regulatory
assets, and one-third would be retained by shareowners.
The DPUC, in the Order, acknowledged that the Order could be revisited in
the light of any new legislation. In April 1998, Connecticut enacted Public Act
98-28, a massive and complex statute designed to restructure the State's
electric utility industry. The business of generating and supplying electricity
to consumers will be opened to competition and will be separated from the
business of delivering electricity to consumers, beginning in the year 2000. The
business of delivering electricity will remain with the incumbent franchised
utility companies (including the Company), each to be called an "electric
distribution company" (Distribution Company). Beginning in 2000, each retail
consumer of electricity in Connecticut (excluding consumers served by municipal
electric systems) will be able to choose his, her or its supplier of electricity
from among the competing suppliers, for delivery over the wire system of the
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the charge for electricity
generation services from the charge for delivering the electricity and all other
charges. The DPUC is directed to issue an order, by August 1, 1998, relative to
this "unbundling" requirement.
A major component of Connecticut's restructuring legislation is the
collection, by Distribution Companies, of a "competitive transition" assessment,
a "systems benefits" charge, an "energy conservation and load management"
assessment and a "renewable energy" assessment, representing costs that either
have been or will be reasonably incurred by Distribution Companies to meet their
public service obligations as electric companies, and that will not otherwise be
recoverable in a competitive generation and supply market. These costs include
above-market long-term purchased power contract obligations, regulatory asset
recovery, above-market investments in power plants (stranded costs), and the
costs of systems benefits and conservation programs. They will be recovered by
the Distribution Companies from all consumers of electricity on a going-forward
basis, commencing in 2000. Because it is expected that many fossil-fueled power
plants may have market values in excess of their net historic costs, the
restructuring legislation requires that, in order for a Distribution Company to
recover the stranded costs associated with its power plants, its fossil-fueled
plants must be auctioned prior to 2000, and the excess proceeds used to mitigate
its recoverable stranded costs, and its nuclear-fueled power plants must be
auctioned prior to 2004.
Another requirement of the restructuring legislation is that, by October 1,
1998, each Distribution Company must file, for the DPUC's approval, an
"unbundling plan" to transfer into one or more legally separate corporate
affiliates, on or before October 1, 1999, all of its power plants that have not
been sold by that date and will not be sold prior to 2000.
- 23 -
<PAGE>
On and after January 1, 2000 and until January 1, 2004, the Company will be
responsible for providing a standard offer service to customers who do not
choose an alternate electricity supplier. The standard offer prices, including
the fully-bundled price of generation, transmission and distribution services,
the competitive transition assessment, the systems benefits charge and the
energy conservation and renewable energy assessments, must be 10% below the
average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4% of this decrease through rate reductions in 1997. The
Order anticipated sufficient income in 2000 to accelerate amortization of
regulatory assets of about $50 million, equivalent to about 8% of retail
revenues. Substantially all of this accelerated amortization may have to be
eliminated to provide for the additional standard offer price reduction
requirement and added costs imposed by the restructuring legislation, although
the legislation does prescribe certain bases for adjusting the price of standard
offer service.
The Company expects that, for all intents and purposes, the 1998
restructuring legislation will take precedence over the Order's five-year rate
plan, beginning in the year 2000.
1998 Earnings
- -------------
The Company's income from its utility business is greatly affected by:
retail sales that fluctuate with weather conditions and economic activity,
fossil fuel prices, nuclear generating unit availability and operating costs,
and interest rates. These are all items over which the Company has little
control, although the Company engages in economic development activities to
increase sales, and hedges its exposure to volatile fuel costs and interest
rates.
The Company's revenues are principally dependent on the level of retail
sales. The two primary factors that affect retail sales volume are economic
conditions and weather. The Company estimates that mild 1997 weather reduced
retail kilowatt-hour sales by about 0.5 percent for the year. Because much of
the mild weather occurred in the summer months, when prices are higher than
average, the revenue impact was exacerbated. It is estimated that mild weather
may have reduced revenues by as much as $5.2 million for the year, and sales
margin (revenue less fuel expense and revenue-based taxes) by as much as $4.2
million. Weather corrected retail sales for 1997 were probably in the
5,375-5,420 gigawatt-hour range. On this basis, the Company experienced about
1.0-1.5 percent of "real" sales growth in 1997 (i.e. exclusive of weather and
leap year factors) over "normal" 1996 sales, with almost all of the growth
occurring in the last half of the year. A similar level of growth in 1998
compared to 1997 from all customer groups would add about $6-$8 million to sales
margin. Although such growth in "real" sales occurred in the first quarter of
1998 compared to the first quarter of 1997, growth in future quarters may be
tempered by other factors, some of which are noted below.
Reductions in revenues could occur for several reasons. The Company has
dealt with the potential loss of customers as a result of self-generation,
relocation or discontinuation of operations by successfully negotiating
multi-year contracts with major customers. Such a contract has been signed with
Yale University, the Company's largest customer, which is constructing a
cogeneration unit that will produce approximately one half of its annual
electricity requirements (about 1.5 percent of the Company's total 1997 retail
sales), commencing sometime in mid-1998. While providing cost reduction and
price stability for customers and helping the Company maintain its customer base
for the long term, these contracts are expected to cause future reductions in
retail revenues. They reduced retail revenues by about $3 million in 1997
compared to 1996, but are not expected to approach that level of change in 1998.
Additionally, rate migration (customers switching to rates that are more
favorable because of usage patterns) reduced retail revenues by about $3 million
in 1997 compared to 1996; but the impact of rate migration on revenues in 1998
compared to 1997 is expected to be less than $1 million. Also, as part of the
Order, the operation of the Company's long-standing fossil fuel adjustment
clause (FAC) mechanism that allowed for recovery in retail rates of changes in
fossil fuel costs was suspended within a broad range of fuel prices. FAC
revenues decreased by about $1.9 million, to zero, in the first quarter of 1998
compared to the first quarter of 1997, due to this suspension of the FAC. There
will be no FAC revenue variances in future quarters.
- 24 -
<PAGE>
To summarize, assuming 1997 rates of "real" growth and the expected loss of
sales due to Yale University cogeneration, little change in retail kilowatt-hour
sales is expected in 1998 compared to 1997. Retail revenues will be reduced,
from what they would otherwise be, if the Company is in the "sharing" range
above an 11.5% return on common stock equity. Currently, the Company anticipates
a revenue reduction of about $1.0 million in 1998 under the sharing mechanism.
The overall average retail price anticipated for 1998 is about 11.6 cents per
kilowatt-hour, almost 5 percent below the average 1996 price.
Wholesale capacity prices strengthened in short-term markets during 1997,
due to outages of regional nuclear generating plants and changes in the New
England Power Pool (NEPOOL) capability responsibility requirements for its
participants. The Company's wholesale capacity and transmission sales revenues
increased $2.1 million in 1997 compared to 1996. The strength of these markets
for 1998 will depend on the timing of the return to service of the nuclear units
at Millstone Station, on the addition of new generation sources, and on how the
capacity and energy markets perform under the new NEPOOL open competition
system, designed to meet Federal Energy Regulatory Commission (FERC) open access
orders, when it is implemented. Implementation of this system is currently
expected in mid-1998; but this date is subject to NEPOOL information system
development and testing and further orders from the FERC. No significant sales
margin improvement is expected from wholesale capacity sales during 1998.
Wholesale energy revenues should remain similar to wholesale energy expense and
not contribute significantly to sales margin.
Another major factor affecting the Company's 1998 earnings prospects will
be the Company's ability to control operating expenses. The Company offered
voluntary early retirement programs and a voluntary severance program to union,
nonunion and management employees in 1996. A portion of the resulting personnel
cost savings occurred in 1996 and 1997, but the largest increment in annual
savings will be realized in 1998. Annual savings of about $6 million from
personnel reductions are estimated, and this amount was validated by first
quarter results.
The Company is expecting other significant expense declines in 1998
compared to 1997 from a number of sources. From the nuclear generating units, it
is expected that operation and maintenance expenses associated with the Seabrook
and Connecticut Yankee units should decline by a total of about $8 million. The
Seabrook unit should have no refueling outage in 1998 and, if it operates at an
assumed 95% availability (its availability was virtually 100% between refueling
outages in 1997), net fuel expense should decline by about $2 million.
Millstone Unit 3 was taken out of service on March 30, 1996, and will
remain shut down pending a comprehensive Nuclear Regulatory Commission (NRC)
inquiry into the conformity of the unit and its operations with all applicable
NRC regulations and standards. The Company anticipates that, once NRC
deficiencies are corrected and Unit 3 is returned to service, operating costs
should ramp down to more normal levels for an efficient and safe nuclear unit of
this class. Also, if Millstone Unit 3 returns to service, net fuel expense
should decline by $400,000 per month for every month of operation, net of the
replacement fuel provision of about $100,000 per month...up to $2.0 million for
the year if full power is reached by July 1, 1998.
Pension and health benefit expenses, excluding one-time items, are expected
to decrease by about $2.5 million in 1998 compared to 1997. NEPOOL expenses are
expected to increase by about $1.0 million, and expenses associated with the
"Year 2000 Issue" could increase by as much as $2.0-$3.0 million over the
1998-99 period, above the original $2.6 million estimate for information
technology systems. This is the result of receiving more current and detailed
information from embedded technology vendors. Other operation and maintenance
expenses may increase or decrease by amounts that cannot be predicted at this
time.
Interest costs are expected to continue to decline by about $10 million in
1998, reaching a level of about $52 million, a level that was last experienced
in 1984. This interest cost reduction is largely a result of 1997 debt
refinancings and debt paydown (long-term debt was reduced by $85 million in
1997) and an expected 1998 debt paydown of more than $70 million.
- 25 -
<PAGE>
Other factors should increase costs. Other operation and maintenance
expense should increase by about $6 million in 1998 compared to 1997, reflecting
increased fossil-fueled generating unit scheduled maintenance and provisions for
future outages. Base depreciation, excluding accelerated amortization, should
increase about $2.0 million; and accelerated amortization per the Order will
increase by about $7 million ($3.3 million per quarter, except for a $3.1
million decrease in the second quarter compared to 1997, as all of the
amortization for 1997 was recorded, as an offset to a one-time gain, in the
second quarter.) Other operating expenses will have some increases and some
decreases that should more or less offset one another.
In summary, the Company expects substantial net expense reductions that
should more than compensate for the loss of one-time items realized in 1997,
cover the increase in accelerated conservation and load management amortization,
and allow utility earnings to increase above an 11.5% return on common stock
equity into the "sharing" range of the Order. The 11.5% return level would
produce utility earnings of about $3.40-$3.45 per share, while "shared" earnings
could add an additional $.05-$.10 per share. Non-utility earnings should
increase approximately $.05 per share in 1998 compared to 1997, due principally
to the anticipated breakeven operation of the non-regulated subsidiaries. The
Company expects that 1998 quarterly earnings from operations will follow a
pattern similar to that of 1997 on a weather-normalized basis.
Although the current $2.88 indicated annual Common Stock dividend level for
1997 represented a payout of 88% of total 1997 earnings, the Company's cash flow
remains, and is expected to remain, very strong. Net cash provided by operating
activities was $168 million in 1997, over four times the Common Stock dividend
payout, one of the highest such "coverage" levels in the utility industry. The
Order will limit earnings from utility operations such that further dividend
increases may have to be delayed for several years. However, the Order should
allow the Company to recover regulatory assets more rapidly, help it prepare for
competition in the electric utility industry, and help maintain cash flow at its
excellent current level through the end of the decade. If the Company is able to
grow income and earnings in 1998 to the extent indicated above, the Common Stock
dividend payout ratio at the current indicated annual dividend rate will decline
to approximately 80%.
Longer Term
- -----------
In addition to the effects of Connecticut's 1998 electric utility industry
restructuring legislation (see the "Five-year rate plan" discussion at the
beginning of the Looking Forward section), there are several other matters that
will affect the longer-term outlook.
The Connecticut Yankee nuclear unit's expenses are expected to continue to
decline by substantial amounts before leveling out at about $6 million per year
after 1998, compared to $11.8 million in 1997, until decommissioning is
complete. However, the ability of the Company to recover its investment in
Connecticut Yankee and its ownership share of future costs associated with the
retirement of the Connecticut Yankee unit will be dependent upon the outcome of
pending regulatory filings with the Federal Energy Regulatory Commission.
On August 7, 1997, the Company and the other nine minority joint owners of
Millstone Unit 3 that are not subsidiaries of Northeast Utilities (NU) filed
lawsuits against NU and its trustees, as well as a demand for arbitration
against The Connecticut Light and Power Company and Western Massachusetts
Electric Company, the operating electric utility subsidiaries of NU that are the
majority joint owners of the unit and have contracted with the minority joint
owners to operate it. The ten non-NU joint owners, who together own about 19.5%
of the unit, claim that NU and its subsidiaries failed to comply with NRC
regulations, failed to operate Millstone Station in accordance with good utility
operating practice and concealed their failures from the non-operating joint
owners and the NRC. The arbitration and lawsuits seek to recover costs of
purchasing replacement power and increased operation and maintenance costs
resulting from the shutdown of Millstone Unit 3.
- 26 -
<PAGE>
The Company's planning and operations functions, and its cash flow, are
dependent on the timely flow of electronic data to and from its customers,
suppliers and other electric utility system managers and operators. In order to
assure that this data flow will not be disturbed by the problems emanating from
the fact that many existing computer programs were designed without considering
the impact of the year 2000 and use only two digits to identify the year in the
date field of the programs (the Year 2000 Issue), the Company initiated in
mid-1997, and is pursuing, an aggressive program to identify and correct
deficiencies in its computer systems. The Company is also identifying critical
suppliers and other persons with whom data must be exchanged and is asking for
assurance of their Year 2000 compliance. An inventory and assessment of the
Company's computer system applications, hardware, software and embedded
technologies has been completed, and recommended solutions to all identified
risks and exposures have been generated. A remediation, retirement, renovation
and testing program has commenced. Necessary upgrades to mainframe hardware and
software are expected to be completed and tested during 1998, and a parallel
program with respect to desktop hardware and application software on all
platforms is currently projected to be completed and tested, for all critical
systems, by March 31, 1999. Requests for documented compliance information have
been sent to all critical suppliers, data sharers and facility building owners
and, as responses are received, appropriate solutions and testing programs are
being developed and executed. The Company believes that the successful
implementation of this program, which was originally estimated to cost
approximately $2.6 million for existing information systems, will preclude any
adverse impact of the Year 2000 Issue on its operations and financial condition.
However, embedded technology issues may increase the originally estimated $2.6
million dollar resolution cost by as much as $2.0-$3.0 million dollars over the
1998-99 period. As more embedded technology vendor product information is
forthcoming and business decisions made, the extent of any such increase will be
determined.
- 27 -
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
On November 2, 1993, the Company received "updated" personal property tax
bills from the City of New Haven (the City) for the tax year 1991-1992,
aggregating $6.6 million, based on an audit by the City's tax assessor. On May
7, 1994, the Company received a "Certificate of Correction....to correct a
clerical omission or mistake" from the City's tax assessor relative to the
assessed value of the Company's personal property for the tax year 1994-1995,
which certificate purports to increase said assessed value by approximately 53%
above the tax assessor's valuation at February 28, 1994, generating tax claims
of approximately $3.5 million. On March 1, 1995, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1995-1996, which notices purport to increase said
assessed value by approximately 48% over the valuation declared by the Company,
generating tax claims of approximately $3.5 million. On May 11, 1995, the
Company received notices of assessment changes relative to the assessed values
of the Company's personal property for the tax years 1992-1993 and 1993-1994,
which notices purport to increase said assessed values by approximately 45% and
49%, respectively, over the valuations declared by the Company, generating tax
claims of approximately $4.1 million and $3.5 million, respectively. On March 8,
1996, the Company received notices of assessment changes relative to the
assessed value of the Company's personal property for the tax year 1996-1997,
which notices purport to increase said assessed value by approximately 57% over
the valuations declared by the Company and are expected to generate tax claims
of approximately $3.8 million. On March 7, 1997, the Company received notices of
assessment changes relative to the assessed value of the Company's personal
property for the tax year 1997-1998, which notices purport to increase said
assessed value by approximately 54% over the valuations declared by the Company
and are expected to generate tax claims of approximately $3.7 million. The
Company has vigorously contested each of these actions by the City's tax
assessor. In January 1996, the Connecticut Superior Court granted the Company's
motion for summary judgment against the City relative to the earliest tax year
at issue, 1991-1992, ruling that, after January 31, 1992, the tax assessor had
no statutory authority to revalue personal property listed and valued on the
Company's tax list for the tax year 1991-1992. This Superior Court decision,
which would also have been applicable to and defeated the assessor's valuation
increases for the two subsequent tax years, 1992-1993 and 1993-1994, was
appealed by the City. On April 11, 1997, the Connecticut Supreme Court reversed
the Superior Court's decisions in this and two other companion cases involving
other taxpayers, ruling that the tax assessor had a three-year period in which
to audit and revalue personal property listed and valued on the Company's tax
list for the tax year 1991-1992. On May 8, 1998, the City and the Company
reached a comprehensive settlement of all of the Company's contested personal
property tax assessments and tax bills for the tax years 1991-1992 through
1997-1998 and the Company's personal property tax assessments for the tax year
1998-1999 and subsequent years. Under the terms of this settlement, the Company
will pay the City $14.025 million, subject to Superior Court approval of the
settlement and conditioned on the Company receiving authorization from the DPUC
to recover the settlement amount from its retail customers.
ITEM 5. OTHER INFORMATION.
The Company's largest unregulated subsidiary, American Payment Systems, is
in the process of investigating potential errors in its accounting records, the
extent of which cannot be accurately determined at this time. It is the present
opinion of the Company that any adjustments resulting from the investigation
will not be material to the 1998 consolidated results of operations. The
investigation should be completed during the second quarter of 1998.
- 28 -
<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(10) 10.6g Copy of Restated New England Power Pool Agreement, amending and
restating Exhibits 10.6a+, 10.6b++, 10.6c+, 10.6d+, 10.6e+++,
and 10.6f+++.
(10) 10.13a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and Richard J.
Grossi, dated as of February 1, 1998, amending Exhibit 10.13++++.
(10) 10.14a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and Robert L.
Fiscus, dated as of February 1, 1998, amending Exhibit 10.14++++.
(10) 10.15a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and
James F. Crowe, dated as of February 1, 1998, amending
Exhibit 10.15++++.
(10) 10.16a* Copy of First Amendment to Employment Agreement between The
United Illuminating Company and Albert N. Henricksen, dated as
of February 1, 1998, amending Exhibit 10.16++++.
(10) 10.17a* Copy of First Amendment to Employment Agreement between The
United Illuminating Company and Anthony J. Vallillo, dated as of
February 1, 1998, amending Exhibit 10.17++++.
(10) 10.28* Copy of Employment Agreement, dated as of February 23, 1998,
between The United Illuminating Company and Nathaniel D. Woodson.
(10) 10.29* Copy of The United Illuminating Company Phantom Stock Option
Agreement, dated as of February 23, 1998, between The United
Illuminating Company and Nathaniel D. Woodson.
</TABLE>
- 29 -
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended March
31, 1998 and Twelve Months Ended December 31, 1997, 1996, 1995,
1994 and 1993).
(27) 27 Financial Data Schedule
</TABLE>
- ------------------------
+ Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1991.
++ Filed with Registration Statement No. 2-49669, effective December 11, 1973.
++ Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1993.
++++ Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended
September 30, 1997.
* Management contract or compensatory arrangement.
(b) Reports on Form 8-K.
None
- 30 -
<PAGE>
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.
THE UNITED ILLUMINATING COMPANY
Date 5/14/98 Signature /s/ Robert L. Fiscus
-------------------- ---------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
- 31 -
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(10) 10.6g Copy of Restated New England Power Pool Agreement, amending and
restating Exhibits 10.6a+, 10.6b++, 10.6c+, 10.6d+, 10.6e+++,
and 10.6f+++.
(10) 10.13a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and Richard J.
Grossi, dated as of February 1, 1998, amending Exhibit 10.13++++.
(10) 10.14a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and Robert L.
Fiscus, dated as of February 1, 1998, amending Exhibit 10.14++++.
(10) 10.15a* Copy of First Amendment to Amended and Restated Employment
Agreement between The United Illuminating Company and
James F. Crowe, dated as of February 1, 1998, amending
Exhibit 10.15++++.
(10) 10.16a* Copy of First Amendment to Employment Agreement between The
United Illuminating Company and Albert N. Henricksen, dated as
of February 1, 1998, amending Exhibit 10.16++++.
(10) 10.17a* Copy of First Amendment to Employment Agreement between The
United Illuminating Company and Anthony J. Vallillo, dated as of
February 1, 1998, amending Exhibit 10.17++++.
(10) 10.28* Copy of Employment Agreement, dated as of February 23, 1998,
between The United Illuminating Company and Nathaniel D. Woodson.
(10) 10.29* Copy of The United Illuminating Company Phantom Stock Option
Agreement, dated as of February 23, 1998, between The United
Illuminating Company and Nathaniel D. Woodson.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
- ---------- ------- -----------
<S> <C> <C>
(12), (99) 12 Statement Showing Computation of Ratios of Earnings to Fixed
Charges and Ratios of Earnings to Combined Fixed Charges and
Preferred Stock Dividend Requirements (Twelve Months Ended March
31, 1998 and Twelve Months Ended December 31, 1997, 1996, 1995,
1994 and 1993).
(27) 27 Financial Data Schedule
</TABLE>
- ------------------------
+ Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1991.
++ Filed with Registration Statement No. 2-49669, effective December 11, 1973.
+++ Filed with Annual Report (Form 10-K) for fiscal year ended
December 31, 1993.
++++ Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended
September 30, 1997.
* Management contract or compensatory arrangement.
EXHIBIT 10.6g
RESTATED
NEW ENGLAND
POWER POOL AGREEMENT
(Restated to reflect changes effected by the Fifth Supplement to Thirty-Third
Agreement Amending New England Power Pool Agreement, and the Thirty-Fifth
Agreement Amending New England Power Pool Agreement, and all prior amendments)
<PAGE>
||TABLE OF CONTENTS
PART ONE - INTRODUCTION....................................................1
SECTION 1 - DEFINITIONS....................................................1
1.1 Adjusted Load............................................1
1.2 Adjusted Monthly Peak....................................2
1.3 Adjusted Net Interchange.................................2
1.4 AGC Capability...........................................3
1.5 AGC Entitlement..........................................3
1.6 Agreement................................................4
1.7 Automatic Generation Control or AGC......................4
1.8 Bid Price................................................4
1.9 Commission...............................................5
1.10 Dispatch Price...........................................5
1.11 EHV PTF..................................................5
1.12 Electrical Load..........................................6
1.13 Energy...................................................7
1.14 Energy Entitlement.......................................7
1.15 Entitlement..............................................7
1.16 Entity...................................................8
1.17 Executive Committee......................................9
1.18 Firm Contract............................................9
1.19 First Effective Date.....................................9
1.20 Good Utility Practice...................................10
1.21 HQ Contracts............................................10
1.22 HQ Energy Banking Agreement.............................10
1.23 HQ Interconnection......................................11
1.24 HQ Interconnection Agreement............................11
1.25 HQ Interconnection Capability Credit....................12
1.26 HQ Interconnection Transfer Capability..................12
1.27 HQ Net Interconnection Capability Credit................13
1.28 HQ Phase I Energy Contract..............................13
1.29 HQ Phase I Percentage...................................13
1.30 HQ Phase I Transfer Credit..............................14
1.31 HQ Phase II Firm Energy Contract........................14
1.32 HQ Phase II Gross Transfer Responsibility...............14
1.33 HQ Phase II Net Transfer Responsibility.................15
1.34 HQ Phase II Percentage..................................15
i
<PAGE>
PAGE
----
1.35 HQ Phase II Transfer Credit.............................15
1.36 HQ Use Agreement........................................15
1.37 Installed Capability....................................16
1.38 Installed Capability Entitlement........................16
1.39 Installed Capability Responsibility.....................16
1.40 Installed System Capability.............................17
1.41 Interchange Transactions................................17
1.42 ISO.....................................................17
1.43 Kilowatt................................................17
1.44 Load....................................................17
1.45 Lower Voltage PTF.......................................19
1.46 Management Committee....................................19
1.47 Market Reliability Planning Committee...................19
1.48 Monthly Peak............................................19
1.49 NEPOOL..................................................20
1.50 NEPOOL Installed Capability Responsibility..............20
1.51 NEPOOL Control Area.....................................20
1.52 NEPOOL Installed Capability.............................21
1.53 NEPOOL Objective Capability.............................21
1.54 New Unit................................................22
1.55 Non-Participant.........................................22
1.56 Operable Capability.....................................22
1.57 Operable Capability Entitlement.........................23
1.58 Operable Capability Requirement ........................23
1.59 Operable System Capability..............................23
1.60 Operating Reserve.......................................24
1.61 Operating Reserve Entitlement...........................24
1.62 Other HQ Energy.........................................24
1.63 Outside Transaction Adjustment..........................25
1.64 Participant.............................................25
1.65 Pool-Planned Facility...................................25
1.66 Pool-Planned Unit.......................................25
1.67 Power Year..............................................25
1.68 Prior NEPOOL Agreement..................................26
1.69 Proxy Unit..............................................26
1.70 PTF.....................................................26
1.71 Regional Market Operations Committee....................26
1.72 Regional Transmission Operations Committee..............26
ii
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1.73 Regional Transmission Planning Committee................27
1.74 Related Person..........................................27
1.75 Scheduled Dispatch Period...............................27
1.76 Second Effective Date...................................28
1.77 Summer Capability.......................................28
1.78 Summer Period...........................................28
1.79 System Contract.........................................28
1.80 System Operator.........................................29
1.81 Target Availability Rate................................29
1.82 Tariff..................................................29
1.83 Third Effective Date....................................29
1.84 Unit Contract...........................................30
1.85 Voting Share............................................30
1.86 Winter Capability.......................................30
1.87 Winter Period...........................................30
1.88 10-Minute Spinning Reserve..............................31
1.89 10-Minute Non-Spinning Reserve..........................32
1.90 30-Minute Operating Reserve.............................33
1.91 33rd Amendment..........................................34
1.92 Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another
Participant Pursuant to Firm Contract...................34
SECTION 2 - PURPOSE; EFFECTIVE DATES......................................37
2.1 Purpose.................................................37
2.2 Effective Dates; Transitional Provisions................37
SECTION 3 - MEMBERSHIP....................................................39
3.1 Membership..............................................39
3.2 Operations Outside the Control Area.....................40
3.3 Lack of Place of Business in New England................41
3.4 Obligation for Deferred Expenses........................41
3.5 Financial Security......................................42
SECTION 4 - STATUS OF PARTICIPANTS........................................43
4.1 Treatment of Certain Entities as Single Participant.....43
4.2 Participants to Retain Separate Identities..............43
SECTION 5 - NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS.............44
iii
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----
5.1 NEPOOL Objectives.......................................44
5.2 Cooperation by Participants.............................45
PART TWO - GOVERNANCE.....................................................47
SECTION 6 - MANAGEMENT COMMITTEE..........................................47
6.1 Membership..............................................47
6.2 Term of Members.........................................48
6.3 Votes...................................................48
6.4 Number of Votes Necessary for Action....................57
6.5 Proxies.................................................58
6.6 Alternates..............................................58
6.7 Officers................................................58
6.8 Meetings................................................58
6.9 Notice of Meetings......................................59
6.10 Adoption of Budgets.....................................59
6.11 Adoption of Bylaws......................................60
6.12 Establishing Reliability Standards......................60
6.13 Appointment and Compensation of NEPOOL Personnel........60
6.14 Duties and Authority....................................61
6.15 Attendance of Members of Management Committee at Other
Committee Meetings......................................66
SECTION 7 - EXECUTIVE COMMITTEE...........................................66
7.1 Organization............................................66
7.2 Membership..............................................67
7.3 Term of Members.........................................69
7.4 Alternates..............................................70
7.5 Votes...................................................70
7.6 Number of Votes Necessary for Action....................71
7.7 Officers................................................71
7.8 Meetings................................................72
7.9 Notice of Meetings......................................72
7.10 Notice to Members of Management Committee of Actions
by Executive Committee..................................73
7.11 Appeal of Actions to Management Committee...............73
SECTION 8 - MARKET RELIABILITY PLANNING COMMITTEE.........................74
iv
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----
8.1 Organization............................................74
8.2 Membership..............................................74
8.3 Term of Members.........................................76
8.4 Voting..................................................77
8.5 Alternates..............................................78
8.6 Officers................................................78
8.7 Meetings................................................79
8.8 Notice of Meetings......................................79
8.9 Notice to Members of Management Committee...............79
8.10 Appeal of Actions to Management Committee...............80
8.11 Responsibilities........................................80
8.12 Functional Planning Committees..........................82
8.13 Appointment of Task Forces..............................84
8.14 Consultants, Computer Time and Expenses.................84
8.15 Further Powers and Duties...............................85
8.16 Reports to Management Committee.........................85
8.17 Joint Meetings With Regional Transmission Planning
Committee...............................................85
SECTION 9 - REGIONAL TRANSMISSION PLANNING COMMITTEE......................86
9.1 Organization............................................86
9.2 Membership..............................................86
9.3 Term of Members.........................................88
9.4 Voting..................................................89
9.5 Alternates..............................................90
9.6 Officers................................................90
9.7 Meetings................................................91
9.8 Notice of Meetings......................................91
9.9 Notice to Members of Management Committee...............92
9.10 Appeal of Actions to Management Committee...............92
9.11 Responsibilities........................................93
9.12 Functional Planning Committees..........................94
9.13 Appointment of Task Forces..............................96
9.14 Consultants, Computer Time and Expenses.................96
9.15 Further Powers and Duties...............................96
9.16 Reports to Management Committee.........................97
9.17 Joint Meetings With Market Reliability Planning
Committee.... ..................................97
SECTION 10 - REGIONAL MARKET OPERATIONS COMMITTEE.........................97
v
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----
10.1 Organization............................................97
10.2 Membership..............................................98
10.3 Terms of Members.......................................100
10.4 Voting.................................................100
10.5 Alternates.............................................102
10.6 Officers...............................................102
10.7 Meetings...............................................102
10.8 Notice of Meetings.....................................103
10.9 Notice to Members of Management Committee..............103
10.10 Appeal of Actions to Management Committee..............104
10.11 Appointment of Task Forces.............................104
10.12 Consultants, Computer Time and Expenses................105
10.13 Responsibilities.......................................105
10.14 Further Powers and Duties..............................108
10.15 Development of Rules Relating to Non-Participant
Supply and Demand-side Resources.......................108
10.16 Joint Meetings with Regional Transmission Operations
Committee..............................................109
SECTION 11 - REGIONAL TRANSMISSION OPERATIONS COMMITTEE..................110
11.1 Organization...........................................110
11.2 Membership.............................................110
11.3 Terms of Members.......................................112
11.4 Voting.................................................113
11.5 Alternates.............................................114
11.6 Officers...............................................114
11.7 Meetings...............................................115
11.8 Notice of Meetings.....................................115
11.9 Notice to Members of Management Committee..............116
11.10 Appeal of Actions to Management Committee..............116
11.11 Appointment of Task Forces.............................117
11.12 Consultants, Computer Time and Expenses................117
11.13 Responsibilities.......................................117
11.14 Further Powers and Duties..............................119
11.15 Joint Meetings with Regional Market Operations
Committee.... ..................................119
PART THREE - MARKET PROVISIONS...........................................120
vi
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PAGE
----
SECTION 12 - INSTALLED CAPABILITY AND OPERABLE CAPABILITY
OBLIGATIONS AND PAYMENTS.........................................120
12.1 Obligations to Provide Installed Capability and
Operable Capability.....................................120
12.2 Computation of Installed Capability Responsibilities....121
12.3 Computation of Operable Capability Requirements.........142
12.4 Bids to Furnish Installed Capability or Operable
Capability..............................................143
12.5 Consequences of Deficiencies in Installed Capability
Responsibility..........................................143
12.6 Consequences of Deficiencies in Operable Capability
Requirements............................................145
12.7 Payments to Participants Furnishing Installed
Capability and Operable Capability......................148
SECTION 13 - OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS......................................150
13.1 Maintenance and Operation in Accordance with Good
Utility Practice........................................150
13.2 Central Dispatch........................................150
13.3 Maintenance and Repair..................................151
13.4 Objectives of Day-to-Day System Operation...............151
13.5 Satellite Membership....................................152
SECTION 14 - INTERCHANGE TRANSACTIONS.....................................153
14.1 Obligation for Energy, Operating Reserve and Automatic
Generation Control......................................153
14.2 Obligation to Bid or Schedule, and Right to Receive
Energy, Operating Reserve and Automatic Generation
Control.................................................156
14.3 Amount of Energy, Operating Reserve and Automatic
Generation Control Received or Furnished................162
14.4 Payments by Participants Receiving Energy Service,
Operating Reserve and Automatic Generation Control......164
14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control.....166
14.6 Energy Transactions with Non-Participants...............168
14.7 Participant Purchases Pursuant to Firm Contracts and
System Contracts........................................170
14.8 Determination of Energy Clearing Price..................172
14.9 Determination of Operating Reserve Selling Price and
Clearing Price..........................................173
14.10 Determination of AGC Clearing Price.....................176
14.11 Funds to or from which Payments are to be Made..........177
14.12 Development of Rules Relating to Nuclear and
Hydroelectric Generating Facilities, Limited-Fuel
Generating Facilities, and Interruptible Loads..........185
vii
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PAGE
----
14.13 Dispatch and Billing Rules During Energy Shortages......185
14.14 Congestion Uplift.......................................186
14.15 Additional Uplift Charges. ............................192
PART FOUR - TRANSMISSION PROVISIONS.......................................193
SECTION 15 - OPERATION OF TRANSMISSION FACILITIES.........................193
15.1 Definition of PTF.......................................193
15.2 Maintenance and Operation in Accordance with Good
Utility Practice........................................196
15.3 Central Dispatch........................................197
15.4 Maintenance and Repair..................................197
15.5 Additions to or Upgrades of PTF.........................198
SECTION 16 - SERVICE UNDER TARIFF.........................................201
16.1 Effect of Tariff........................................201
16.2 Obligation to Provide Regional Service..................201
16.3 Obligation to Provide Local Network Service.............202
16.4 Transmission Service Availability.......................205
16.5 Transmission Information................................205
16.6 Distribution of Transmission Revenues...................206
16.7 Changes to Tariff.......................................210
SECTION 17 - POOL-PLANNED UNIT SERVICE....................................211
17.1 Effective Period........................................211
17.2 Obligation to Provide Service...........................212
17.3 Rules for Determination of Facilities Covered by
Particular Transactions.................................213
17.4 Payments for Uses of EHV PTF During the Transition
Period..................................................214
17.5 Payments for Uses of Lower Voltage PTF..................218
17.6 Use of Other Transmission Facilities by Participants....219
17.7 Limits on Individual Transmission Charges...............219
PART FIVE - GENERAL.......................................................220
SECTION 18 - GENERATION AND TRANSMISSION FACILITIES.......................220
18.1 Designation of Pool-Planned Facilities..................220
18.2 Construction of Facilities..............................221
18.3 Protective Devices for Transmission Facilities and
Automatic Generation Control Equipment..................221
viii
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18.4 Review of Participant's Proposed Plans..................222
18.5 Participant to Avoid Adverse Effect.....................223
SECTION 19 - EXPENSES.....................................................224
19.1 Annual Fee..............................................224
19.2 NEPOOL Expenses.........................................225
SECTION 20 - INDEPENDENT SYSTEM OPERATOR..................................226
SECTION 21 - MISCELLANEOUS PROVISIONS.....................................231
21.1 Alternative Dispute Resolution..........................231
21.2 Payment of Pool Charges; Termination of Status as
Participant.............................................243
21.3 Assignment..............................................247
21.4 Force Majeure...........................................248
21.5 Waiver of Defaults......................................248
21.6 Other Contracts.........................................249
21.7 Liability and Insurance.................................249
21.8 Records and Information.................................251
21.9 Consistency with NPCC and NERC Standards................251
21.10 Construction............................................251
21.11 Amendment...............................................252
21.12 Termination.............................................254
21.13 Notices to Participants.................................254
21.14 Severability and Renegotiation..........................256
21.15 No Third-Party Beneficiaries............................256
21.16 Counterparts............................................257
||
ix
<PAGE>
RESTATED NEPOOL POWER POOL AGREEMENT
THIS AGREEMENT dated as of the first day of September, 1971, as amended, was
entered into by the signatories thereto for the establishment by them of a bulk
power pool to be known as NEPOOL and is restated by an amendment dated as of
December 1, 1996.
In consideration of the mutual agreements and undertakings herein, the
signatories hereby agree as follows:
PART ONE
INTRODUCTION
SECTION 1
DEFINITIONS
-----------
Whenever used in this Agreement, in either the singular or plural number, the
following terms shall have the following respective meanings (an asterisk (*)
indicates that the definition may be modified in certain cases pursuant to
Section 1.94):
1.1 Adjusted Load * (not less than zero) of a Participant during any
--------------
particular hour is the Participant's Load during such hour less any
Kilowatts received (or Kilowatts which
<PAGE>
-2-
would have been received except for the application of Section 14.7(b))
by such Participant pursuant to a Firm Contract.
1.2 Adjusted Monthly Peak of a Participant for a month is its Monthly Peak,
---------------------
provided that if there has been a transfer between participants, in
whole or part, of the responsibilities under this Agreement during such
month pursuant to a Firm Contract, the Adjusted Monthly Peak of each
such Participant shall reflect the effect of such transaction, but the
Adjusted Monthly Peak of a Participant shall not be changed from the
Monthly Peak to reflect the effect of any other transaction.
1.3 Adjusted Net Interchange of a Participant for an hour is (a) the
--------------------------
Kilowatts produced by or delivered to the Participant from its Energy
Entitlements or pursuant to arrangements entered into under Section
14.6, as adjusted in accordance with uniform market operation rules
approved by the Regional Market Operations Committee to take account of
associated electrical losses, as appropriate, minus (b) the sum of (i)
-----
the Electrical Load of the Participant for the hour, and (ii) the
kilowatthours delivered by such Participant to other Participants
pursuant to Firm Contracts or System Contracts, in accordance with the
treatment agreed to pursuant to Section 14.7(a), together with any
associated electrical losses.
<PAGE>
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1.4 AGC Capability of an electric generating unit or combination of units
--------------
is the maximum dependable ability of the unit or units to increase or
decrease the level of output within a time frame specified by market
operation rules approved by the Regional Market Operations Committee,
in response to a remote direction from the System Operator in order to
maintain currently proper power flows into and out of the NEPOOL
Control Area and to control frequency.
1.5 AGC Entitlement is (a) the right to all or a portion of the AGC
----------------
Capability of a generating unit or combination of units to which an
Entity is entitled as an owner (either sole or in common) or as a
purchaser, reduced by (b) any portion thereof which such Entity is
----------
selling pursuant to a Unit Contract, and (c) further reduced or
-----------
increased, as appropriate, to recognize rights to receive or
---------
obligations to supply AGC pursuant to Firm Contracts or System
Contracts in accordance with Section 14.7(a). An AGC Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, Operable Capability Entitlement, Energy Entitlement, or
Operating Reserve Entitlements.
<PAGE>
-4-
1.6 Agreement is this restated contract and attachments, including the
---------
Tariff, as amended and restated from time to time.
1.7 Automatic Generation Control or AGC is a measure of the ability of a
-------------------------------------
generating unit or portion thereof to respond automatically within a
specified time to a remote direction from the System Operator to
increase or decrease the level of output in order to control frequency
and to maintain currently proper power flows into and out of the NEPOOL
Control Area.
1.8 Bid Price is the amount which a Participant offers to accept, in a
---------
notice furnished to the System Operator by it or on its behalf in
accordance with the market operation rules approved by the Regional
Market Operations Committee, as compensation for (i) furnishing
Installed Capability or Operable Capability to other Participants
pursuant to this Agreement, or (ii) preparing the start up or starting
up or increasing the level of operation of, and thereafter operating, a
generating unit or units to provide Energy to other Participants
pursuant to this Agreement, or (iii) having a unit or units available
to provide Operating Reserve to other Participants pursuant to this
Agreement, or (iv) having a unit or units available to provide AGC to
other Participants pursuant to this Agreement, or (v) providing to
other Participants Installed Capability, Operable
<PAGE>
-5-
Capability, Energy, Operating Reserve and/or AGC pursuant to a Firm
Contract or System Contract in accordance with Section 14.7.
1.9 Commission is the Federal Energy Regulatory Commission or any
----------
regulatory agency succeeding to substantially all of the authority of
the Federal Energy Regulatory Commission with respect to electric
service.
1.10 Dispatch Price of a generating unit or combination of units, or a Firm
--------------
Contract or System Contract permitted to be bid to supply Energy in
accordance with Section 14.7(b), is the price to provide Energy from
the unit or units or Contract, as determined pursuant to market
operation rules approved by the Regional Market Operations Committee to
incorporate the Bid Price for such Energy and any loss adjustments, if
and as appropriate under such market operation rules.
1.11 EHV PTF are PTF transmission lines which are operated at 230 kV or
-------
above and related PTF facilities, including transformers which link
other EHV PTF facilities, but do not include transformers which step
down from 230 kV or a higher voltage to a voltage below 230 kV.
<PAGE>
-6-
1.12 Electrical Load (in Kilowatts) of a Participant during any particular
----------------
hour is the total during such hour (eliminating any distortion arising
out of (i) Interchange Transactions, or (ii) transactions across the
system of such Participant, (iii) deliveries between Entities
constituting a single Participant, or (iv) other electrical losses, if
and as appropriate), of
(a) kilowatthours provided by such Participant to its
retail customers for consumption, plus
----
(b) kilowatthours of use by such Participant, plus
----
(c) kilowatthours of electrical losses and unaccounted
for use by the Participant on its system, plus
----
(d) kilowatthours used by such Participant for pumping
Energy for its Entitlements in pumped storage
hydroelectric generating facilities, plus
----
(e) kilowatthours delivered by such Participant
to Non-Participants.
<PAGE>
-7-
The Electrical Load of a Participant may be calculated in any
reasonable manner which substantially complies with this definition.
1.13 Energy is power produced in the form of electricity, measured in
------
kilowatthours or megawatthours.
1.14 Energy Entitlement is (i) a right to receive Energy under a System
Contract or a Firm Contract in accordance with Section 14.7(a), or
(ii) a right to receive all or a portion of the electric output of a
generating unit or units to which an Entity is entitled as an owner
(either sole or in common) or as a purchaser pursuant to a Unit
Contract, reduced by (iii) any portion thereof which such Entity is
----------
selling pursuant to a Unit Contract. An Energy Entitlement in a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the related Installed Capability
Entitlement, Operable Capability Entitlement, Operating Reserve
Entitlements, or AGC Entitlement.
1.15 Entitlement is an Installed Capability Entitlement, Operable
-----------
Capability Entitlement, Energy Entitlement, Operating Reserve
Entitlement, or AGC Entitlement. When used
<PAGE>
-8-
in the plural form, it may be any or all such Entitlements or
combinations thereof, as the context requires.
1.16 Entity is any person or organization whether the United States of
------
America or Canada or a state or province or a political subdivision
thereof or a duly established agency of any of them, a private
corporation, a partnership, an individual, an electric cooperative or
any other person or organization recognized in law as capable of owning
property and contracting with respect thereto that is either:
(a) engaged in the electric power business (the
generation and/or transmission and/or distribution of
electricity for consumption by the public or the
purchase, as a principal or broker, of Installed
Capability, Operable Capability, Energy, Operating
Reserve, and/or AGC for resale); or
(b) an end user of electricity that is taking or eligible
to take unbundled transmission service pursuant to an
effective state requirement that the Participant that
is the Transmission Provider with which that end user
is directly interconnected offer the
<PAGE>
-9-
transmission service, or pursuant to a voluntary
offer of unbundled transmission service to that end
user by the Participant that is the Transmission
Provider with which that end user is directly
interconnected.
1.17 Executive Committee is the committee established pursuant to Section 7.
-------------------
1.18 Firm Contract is any contract, other than a Unit Contract, for the
--------------
purchase of Installed Capability, Operable Capability, Energy,
Operating Reserves, and/or AGC, pursuant to which the purchaser's right
to receive such Installed Capability, Operable Capability, Energy,
Operating Reserves, and/or AGC is subject only to the supplier's
inability to make deliveries thereunder as the result of events beyond
the supplier's reasonable control.
1.19 First Effective Date is March 1, 1997 or such other date as the
----------------------
Commission may fix as the date on which the provisions of Parts One,
Two, Four and Five of this Agreement and the Tariff will become
effective.
<PAGE>
-10-
1.20 Good Utility Practice shall mean any of the practices, methods, and
----------------------
acts engaged in or approved by a significant portion of the electric
utility industry during the relevant time period, or any of the
practices, methods, and acts which, in the exercise of reasonable
judgement in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices, reliability,
safety and expedition. Good Utility Practice is not limited to a
single, optimum practice, method or act to the exclusion of others, but
rather is intended to include acceptable practices, methods, or acts
generally accepted in the region.
1.21 HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I
-------------
Energy Contract, and the HQ Phase II Firm Energy Contract.
1.22 HQ Energy Banking Agreement is the Energy Banking Agreement entered
-----------------------------
into on March 21, 1983 by Hydro-Quebec, the Participants, New England
Electric Transmission Corporation and Vermont Electric Transmission
Company, Inc., as it may be amended from time to time.
<PAGE>
-11-
1.23 HQ Interconnection is the United States segment of the
-------------------
transmission interconnection which connects the systems of
Hydro-Quebec and the Participants. "Phase I" is the United States
portion of the 450 kV HVDC transmission line from a terminal at the
Des Cantons Substation on the Hydro-Quebec system near Sherbrooke,
Quebec to a terminal having an approximate rating of 690 MW at a
substation at the Comerford Generating Station on the Connecticut
River. "Phase II" is the United States portion of the facilities
required to increase to approximately 2000 MW the transfer capacity of
the HQ Interconnection, including an extension of the HVDC
transmission line from the terminus of Phase I at the Comerford
Station through New Hampshire to a terminal at the Sandy Pond
Substation in Massachusetts. The HQ Interconnection does not include
any PTF facilities installed or modified to effect reinforcements of
the New England AC transmission system required in connection with the
HVDC transmission line and terminals.
1.24 HQ Interconnection Agreement is the Interconnection Agreement entered
-----------------------------
into on March 21, 1983 by Hydro-Quebec and the Participants, as it may
be amended from time to time.
<PAGE>
-12-
1.25 HQ Interconnection Capability Credit of a Participant for a month
------------------------------------
during the Base Term (as defined in Section 1.33) of the HQ Phase II
Firm Energy Contract is the sum in Kilowatts of (1)(a) the
Participant's percentage share, if any, of the HQ Phase I Transfer
Capability times (b) the HQ Phase I Transfer Credit, plus (2)(a) the
-----
Participant's percentage share, if any, of the Phase II Transfer
Capability, times (b) the HQ Phase II Transfer Credit. The Management
-----
Committee shall establish appropriate HQ Interconnection Capability
Credits to apply for a Participant which has such a percentage share
(i) during an extension of the HQ Phase II Firm Energy Contract, and
(ii) following the expiration of the HQ Phase II Firm Energy Contract.
1.26 HQ Interconnection Transfer Capability is the transfer capacity of the
---------------------------------------
HQ Interconnection under normal operating conditions, as determined in
accordance with Good Utility Practice. The "HQ Phase I Transfer
Capability" is the transfer capacity under normal operating conditions,
as determined in accordance with Good Utility Practice, of the Phase I
terminal facilities as determined initially as of the time immediately
prior to Phase II of the Interconnection first being placed in service,
and as adjusted thereafter only to take into account changes in the
transfer capacity which are independent of any effect of Phase II on
the operation of Phase I. The "HQ Phase II Transfer Capability" is the
difference between the HQ Interconnection Transfer
<PAGE>
-13-
Capability and the HQ Phase I Transfer Capability. Determinations of,
and any adjustment in, transfer capacity shall be made by the Regional
Market Operations Committee in accordance with a schedule consistent
with that followed by it in its determination of the Winter Capability
and Summer Capability of generating units.
1.27 HQ Net Interconnection Capability Credit of a Participant at a
--------------------------------------------
particular time is its HQ Interconnection Capability Credit at the time
in Kilowatts, minus a number of Kilowatts equal to (1) the percentage
----- -----
of its share of the HQ Interconnection Transfer Capability committed or
used by it for an "Entitlement Transaction" at the time under the HQ
Use Agreement, times (2) its HQ Interconnection Capability Credit for
-----
the current month.
1.28 HQ Phase I Energy Contract is the Energy Contract entered into on March
--------------------------
21, 1983 by Hydro-Quebec and the Participants, as it may be amended
from time to time.
1.29 HQ Phase I Percentage is the percentage of the total HQ Interconnection
Transfer Capability represented by the HQ Phase I Transfer Capability.
<PAGE>
-14-
1.30 HQ Phase I Transfer Credit is 60/69 of the HQ Phase I Transfer
-----------------------------
Capability, or such other fraction of the HQ Phase I Transfer
Capability as the Management Committee may establish.
1.31 HQ Phase II Firm Energy Contract is the Firm Energy Contract dated as
---------------------------------
of October 14, 1985 between Hydro-Quebec and certain of the
Participants, as it may be amended from time to time. The "Base Term"
of the HQ Phase II Firm Energy Contract is the period commencing on the
date deliveries were first made under the Contract and ending on August
31, 2000.
1.32 HQ Phase II Gross Transfer Responsibility of a Participant for any
-------------------------------------------
month during the Base Term of the HQ Phase II Firm Energy Contract (as
defined in Section 1.33) is the number in Kilowatts of (a) the
Participant's percentage share, if any, of the HQ Phase II Transfer
Capability for the month times (b) the HQ Phase II Transfer Credit.
-----
Following the Base Term of the HQ Phase II Firm Energy Contract, and
again following the expiration of the HQ Phase II Firm Energy Contract,
the Management Committee shall establish an appropriate HQ Phase II
Gross Transfer Responsibility that shall remain in effect concurrently
with the HQ Interconnection Capability Credit.
<PAGE>
-15-
1.33 HQ Phase II Net Transfer Responsibility of a Participant for any month
----------------------------------------
is its HQ Phase II Gross Transfer Responsibility for the month minus a
number of Kilowatts equal to (1) the highest percentage of its share of
` --------
the HQ Interconnection Transfer Capability committed or used by it on
any day of the month for an "Entitlement Transaction" under the HQ Use
Agreement, times (2) its HQ Phase II Gross Transfer Responsibility for
-----
the month.
1.34 HQ Phase II Percentage is the percentage of the total HQ
--------------------------
Interconnection Transfer Capability represented by the HQ Phase II
Transfer Capability.
1.35 HQ Phase II Transfer Credit is 90/131 of the HQ Phase II Transfer
-----------------------------
Capability, or such other fraction of the HQ Phase II Transfer
Capability as the Management Committee may establish.
1.36 HQ Use Agreement is the Agreement with Respect to Use of Quebec
-----------------
Interconnection dated as of December 1, 1981 among certain of the
Participants, as amended and restated as of September 1, 1985 and as it
may be further amended from time to time.
<PAGE>
-16-
1.37 Installed Capability of an electric generating unit or combination of
---------------------
units during the Winter Period is the Winter Capability of such unit or
units and during the Summer Period is the Summer Capability of such
unit or units.
1.38 Installed Capability Entitlement is (a) the right to all or a portion
----------------------------------
of the Installed Capability of a generating unit or units to which an
Entity is entitled as an owner (either sole or in common) or as a
purchaser pursuant to a Unit Contract, (b) reduced by any portion
----------
thereof which such Entity is selling pursuant to a Unit Contract, and
(c) further reduced or increased, as appropriate, to recognize rights
--------------------
to receive or obligations to supply Installed Capability pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Installed Capability Entitlement relating to a unit or units may,
but need not, be combined with any other Entitlements relating to such
generating unit or units and may be transferred separately from the
related Operable Capability Entitlement, Energy Entitlement, Operating
Reserve Entitlements, or AGC Entitlement.
1.39 Installed Capability Responsibility * of a Participant for any month is
-----------------------------------
the number of Kilowatts determined in accordance with Section 12.2.
<PAGE>
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1.40 Installed System Capability of a Participant at a particular time is
-----------------------------
(1) the sum of such Participant's Installed Capability Entitlements
plus (2) its HQ Net Interconnection Capability Credit at the time.
----
1.41 Interchange Transactions are transactions deemed to be effected under
-------------------------
Section 12 of the Prior NEPOOL Agreement prior to the Second Effective
Date, and transactions deemed to be effected under Section 14 of this
Agreement on and after the Second Effective Date.
1.42 ISO is the Independent System Operator which is expected to assume
---
responsibility for the continued operation of the NEPOOL Control Area
from the NEPOOL control center and the administration of the Tariff,
subject to regulation by the Commission.
1.43 Kilowatt is a kilowatthour per hour.
--------
1.44 Load * (in Kilowatts) of a Participant during any particular hour is
----
the total during such hour (eliminating any distortion arising out of
(i) Interchange Transactions, or (ii) transactions across the system of
such Participant, or (iii) deliveries between Entities constituting a
single Participant, or (iv) other electrical losses, if and as
appropriate) of
<PAGE>
-18-
(a) kilowatthours provided by such Participant to its
retail customers for consumption (excluding any
kilowatthours which may be classified as
interruptible under market operation rules approved
by the Regional Market Operations Committee), plus
----
(b) kilowatthours delivered by such Participant pursuant
to Firm Contracts to its wholesale customers for
resale, plus
----
(c) kilowatthours of use by such Participant, exclusive
of use by such Participant for the operation and
maintenance of its generating unit or units, plus
----
(d) kilowatthours of electrical losses and unaccounted
for use by the Participant on its system.
The Load of a Participant may be calculated in any reasonable manner
which substantially complies with this definition.
<PAGE>
-19-
For the purposes of calculating a Participant's Annual Peak, Adjusted
Monthly Peak, Adjusted Annual Peak and Monthly Peak, the Load of a
Participant shall be adjusted to eliminate any distortions resulting
from voltage reductions. In addition, upon the request of any
Participant, the Regional Market Operations Committee shall make, or
supervise the making of, appropriate adjustments in the computation of
Load for the purposes of calculating any Participant's Annual Peak,
Adjusted Monthly Peak, Adjusted Annual Peak and Monthly Peak to
eliminate any distortions resulting from emergency load curtailments
which would significantly affect the Load of any Participant.
1.45 Lower Voltage PTF are all PTF facilities other than EHV PTF.
-----------------
1.46 Management Committee is the committee established pursuant to Section
--------------------
6.
1.47 Market Reliability Planning Committee is the committee established
----------------------------------------
pursuant to Section 8.
1.48 Monthly Peak of a Participant for a month is the maximum Adjusted Load
------------
of the Participant during any hour in the month.
<PAGE>
-20-
1.49 NEPOOL is the New England Power Pool, the power pool created under and
------
governed by this Agreement, and the Entities collectively participating
in the New England Power Pool as Participants.
1.50 NEPOOL Installed Capability Responsibility for any month is the sum of
-------------------------------------------
the Installed Capability Responsibilities of all Participants during
that month.
1.51 NEPOOL Control Area is the integrated electric power system to which a
-------------------
common Automatic Generation Control scheme and various operating
procedures are applied by or under the supervision of the System
Operator in order to:
(i) match, at all times, the power output of the
generators within the electric power system and
capacity and Energy purchased from entities outside
the electric power system, with the load within the
electric power system;
(ii) maintain scheduled interchange with other
interconnected systems, within the limits of Good
Utility Practice;
<PAGE>
-21-
(iii) maintain the frequency of the electric power system
within reasonable limits in accordance with Good
Utility Practice and the criteria of the Northeast
Power Coordinating Council and the North American
Electric Reliability Council; and
(iv) provide sufficient generating capacity to maintain
operating reserves in accordance with Good Utility
Practice.
1.52 NEPOOL Installed Capability at any particular time is the sum of the
-----------------------------
Installed System Capabilities of all Participants at such time.
1.53 NEPOOL Objective Capability for any year or period during a year is the
---------------------------
minimum NEPOOL Installed Capability, treating the reliability benefits
of the HQ Interconnection as Installed Capability, as established by
the Management Committee, required to be provided by the Participants
in aggregate for the period to meet the reliability standards
established by the Management Committee pursuant to Section 6.12.
<PAGE>
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1.54 New Unit is an electric generating unit (including a unit or units
--------
owned by a Non-Participant in which a Participant has an Entitlement
under a Unit Contract) first placed into commercial operation after May
1, 1987 (or, in the case of a unit or units owned by a Non-Participant,
in which a Participant's Unit Contract Entitlement became effective
after May 1, 1987) and not listed on Exhibit B to the Prior NEPOOL
Agreement.
1.55 Non-Participant is any entity which is not a Participant.
---------------
1.56 Operable Capability of an electric generating unit or units in any hour
-------------------
is the portion of the Installed Capability of the unit or units which
is operating or available to respond within an appropriate period (as
identified in market operation rules approved by the Regional Market
Operations Committee) to the System Operator's call to meet the Energy
and/or Operating Reserve and/or AGC requirements of the NEPOOL Control
Area during a Scheduled Dispatch Period or is available to respond
within an appropriate period to a schedule submitted by a Participant
for the hour in accordance with market operation rules approved by the
Regional Market Operations Committee.
<PAGE>
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1.57 Operable Capability Entitlement is (a) the right to all or a portion of
-------------------------------
the Operable Capability of a generating unit or units to which an
Entity is entitled as an owner (either sole or in common) or as a
purchaser pursuant to a Unit Contract, (b) reduced by any portion
----------
thereof which such Entity is selling pursuant to a Unit Contract, and
(c) further reduced or increased, as appropriate, to recognize rights
--------------------
to receive or obligations to supply Operable Capability pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Operable Capability Entitlement relating to a unit or units may, but
need not, be combined with any other Entitlements relating to such
generating unit or units, and may be transferred separately from the
related Installed Capability Entitlement, Energy Entitlement, Operating
Reserve Entitlements, or AGC Entitlement.
1.58 Operable Capability Requirement of a Participant for any hour is the
---------------------------------
number of Kilowatts determined in accordance with Section 12.3.
1.59 Operable System Capability of a Participant in any hour is the sum of
----------------------------
such Participant's Operable Capability Entitlements.
<PAGE>
-24-
1.60 Operating Reserve is any or a combination of 10-Minute Spinning
------------------
Reserve, 10-Minute Non-Spinning Reserve, and 30-Minute Operating
Reserve, as the context requires.
1.61 Operating Reserve Entitlement is (a) the right to all or a portion of
-------------------------------
the Operating Reserve of any category which can be provided by a
generating unit or units to which an Entity is entitled as an owner
(either sole or in common) or as a purchaser pursuant to a Unit
Contract, (b) reduced by any portion thereof which such Entity is
----------
selling pursuant to a Unit Contract, and (c) further reduced or
-----------
increased, as appropriate, to recognize rights to receive or
---------
obligations to supply Operating Reserve of that category pursuant to
Firm Contracts or System Contracts in accordance with Section 14.7(a).
An Operating Reserve Entitlement in any category relating to a
generating unit or units may, but need not, be combined with any other
Entitlements relating to such generating unit or units and may be
transferred separately from the other categories of Operating Reserve
Entitlements related to such unit or units and from the related
Installed Capability Entitlement, Operable Capability Entitlement,
Energy Entitlement, or AGC Entitlement.
1.62 Other HQ Energy is Energy purchased under the HQ Phase I Energy
-----------------
Contract which is classified as "Other Energy" under that contract.
<PAGE>
-25-
1.63 Outside Transaction Adjustment of a Participant for any month is the
--------------------------------
number of Kilowatts determined in accordance with Section 12.2(a)(3).
1.64 Participant is an eligible Entity (or group of Entities which has
-----------
elected to be treated as a single Participant pursuant to Section 4.1)
which is a signatory to this Agreement and has become a Participant in
accordance with Section 3.1 until such time as such Entity's status as
a Participant terminates pursuant to Section 21.2.
1.65 Pool-Planned Facility is a generation or transmission facility
-----------------------
designated as "pool-planned" pursuant to Section 18.1.
1.66 Pool-Planned Unit is one of the following units: New Haven Harbor Unit
------------------
1 (Coke Works), Mystic Unit 7, Canal Unit 2, Potter Unit 2, Wyman Unit
4, Stony Brook Units 1, 1A, 1B, 1C, 2A and 2B, Millstone Unit 3,
Seabrook Unit 1 and Waters River Unit 2 (to the extent of 7 megawatts
of its Summer Capability and 12 megawatts of its Winter Capability).
1.67 Power Year is the period of twelve months commencing on November 1.
----------
<PAGE>
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1.68 Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December
----------------------
1, 1996.
1.69 Proxy Unit is a hypothetical electric generating unit which possesses a
----------
Winter Capability, equivalent forced outage rate, annual maintenance
outage requirement, and seasonal derating determined in accordance with
Section 12.2(a)(2).
1.70 PTF are the pool transmission facilities defined in Section 15.1, and
---
any other new transmission facilities which the Regional Transmission
Planning Committee determines, in accordance with criteria approved by
the Management Committee and subject to review by the System Operator,
should be included in PTF.
1.71 Regional Market Operations Committee is the committee established
---------------------------------------
pursuant to Section 10.
1.72 Regional Transmission Operations Committee is the committee established
------------------------------------------
pursuant to Section 11.
<PAGE>
-27-
1.73 Regional Transmission Planning Committee is the committee established
------------------------------------------
pursuant to Section 9.
1.74 Related Person of a Participant is either (i) a corporation,
----------------
partnership, business trust or other business organization 10% or more
of the stock or equity interest in which is owned directly or
indirectly by, or is under common control with, the Participant, or
(ii) a corporation, partnership, business trust or other business
organization which owns directly or indirectly 10% or more of the stock
or other equity interest in the Participant, or (iii) a corporation,
partnership, business trust or other business organization 10% or more
of the stock or other equity interest in which is owned directly or
indirectly by a corporation, partnership, business trust or other
business organization which also owns 10% or more of the stock or other
equity interest in the Participant.
1.75 Scheduled Dispatch Period is the shortest period for which the System
---------------------------
Operator performs and publishes a projected dispatch schedule based on
projected Electrical Loads and actual Bid Prices and
Participant-directed schedules for resources submitted in accordance
with Section 14.2(d).
<PAGE>
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1.76 Second Effective Date is the date on which the provisions of Part Three
---------------------
of the Agreement (other than the Installed Capability Responsibility
provisions of Section 12) shall become effective and shall be April 1,
1998 or such other date on or before June 30, 1998 as the Management
Committee may fix, or such other date as the Commission may fix on its
own or pursuant to a request of the Management Committee.
1.77 Summer Capability of an electric generating unit or combination of
------------------
units is the maximum dependable load carrying ability in Kilowatts of
such unit or units (exclusive of capacity required for station use)
during the Summer Period, as determined by the Regional Market
Operations Committee in accordance with Section 10.13(f).
1.78 Summer Period in each Power Year is the four-month period from June
--------------
through September.
1.79 System Contract is any contract for the purchase of Installed
-----------------
Capability, Operable Capability, Energy, Operating Reserves and/or AGC,
other than a Unit Contract or Firm Contract, pursuant to which the
purchaser is entitled to a specifically determined or determinable
amount of such Installed Capability, Operable Capability, Energy,
Operating Reserves and/or AGC.
<PAGE>
-29-
1.80 System Operator is the central dispatching agency provided for in this
---------------
Agreement which has responsibility for the operation of the NEPOOL
Control Area from the NEPOOL control center and the administration of
the Tariff. The System Operator shall be the ISO after it has been
activated and is prepared to assume responsibility for the operation of
the NEPOOL Control Area and control center.
1.81 Target Availability Rate is the assumed availability of a type of
--------------------------
generating unit utilized by the Management Committee in its
determination pursuant to Section 6.14(e) of NEPOOL Objective
Capability.
1.82 Tariff is the NEPOOL Open Access Transmission Tariff set out in
------
Attachment B to the Agreement, as modified and amended from time to
time.
1.83 Third Effective Date is the date on which all Interchange Transactions
--------------------
shall begin to be effected on the basis of separate Bid Prices for each
type of Entitlement. The Third Effective Date shall be fixed at the
discretion of the Management Committee to occur within six months to
one year after the Second Effective Date, or at such later date as
<PAGE>
-30-
the Commission may fix on its own or pursuant to a request by the
Management Committee.
1.84 Unit Contract is a purchase contract pursuant to which the purchaser is
-------------
in effect currently entitled either (i) to a specifically determined or
determinable portion of the Installed Capability of a specific electric
generating unit or units, or (ii) to a specifically determined or
determinable amount of Operable Capability, Energy, Operating Reserves
and/or AGC if, or to the extent that, a specific electric generating
unit or units is or can be operated.
1.85 Voting Share has the meaning specified in Section 6.3.
------------
1.86 Winter Capability of an electric generating unit or combination of
------------------
units is the maximum dependable load carrying ability in Kilowatts of
such unit or units (exclusive of capacity required for station use)
during the Winter Period, as determined by the Regional Market
Operations Committee in accordance with Section 10.13(f).
1.87 Winter Period in each Power Year is the seven-month period from
--------------
November through May and the month of October.
<PAGE>
-31-
1.88 10-Minute Spinning Reserve in an hour are the following resources that
--------------------------
are designated by the System Operator in accordance with market
operation rules, as approved by the Regional Market Operations
Committee, to be available to provide contingency protection for the
system: (1) the Kilowatts of Operable Capability of an electric
generating unit or units that are synchronized to the system, unloaded
during all or part of the hour, and capable of providing contingency
protection by loading to supply Energy immediately on demand,
increasing the Energy output over no more than ten minutes to the full
amount of generating capacity so designated, and sustaining such Energy
output for so long as the System Operator determines in accordance with
market operation rules approved by the Regional Market Operations
Committee is necessary; and (2) any portion of the Electrical Load of a
Participant that the System Operator is able to verify as capable of
providing contingency protection by immediately on demand reducing
Energy requirements within ten minutes and maintaining such reduced
Energy requirements for so long as the System Operator determines in
accordance with market operation rules approved by the Regional Market
Operations Committee is necessary.
<PAGE>
-32-
1.89 10-Minute Non-Spinning Reserve in an hour are the following resources
--------------------------------
that are designated by the System Operator in accordance with market
operation rules, as approved by the Regional Market Operations
Committee, to be available to provide contingency protection for the
system: (1) the Kilowatts of Operable Capability of an electric
generating unit or units that are not synchronized to the system,
during all or part of the hour, and capable of providing contingency
protection by loading to supply Energy within ten minutes to the full
amount of generating capacity so designated, and sustaining such Energy
output for so long as the System Operator determines in accordance with
market operation rules approved by the Regional Market Operations
Committee is necessary; (2) any portion of a Participant's Electrical
Load that the System Operator is able to verify as capable of providing
contingency protection by reducing Energy requirements within ten
minutes and maintaining such reduced Energy requirements for so long as
the System Operator determines in accordance with market operations
rules approved by the Regional Market Operations Committee is
necessary; and (3) any other resources and requirements that were able
to be designated for the hour as 10-Minute Spinning Reserve but were
not designated by the System Operator for such purpose in the hour.
<PAGE>
-33-
1.90 30-Minute Operating Reserve in an hour are the following resources that
---------------------------
are designated by the System Operator in accordance with market
operation rules, as approved by the Regional Market Operations
Committee, to be available to provide contingency protection for the
system: (1) the Kilowatts of Operable Capability of an electric
generating unit or units that are capable of providing contingency
protection by loading to supply Energy within thirty minutes of demand
at an output equal to its full amount of generating capacity so
designated and sustaining such Energy output for so long as the System
Operator determines in accordance with market operation rules approved
by the Regional Market Operations Committee is necessary; (2) any
portion of the Electrical Load of a Participant that the System
Operator is able to verify as capable of providing contingency
protection by reducing Energy requirements within thirty minutes and
maintaining such reduced Energy requirements for so long as the System
Operator determines in accordance with market operation rules approved
by the Regional Market Operations Committee is necessary; and (3) any
other resources and requirements that were able to be designated for
the hour as 10-Minute Spinning Reserve or 10-Minute Non-Spinning
Reserve but were not designated by the System Operator for such
purposes in the hour.
<PAGE>
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1.91 33rd Amendment is the Thirty-Third Agreement Amending New England Power
--------------
Pool Agreement dated as of December 1, 1996.
1.92 Modification of Certain Definitions When a Participant Purchases a
----------------------------------------------------------------------
Portion of Its Requirements from Another Participant Pursuant to Firm
----------------------------------------------------------------------
Contract
--------
Definitions marked by an asterisk (*) are modified as follows
when a Participant purchases a portion of its requirements of
electricity from another Participant pursuant to a Firm
Contract:
(a) If the Firm Contract limits deliveries to a
specifically stated number of Kilowatts and requires
payment of a demand charge thereon (thus placing the
responsibility for meeting additional demands on the
purchasing Participant):
(1) in computing the Adjusted Load of the
--------------
purchasing Participant, the Kilowatts
received pursuant to such Firm Contract
shall be deemed to be the number of
Kilowatts specified in the Firm Contract;
and
<PAGE>
-35-
(2) in computing the Load of the supplying
----
Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be
deemed to be the number of Kilowatts
specified in the Firm Contract.
(b) If the Firm Contract does not limit deliveries to a
specifically stated number of Kilowatts, but entitles
the Participant to receive such amounts of
electricity as it may require to supply its electric
needs (thus placing the responsibility for meeting
additional demands on the supplying Participant):
(1) the Installed Capability Responsibility of
-----------------------------------
the purchasing Participant shall be equal to
-----
the amount of its Installed Capability
Entitlements;
(2) in computing the Adjusted Load of the
--------------
purchasing Participant, the Kilowatts
received pursuant to such Firm Contract
shall be deemed to be a quantity Rl; and
<PAGE>
-36-
(3) in computing the Load of the supplying
----
Participant, the Kilowatts delivered
pursuant to such Firm Contract shall be
deemed to be a quantity Rl.
The quantity Rl equals (i) the Load of the purchasing
Participant less (ii) the amount of the purchasing
Participant's Installed Capability Entitlements
multiplied by a fraction X OVER Y wherein:
X is the maximum Load of the
purchasing Participant in the month,
and
Y is the NEPOOL Installed Capability
Responsibility multiplied by the
purchasing Participant's fraction P
determined pursuant to Section
12.2(a)(1), computed as if the Firm
Contract did not exist.
Terms used in this Agreement which are not defined above but which are
defined in the Tariff shall have the meanings specified in the Tariff.
Terms used in this Agreement that are not defined above, or in the
Tariff, or in the sections in which such terms are
<PAGE>
-37-
used, shall have the meanings customarily attributed to such terms in
the electric power industry in New England.
SECTION 2
PURPOSE; EFFECTIVE DATES
------------------------
2.1 Purpose. This Restated NEPOOL Agreement is intended to provide for a
-------
restructuring of the New England Power Pool by modifying the pool's
governance and market provisions to take account of a changed
competitive environment, by modifying the transmission responsibilities
of the Participants so that the pool will perform the functions of a
regional transmission group and provide service to Participants and
Non-Participants under a regional open access transmission tariff, and
by providing for the activation of the ISO and the execution of a
contract between the ISO and NEPOOL to define the ISO's
responsibilities.
2.2 Effective Dates; Transitional Provisions. The provisions of Parts One,
----------------------------------------
Two, Four and Five of this Agreement and the Tariff shall become
effective on the First Effective Date, and shall replace on the First
Effective Date the provisions of Sections 1-8, inclusive, 10, 11, 13,
14.2, 14.3, 14.4 and 16 of the Prior NEPOOL Agreement. The
<PAGE>
-38-
provisions of Sections 12.1(a), 12.2, 12.4 (as to Installed Capability
only), 12.5 and 12.7(a) of this Agreement shall become effective on
November 1, 1997, or such other date as the Commission may fix, and
shall replace on such date the provisions of Section 9 of the Prior
NEPOOL Agreement.
The effectiveness of the remaining Sections of this Restated NEPOOL
Agreement shall be delayed pending the preparation of implementing
criteria, rules and standards and computer programs. These Sections
shall become effective on the Second Effective Date and shall replace
on the Second Effective Date the remaining provisions of the Prior
NEPOOL Agreement, which shall continue in effect until the Second
Effective Date.
As provided in Section 14, certain portions of Section 14 which will
become effective on the Second Effective Date will be superseded on the
Third Effective Date by other portions of Section 14.
The activation of the ISO will occur after the First Effective Date.
Until that time, the NEPOOL committees shall continue to be responsible
for the supervision of the NEPOOL staff.
<PAGE>
-39-
SECTION 3
MEMBERSHIP
----------
3.1 Membership. Those Entities which are Participants in NEPOOL on the
----------
First Effective Date shall continue to be Participants.
Any other Entity may, upon compliance with such reasonable conditions
as the Management Committee may prescribe, become a Participant by
depositing a counterpart of this Agreement as theretofore amended, duly
executed by it, with the Secretary of the Management Committee,
accompanied by a certified copy of a vote of its board of directors, or
such other body or bodies as may be appropriate, duly authorizing its
execution and performance of this Agreement, and a check in payment of
the application fee described below.
Any such Entity which satisfies the requirements of this Section 3.1
shall become a Participant, and this Agreement shall become fully
binding and effective in accordance with its terms as to such Entity,
as of the first day of the second calendar month following its
satisfaction of such requirements; provided that an earlier or later
<PAGE>
-40-
effective time may be fixed by the Management Committee with the
concurrence of such Entity or by the Commission.
The application fee to be paid by each Entity seeking to become a
Participant shall be in addition to the annual fee provided by Section
19.1 and shall be $500 or such other amount as may be fixed by the
Management Committee.
3.2 Operations Outside the Control Area. Subject to the reciprocity
---------------------------------------
requirements of the Tariff, if a Participant serves a Load, or has
rights in supply or demand-side resources or owns transmission and/or
distribution facilities, located outside of the NEPOOL Control Area,
such Load and resources shall not be included for purposes of
determining the Participant's rights, responsibilities and obligations
under this Agreement, except that the Participant's Entitlements in
facilities or its rights in demand side-resources outside the NEPOOL
Control Area shall be included in such determinations if, to the
extent, and while such Entitlements are used for retail or wholesale
sales within the NEPOOL Control Area or such Entitlements or rights are
designated by a Participant for purposes of meeting its obligations
under Section 12 of this Agreement.
<PAGE>
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3.3 Lack of Place of Business in New England. If and for so long as a
---------------------------------------------
Participant does not have a place of business located in one of the New
England states, the Participant shall be deemed to irrevocably (1)
submit to the jurisdiction of any Connecticut state court or United
States Federal Court sitting in Connecticut (the state whose laws
govern this Agreement) over any action or proceeding arising out of or
relating to this Agreement that is not subject to the exclusive
jurisdiction of the Commission, (2) agree that all claims with respect
to such action or proceeding may be heard and determined in such
Connecticut state court or Federal court, (3) waive any objection to
venue or any action or proceeding in Connecticut on the basis of forum
non conveniens, and (4) agree that service of process may be made on
the Participant outside Connecticut by certified mail, postage prepaid,
mailed to the Participant at the address of its member on the
Management Committee as set out in the NEPOOL roster or at the address
of its principal place of business.
3.4 Obligation for Deferred Expenses. NEPOOL may provide for the deferral
---------------------------------
on the books of the Participants from time to time of capital or other
expenditures, and the recovery of the deferred expenses in subsequent
periods. Any Entity which becomes a Participant during the recovery
period for any such deferred expenses shall be
<PAGE>
-42-
obligated, together with the continuing Participants, for its share of
the current and deferred expenses pursuant to Section 19.2.
3.5 Financial Security. For an Entity applying to become a Participant or
-------------------
any continuing Participant that the Management Committee reasonably
determines may fail to meet its financial obligations under the
Agreement, the Management Committee may require reasonable credit
review procedures which shall be made in accordance with standard
commercial practices. In addition, the Management Committee may
prescribe for such Entity or Participant a requirement that the Entity
or Participant provide and maintain in effect an unconditional and
irrevocable letter of credit as security to meet its responsibilities
and obligations under the Agreement, or an alternative form of security
proposed by the Entity or Participant and acceptable to the Management
Committee and consistent with commercial practices established by the
Uniform Commercial Code that protects the Participants against the risk
of non-payment.
<PAGE>
-43-
SECTION 4
STATUS OF PARTICIPANTS
----------------------
4.1 Treatment of Certain Entities as Single Participant. All Entities which
---------------------------------------------------
are controlled by a single person (such as a corporation or a business
trust) which owns at least seventy-five percent of the voting shares
of, or equity interest in, each of them shall be collectively treated
as a single Participant for purposes of this Agreement, if they each
elect such treatment. They are encouraged to do so. Such an election
shall be made in writing and shall continue in effect until revoked in
writing.
In view of the long-standing arrangements in Vermont, Vermont Electric
Power Company, Inc. and any other Vermont electric utilities which
elect in writing to be grouped with it shall be collectively treated as
a single Participant for purposes of this Agreement.
4.2 Participants to Retain Separate Identities. The signatories to this
---------------------------------------------
Agreement shall not become partners by reason of this Agreement or
their activities hereunder, but as to each other and to third persons,
they shall be and remain independent contractors in all matters
relating to this Agreement. This Agreement shall not be construed to
create
<PAGE>
-44-
any liability on the part of any signatory to anyone not a party to
this Agreement. Each signatory shall retain its separate identity and,
to the extent not limited hereby, its individual freedom in rendering
service to its customers.
SECTION 5
NEPOOL OBJECTIVES AND COOPERATION BY PARTICIPANTS
-------------------------------------------------
5.1 NEPOOL Objectives. The objectives of NEPOOL are, through joint
------------------
planning, central dispatching, cooperation in environmental matters and
coordinated construction, central dispatch by the System Operator of
the operation and coordinated maintenance of electric supply and
demand-side resources and transmission facilities, the provision of an
open access regional transmission tariff and the provision of a means
for effective coordination with other power pools and utilities
situated in the United States and Canada,
(a) to assure that the bulk power supply of the NEPOOL
Control Area conforms to proper standards of
reliability;
<PAGE>
-45-
(b) to create and maintain open, non-discriminatory,
competitive, unbundled markets for Energy, capacity,
and ancillary services that function efficiently in a
changing electric power industry and have access to
regional transmission at rates that do not vary with
distance;
(c) to attain maximum practicable economy, consistent
with proper standards of reliability and the
maintenance of competitive markets, in such bulk
power supply; and
(d) to provide access to competitive markets within the
NEPOOL Control Area and to neighboring regions;
and to provide for equitable sharing of the resulting responsibilities,
benefits and costs.
5.2 Cooperation by Participants. In order to attain the objectives of
-----------------------------
NEPOOL set forth in Section 5.1, each Participant shall observe the
provisions of this Agreement in good faith, shall cooperate with all
other Participants and shall not either alone or in conjunction with
one or more other Entities take advantage of the provisions of this
<PAGE>
-46-
Agreement so as to harm another Participant or to prejudice the
position of any Participant in the electric power business.
Until the Second Effective Date, in order to assure the equitable
sharing among the Participants of the benefits contemplated by this
Agreement, no Participant shall participate, except pursuant to this
Agreement, in any transaction with one or more other Participants or
other Entities if such transaction involves an economy interchange
arrangement. The foregoing restriction shall not, however, apply to an
economy interchange or other similar arrangement between or among a
Participant and one or more Entities which are not Participants if, and
to the extent that, such arrangement is consistent with attainment of
the objectives stated in Section 5.1 and with the Participant's
obligations under this Agreement.
Until the effective date of the Tariff, in order further to assure the
equitable sharing among the Participants of the benefits and costs
contemplated by this Agreement, no transfer by a Participant to its
Related Person of an Entitlement in any generating unit shall be
recognized for purposes of this Agreement, including but not limited to
the calculation and allocation of benefits and costs under this
Agreement, if either (i) the transferee has a zero Adjusted Load or
(ii) the amount of the transferee's Installed
<PAGE>
-47-
System Capability, including such Entitlement, bears no reasonable
relation to its Adjusted Load. Furthermore, no other arrangement
substantially similar to that described in the preceding sentence shall
be recognized for purposes of this Agreement, including but not limited
to the calculation and allocation of benefits and costs under this
Agreement.
For the purposes of the preceding paragraph, the Adjusted Load and
Installed System Capability of any transferee that is not a Participant
shall be determined as if it were a Participant. The term "transferee,"
as used herein, shall include, without limitation, any Participant or
Entity, or any other organization or person.
PART TWO
GOVERNANCE
SECTION 6
MANAGEMENT COMMITTEE
--------------------
6.1 Membership. There shall be a Management Committee which shall be
----------
constituted as follows: each Participant shall appoint and be
represented by one member of the Management Committee.
<PAGE>
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6.2 Term of Members. Each member of the Management Committee shall hold
---------------
office until such member is replaced by the Participant which appointed
the member or until such Participant ceases to be a Participant.
Replacement of a member shall be effected by delivery by a Participant
of written notice of such replacement to the Secretary of the
Management Committee.
6.3 Votes. Each member of the Management Committee shall have a Voting
-----
Share in any month entitling the member to cast, on behalf of the
Participant which the member represents, votes representing the
percentage to which the member's Participant is entitled of the
aggregate Voting Shares of all Participants for the month. The
percentage of the aggregate Voting Shares of all Participants to which
a Participant is entitled in any month shall be determined in
accordance with the following formula:
P E C X M R Y
V = .15833(--)+.15833(--)+.15833(--)+.15833(--)+.15833(--)+.15833(--)+.05(--)
P1 E1 C1 X1 M1 R1 Y1
in which
<PAGE>
-49-
V = the Participant's Voting Share as a percentage of the aggregate
Voting Shares of all Participants;
P = the average for each of the most recently completed twelve
months of the Participant's maximum Load during any clock hour
in a month;
P1 = the average of the sums for each of the most recently
completed twelve months of the noncoincidental maximum Load
during any clock hour in a month of all Participants;
E = the average for the most recently completed twelve months of
the sum for each month of the Participant's Load for each hour
of the month plus any kilowatthours delivered during the month
----
to loads classified as interruptible under market operation
rules approved by the Regional Market Operations Committee;
E1 = the average for the most recently completed twelve months of
the sum for each month of the Loads of all Participants for
each hour of the month plus any kilowatthours delivered during
----
the month to loads classified as interruptible under market
operation rules approved by the Regional Market Operations
Committee.
<PAGE>
-50-
C = the average in megawatts for the most recently completed
twelve months of the sum for each month of the Generation
Ownership Shares, as defined in this Section, of the
Participant;
C1 = the average in megawatts for the most recently completed
twelve months of the sum for each month of the Generation
Ownership Shares of all Participants;
X = the average for the most recently completed twelve months of
the sum for each month of (i) a number of kilowatthours equal
-----
to the Kilowatts of the Participant's Generation Ownership
--
Shares, times the number of hours in the month, plus (ii) the
----- ----
number of kilowatthours that the Participant was entitled to
receive in each hour with respect to its Energy Entitlements
under Unit Contracts or System Contracts times, in the case of
-----
each contract, the number of hours the contract was in effect
in the month, as computed without giving effect to any resale
in whole or part of any such Energy Entitlement;
X1 = the average for the most recently completed twelve months of
the sum for each month of (i) a number of kilowatthours equal
-----
to the Kilowatts of the Generation Ownership Shares of all
--
Participants, times the number of hours in the month, plus
----- ----
(ii) the number of kilowatthours that all Participants were
entitled to
<PAGE>
-51-
receive in each hour with respect to their Energy Entitlements
under Unit Contracts or System Contracts times, in the case of
-----
each contract, the number of hours the contract was in effect
in the month, as computed without giving effect to any resale
in whole or part of any such Energy Entitlement;
M = the circuit miles of the Participant's Transmission
Ownership Shares, as defined in this Section, of PTF
transmission lines times, in the case of each line, the
-----
nominal operating voltage of the line;
M1 = the aggregate of the circuit miles of the Transmission
Ownership Shares of PTF transmission lines of all Participants
times, in the case of each line, the nominal operating voltage
-----
of the line;
R = the Annual Transmission Revenue Requirements of the
Participant's PTF as of the beginning of the current calendar
year as determined in accordance with Attachment F to the
Tariff except that 1) such Revenue Requirements shall not be
reduced by the transmission support revenue received as
described in Section I of that Attachment and 2) such Revenue
Requirements shall not include
<PAGE>
-52-
transmission support payments as described in Section J of
that Attachment for support arrangements which were entered
into after December 31, 1996;
R1 = the aggregate Annual Transmission Revenue Requirements of the
PTF of all Participants as of the beginning of the current
calendar year as determined in accordance with Attachment F to
the Tariff, except that 1) such Revenue Requirements shall not
be reduced by the transmission support revenue received as
described in Section I of that Attachment and 2) such Revenue
Requirements shall not include transmission support payments
as described in Section J of that Attachment for support
arrangements which were entered into after December 31, 1996;
Y = 1; and
Y1 = the number of NEPOOL Participants at the beginning of th
month;
provided, however, that a Participant and its Related Persons may not have
- -------- -------
aggregate Voting Shares exceeding 25% of the aggregate Voting Shares to which
all Participants are entitled. If the aggregate Voting Shares of a Participant
and its Related Persons would be in excess of
<PAGE>
-53-
25% if it were not for this limitation, the remaining Voting Shares to which
such Participant and its Related Persons would otherwise be entitled shall be
allocated to the other Participants on a pro rata basis.
For purposes of the preceding formula (i) if an Entity has been a Participant
for less than twelve months, the amounts to be taken into account for purposes
of "P", "E", "C" and "X" in the formula shall be for the period during which the
Entity has been a Participant; (ii) for purposes of "X" and "X1" in the formula,
the number of kilowatthours to be taken into account with respect to the HQ
Phase II Firm Energy Contract for each Participant which has a share in the HQ
Phase II Firm Energy Contract shall be computed on the basis of the number of
Kilowatts of its HQ Interconnection Capability Credit, if any, for the month;
and (iii) for purposes of "X" and "X1" in the formula, the number of
kilowatthours to be taken into account with respect to an Energy Entitlement
under a Unit Contract or System Contract, other than the HQ Phase II Firm Energy
Contract, under which a Participant is entitled to receive Energy from outside
the NEPOOL Control Area shall be computed on the basis of the number of
Kilowatts of Installed Capability credit, or Monthly Peak reduction, for which
the Participant is given credit in determining whether it has satisfied its
Installed Capability Responsibility pursuant to Section 12.
<PAGE>
-54-
In the event a Participant both participates in the wholesale bulk power market
and owns PTF, the member appointed by the Participant shall be entitled to
divide the member's vote, as determined in accordance with this Section, on any
matter on the basis specified by it in a notice given to the Secretary of the
Management Committee at or prior to the meeting at which the vote is to be cast,
to reflect its market and transmission interests. In such case the portion of
the member's vote reflecting its transmission interest may be cast by the
member's alternate.
For purposes of this Section, the Generation Ownership Shares of a Participant
means and includes:
(A) the direct ownership interest which the Participant has as a
sole or joint owner in the Installed Capability of a
generating unit which is subject to NEPOOL central dispatch in
accordance with Section 13.2;
(B) the indirect ownership interest which the Participant has, as
a shareholder in Connecticut Yankee Atomic Power Company,
Maine Yankee Atomic Power Company, Vermont Yankee Nuclear
Power Corporation or a similar corporation, or as a general or
limited partner in Ocean State Power or a similar
<PAGE>
-55-
partnership, in the Installed Capability of a generating unit
which is subject to NEPOOL central dispatch in accordance with
Section 13.2, provided the corporation or partnership is
itself not a Participant;
(C) any other interest which the Participant has in the Installed
Capability of a generating unit which is subject to NEPOOL
central dispatch in accordance with Section 13.2, under a
lease or other contractual arrangement, provided the other
party to the arrangement is itself not a Participant and the
Management Committee determines, at the request of the
affected Participant, that the Participant has benefits and
rights, and assumes risks, under the arrangement with respect
to the unit which are substantially equivalent to the
benefits, rights and risks of an owner; and
(D) an interest which the Participant shall be deemed to have in
the direct ownership interest, or the indirect ownership
interest as a shareholder or general or limited partner, of a
Related Person of the Participant in the Installed Capability
of a generating unit which is subject to NEPOOL central
dispatch in accordance with Section 13.2, provided the Related
Person is itself not a Participant.
<PAGE>
-56-
For purposes of this Section, the Transmission Ownership Shares of a Participant
means and includes:
(W) the direct ownership interest which the Participant has as a
sole or joint owner of PTF;
(X) the indirect ownership interest which the Participant has, as
a shareholder in a corporation, or as a general or limited
partner in a partnership, in PTF owned by such corporation or
partnership, provided the corporation or partnership is not
itself a Participant;
(Y) any other interest which the Participant has in PTF under a
lease or other contractual arrangement, provided the other
party to the arrangement is not itself a Participant and the
Management Committee determines, at the request of the
affected Participant, that the Participant has benefits and
rights, and assumes risks, under the arrangement with respect
to the PTF which are substantially equivalent to the benefits,
rights and risks of an owner; and
<PAGE>
-57-
(Z) an interest which the Participant shall be deemed to have in
the direct ownership interest, or the indirect ownership
interest as a shareholder or general or limited partner, of a
Related Person of the Participant in PTF, provided the Related
Person is itself not a Participant.
6.4 Number of Votes Necessary for Action. Actions of the Management
-----------------------------------------
Committee shall be effected only upon an affirmative vote of members
having at least 66% of the aggregate Voting Shares to which all members
are entitled; provided, however, that the negative votes of any three
-------- -------
or more members representing Participants which are not Related Persons
of each other and which have at least 20% of the aggregate Voting
Shares to which all members are entitled shall defeat any proposed
action. In determining whether the negative vote total specified above
has been reached, the following limitation shall be applied: if the
member or members representing any Participant and its Related Persons
would be entitled to cast against the proposed action more than 18% of
the aggregate Voting Shares to which all members are entitled, such
member or members shall be entitled to vote negatively only 18% of such
aggregate Voting Shares.
<PAGE>
-58-
6.5 Proxies. The vote of any member of the Management Committee or the
-------
member's alternate may be cast by another person pursuant to a written
proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Management Committee at or prior to
the meeting at which the proxy vote is cast.
6.6 Alternates. A Participant may designate, by a written notice delivered
----------
to the Secretary of the Management Committee, an alternate for a member
of the Management Committee appointed by it. In the absence of the
member, the alternate shall have all the powers of the member,
including the power to vote.
6.7 Officers. At its annual meeting, the Management Committee shall elect
--------
from among its members a Chair and a Vice-Chair; it shall also elect a
Secretary who need not be a member. These officers shall have the
powers and duties usually incident to such offices.
6.8 Meetings. The Management Committee shall hold its annual meeting in
--------
December at such time and place as the Chair shall designate and shall
hold other meetings in accordance with a schedule adopted by the
Management Committee or at the call of the Chair. One or more members
who represent Participants having in the aggregate at
<PAGE>
-59-
least 3% of the aggregate Voting Shares of all Participants may call a
special meeting of the Management Committee in the event that the Chair
shall fail to call such a meeting within three business days following
the Chair's receipt from such member or members of a request specifying
the subject matters to be acted upon at the meeting.
6.9 Notice of Meetings. Written notice of each meeting of the Management
------------------
Committee shall be given to each member not less than five business
days prior to the date of the meeting, which notice shall specify the
principal subject matter expected to be acted upon at the meeting.
6.10 Adoption of Budgets. At each annual meeting, the Management Committee
-------------------
shall adopt a NEPOOL budget for the ensuing calendar year. In adopting
budgets the Management Committee shall give due consideration to the
budgetary requests of each committee and shall include the budget of
the ISO as determined in accordance with NEPOOL's contract between
NEPOOL and the ISO. The Management Committee may modify any NEPOOL
budget from time to time after its adoption and shall modify the NEPOOL
budget if and as required to support changes to the ISO budget adopted
in accordance with the contract between NEPOOL and the ISO.
<PAGE>
-60-
6.11 Adoption of Bylaws. The Management Committee may adopt bylaws,
--------------------
consistent with this Agreement, governing procedural matters including
the conduct of its meetings and those of the other committees.
6.12 Establishing Reliability Standards. It shall be the duty of the
------------------------------------
Management Committee, after review of reports or actions of the System
Operator and the Market Reliability Planning Committee and Regional
Transmission Planning Committees and such other matters as the
Management Committee deems pertinent, to establish or approve proper
standards of reliability for the bulk power supply of NEPOOL. Such
standards shall be consistent with the directives of the North American
Electric Reliability Council and the Northeast Power Coordinating
Council and shall be reviewed periodically by the Management Committee
and revised as the Management Committee deems appropriate.
6.13 Appointment and Compensation of NEPOOL Personnel. The Management
-----------------------------------------------------
Committee shall determine what personnel are desirable for the
effective operation and administration of NEPOOL and shall fix or
authorize the fixing of the compensation for such persons.
<PAGE>
-61-
6.14 Duties and Authority.
--------------------
(a) The Management Committee shall have the duty and
requisite authority to administer, enforce and
interpret the provisions of this Agreement in order
to accomplish the objectives of NEPOOL including the
making of any decision or determination necessary
under any provision of this Agreement and not
expressly specified to be decided or determined by
any other body.
(b) The Management Committee shall have the authority to
provide for such facilities, materials and supplies
as the Management Committee may determine are
necessary or desirable to carry out the provisions of
this Agreement.
(c) The Management Committee shall have, in addition to
the authority provided in Section 6.12, the
authority, after consultation with other NEPOOL
committees and the System Operator, to establish or
approve consistent standards with respect to any
aspect of arrangements between Participants and
Non-Participants which it determines may adversely
<PAGE>
-62-
affect the reliability of NEPOOL, and to review such
arrangements to determine compliance with such
standards.
(d) The Management Committee, or its designee, shall have
the authority to act on behalf of all Participants in
carrying out any action properly taken pursuant to
the provisions of this Agreement. Without limiting
the foregoing general authority, the Management
Committee, or its designee, shall have the authority
on behalf of all Participants to execute any
contract, lease or other instrument which has been
properly authorized pursuant to this Agreement
including, but not limited to, one or more contracts
with the ISO, and to file with the Commission and
other appropriate regulatory bodies: (i) this
Agreement and documents amending or supplementing
this Agreement, including the Tariff, (ii) contracts
with Non-Participants or the ISO, and (iii) related
tariffs, rate schedules and certificates of
concurrence. The Management Committee shall,
in addition, have the authority to represent NEPOOL
in proceedings before the Commission.
<PAGE>
-63-
(e) The Management Committee shall have the duty and
requisite authority, after consultation with other
NEPOOL committees and the System Operator, to fix the
NEPOOL Objective Capability for each month of each
Power Year prior to the beginning of the Power Year
and thereafter to review at least annually the
anticipated Load of the NEPOOL Participants and
NEPOOL Installed Capability for each month of such
Power Year and to make such adjustments in the NEPOOL
Objective Capability as the Management Committee may
determine on the basis of such review. Since changes
in the circumstances which must be assumed by the
Management Committee in fixing NEPOOL Objective
Capability for a future period can significantly
affect the required level of NEPOOL Objective
Capability for that period, the Management Committee
shall, where appropriate, also determine the effect
on NEPOOL Objective Capability of significant changes
in circumstances from those assumed, either by fixing
alternative NEPOOL Objective Capabilities, or by
adopting adjustment factors or formulas.
(f) The Management Committee shall have the duty and
requisite authority to establish or approve schedules
fixing the amounts to be paid by
<PAGE>
-64-
Participants and Non-Participants to permit the
recovery of expenses incurred in furnishing some or
all of the services furnished by NEPOOL either
directly or through the System Operator.
(g) The Management Committee shall have the duty and
requisite authority to provide for the sharing by
Participants, on such basis as the Management
Committee may deem appropriate, of payments and costs
which are not otherwise reimbursed under this
Agreement and which are incurred by Participants or
under arrangements with Non-Participants and approved
or authorized by the Committee as necessary in order
to meet or avoid short-term deficiencies in the
amount of resources available to meet the pool's
reliability objectives.
(h) The Management Committee shall have the authority, at
the time that it acts on an Entity's application
pursuant to Section 3.1 to become a Participant, to
waive, conditionally or unconditionally, compliance
by such Entity with one or more of the obligations
imposed by this Agreement if the Management Committee
determines that such compliance would be unnecessary
or inappropriate for such Entity and
<PAGE>
-65-
the waiver for such Entity will not impose an
additional burden on other Participants.
(i) Until the Second Effective Date, the Management
Committee shall have the duty and requisite authority
to determine which generating facilities should be
equipped for Automatic Generation Control in order to
maintain proper frequency for the interconnected bulk
power system of the Participants and to control power
flows on interconnections between Participants and
non-Participants. The Management Committee shall
establish a system for sharing by the Participants
until the Second Effective Date, on such basis as the
Committee may deem appropriate, of the costs,
including loss of generator efficiency, that are
incurred by Participants in installing, maintaining
and operating Automatic Generation Control equipment
required by the Committee and are not otherwise
reimbursed under this Agreement.
(j) The Management Committee shall have the duty and
requisite authority to act on appeals to it from the
actions of other NEPOOL committees and to appoint a
special committee to administer NEPOOL's alternate
<PAGE>
-66-
dispute resolution procedures or to take any other
action if it determines that such action is necessary
or appropriate to achieve a prompt resolution of
disputes under the provisions of Section 21.1.
(k) The Management Committee shall have such further
powers and duties as are conferred or imposed upon it
by other sections of this Agreement.
6.15 Attendance of Members of Management Committee at Other Committee
-----------------------------------------------------------------------
Meetings. Each member of the Management Committee or that member's
--------
designee shall be entitled to attend any meeting of any other NEPOOL
committee, and shall have a reasonable opportunity to express views on
any matter to be acted upon at the meeting.
SECTION 7
EXECUTIVE COMMITTEE
-------------------
7.1 Organization. There shall be an Executive Committee which shall have
------------
all the powers and duties of the Management Committee (except as
provided below), subject to appeal to the Management Committee pursuant
to the provisions of Section 7.11. Between meetings of the Management
Committee, the Executive Committee shall exercise the
<PAGE>
-67-
powers and perform the duties of the Management Committee. The
Executive Committee shall not have any of the powers or duties of the
Management Committee under Sections 6.7 and 6.10, except that the
Executive Committee shall have the power of the Management Committee to
modify from time to time an overall NEPOOL annual budget adopted by the
Management Committee, subject to the limitation that the aggregate
amount of net increase in an overall budget which may be effected by
the Executive Committee for any year shall not exceed 10% of the budget
initially adopted by the Management Committee.
7.2 Membership. The Executive Committee shall be constituted as follows:
----------
following its activation, the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting Share
equals or exceeds 3% of the aggregate Voting Shares of all Participants
shall have the right to appoint a voting member of the Committee; the
remaining Participants whose Voting Shares are less than 3% of the
aggregate Voting Shares of all Participants shall be divided into the
following five groups, with each having the right to appoint one voting
member of the Committee:
<PAGE>
-68-
(a) One group consisting of the remaining
Participants which are municipally-owned and
cooperatively-owned utilities;
(b) One group consisting of the remaining
Participants which are not subject to
traditional utility rate regulation and
which are engaged in the NEPOOL Control Area
principally in the business of owning or
operating generation facilities and selling
the output of such generation;
(c) One group consisting of the remaining
Participants which are not subject to
traditional utility rate regulation and
which are engaged in the NEPOOL Control Area
principally in a business other than the
business of owning or operating generation
or PTF facilities and selling the output of
such generation;
(d) One group consisting of the remaining
Participants, if any, which (i) own PTF,
(ii) are not engaged in electric generation
or distribution and do not participate in
the wholesale bulk power
<PAGE>
-69-
market, and (iii) are not Related Persons of
any other Participant; and
(e) One group consisting of the remaining
Participants which are investor-owned
utilities subject to traditional rate
regulation or other Entities which do not
qualify to be included in any of the other
four groups.
Notwithstanding the foregoing, any such Participant may elect to join a
different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person of
another Participant which has the individual right to appoint a member
of the Committee on the basis of its individual Voting Share, the
Participant shall be represented on the Committee by the member
appointed by the Participant which is its Related Person and shall not
be assigned to any of the five groups.
7.3 Term of Members. The member of the Executive Committee appointed by the
---------------
ISO shall serve until replaced by the ISO. Members of the Executive
Committee appointed by a Participant or group of Participants shall
serve until replaced by the Participant or
<PAGE>
-70-
Participants which appointed them or until such Participant or
Participants shall lose their status as Participants or otherwise lose
their right to appoint the member. Appointment or replacement of a
member shall be effected by the ISO or a Participant or group of
Participants by giving written notice of such appointment or
replacement to the Secretary of the Executive Committee.
7.4 Alternates. The ISO or a Participant or group of Participants may
----------
designate, by a written notice given to the Secretary of the Executive
Committee, an alternate for any member of the Executive Committee
appointed by the ISO or such Participant or group of Participants. In
the absence of the member, the alternate shall have all the powers of
the member, including the power to vote.
7.5 Votes. Each voting member of the Executive Committee shall have one
-----
vote, which may be cast in person by the member or the member's
alternate or by another person pursuant to a written proxy dated not
more than one year previous to the meeting and delivered to the
Secretary of the Executive Committee at or prior to the meeting at
which the proxy vote is cast. If a Participant which has the individual
right to appoint a member of the Executive Committee both participates
in the wholesale bulk power market and owns PTF, the member appointed
by the Participant shall be entitled to
<PAGE>
-71-
divide the member's vote on the basis specified in a notice given by it
to the Secretary of the Committee at or prior to the meeting at which
the vote is to be cast, to reflect the Participant's market and
transmission interests. In such case the portion of the Participant
member's vote reflecting its transmission interest may be cast by the
member's alternate.
A voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
7.6 Number of Votes Necessary for Action. The adoption of actions by the
--------------------------------------
Executive Committee shall require affirmative votes by voting members
aggregating at least 60% of the number of votes which the voting
members in attendance at a meeting at which a quorum is present are
entitled to cast. A majority of the voting members at any time shall
constitute a quorum.
7.7 Officers. At its annual meeting, the Executive Committee shall elect
--------
from its voting members a Chair and a Vice-Chair; it shall also elect a
Secretary who need not be a
<PAGE>
-72-
member. These officers shall have the powers and duties usually
incident to such offices.
7.8 Meetings. The Executive Committee shall hold its annual meeting in
--------
December or January at such time and place as the Chair shall designate
and shall hold other meetings in accordance with a schedule adopted by
the Executive Committee or at the call of the Chair. Any two members
may call a special meeting of the Executive Committee in the event that
the Chair shall fail to call such a meeting within three business days
following the Chair's receipt from such members of a request specifying
the subject matters to be acted upon at the meeting. Any regular or
special meeting of the Executive Committee may be conducted by means of
conference telephone or other communications equipment by means of
which all persons participating in the meeting can hear each other.
7.9 Notice of Meetings. Written notice of each meeting of the Executive
------------------
Committee shall be given to each member of the Committee and each
member of the Management Committee not less than three business days
prior to the date of the meeting. The notice shall specify the
principal subject matter expected to be acted upon at the meeting.
<PAGE>
-73-
7.10 Notice to Members of Management Committee of Actions by Executive
-----------------------------------------------------------------------
Committee. Prior to the end of the fifth business day following a
---------
meeting of the Executive Committee, the Secretary of the Executive
Committee shall give written notice to the ISO and each member of the
Management Committee of any action taken by the Executive Committee at
such meeting.
7.11 Appeal of Actions to Management Committee. The ISO or any Participant
-----------------------------------------
may appeal to the Management Committee any action taken by the
Executive Committee. Such an appeal shall be taken prior to the end of
the tenth business day following the meeting of the Executive
Committee to which the appeal relates by giving to the Secretary of
the Management Committee a signed and written notice of appeal and by
mailing a copy of the notice to the ISO and each member of the
Management Committee. Pending action on the appeal by the Management
Committee, the giving of a notice of appeal as aforesaid shall suspend
the action appealed from.
<PAGE>
-74-
SECTION 8
MARKET RELIABILITY PLANNING COMMITTEE
-------------------------------------
8.1 Organization. There shall be a Market Reliability Planning Committee
------------
which shall have the responsibilities specified in Section 8.11. It may
provide from time to time for the creation of one or more Functional
Planning Committees to act in particular functional planning areas and
to exercise such of the Market Reliability Planning Committee's
responsibilities as it may delegate to them.
8.2 Membership. The Market Reliability Planning Committee shall be
----------
constituted as follows: following its activation, the ISO shall have
the right to appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 3% of the aggregate
Voting Shares of all Participants shall have the right to appoint a
voting member of the Committee; the remaining Participants shall be
divided into the following five groups, with each having the right to
appoint one voting member of the Committee:
<PAGE>
-75-
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owne
utilities;
(b) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in the business of owning or
operating generation facilities and selling the
output of such generation;
(c) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than the
business of owning or operating generation or PTF
facilities and selling the output of such generation;
(d) One group consisting of the remaining Participants,
if any, which (i) own PTF, (ii) are not engaged in
electric generation or distribution and do not
participate in the wholesale bulk power market, and
(iii) are not Related Persons of any other
Participant; and
<PAGE>
-76-
(e) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional rate regulation or other Entities which
do not qualify to be included in any of the other
four groups.
Notwithstanding the foregoing, any such Participant may elect to join a
different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person of
another Participant which has the individual right to appoint a member
of the Committee, the Participant shall be represented in the Committee
by the member appointed by the Participant which is its Related Person
and shall not be assigned to any of the five groups.
8.3 Term of Members. The member of the Market Reliability Planning
-----------------
Committee appointed by the ISO shall serve until replaced by the ISO.
Members of the Market Reliability Planning Committee appointed by a
Participant or group of Participants shall serve until replaced by the
Participant or Participants which appointed them or until such
Participant or Participants cease to be Participants or otherwise lose
their right to appoint the member. Appointment or replacement of a
member shall be effected by the ISO or a Participant or group of
Participants by giving written notice of
<PAGE>
-77-
such appointment or replacement to the Secretary of the Market
Reliability Planning Committee.
8.4 Voting. Each voting member of the Market Reliability Planning Committee
------
shall have one vote which may be cast in person by the member or the
member's alternate or by another person pursuant to a written proxy
dated not more than one year previous to the meeting and delivered to
the Secretary of the Market Reliability Planning Committee at or prior
to the meeting at which the proxy vote is cast. If a Participant which
has the individual right to appoint a voting member of the Market
Reliability Planning Committee both participates in the wholesale bulk
power market and owns PTF, the member appointed by the Participant
shall be entitled to divide the member's vote on the basis specified in
a notice given by it to the Secretary of the Committee at or prior to
the meeting at which the vote is to be cast, to reflect the
Participant's market and transmission interests. In such case the
portion of the member's vote reflecting its transmission interest may
be cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the
<PAGE>
-78-
meeting at which the vote is to be cast, to reflect the different
positions of the members of the group.
The adoption of actions by the Market Reliability Planning Committee
shall require affirmative votes by voting members aggregating at least
60% of the number of votes which the members in attendance at a meeting
at which a quorum is present are entitled to cast. A majority of the
voting members at any time shall constitute a quorum.
8.5 Alternates. The ISO or a Participant or group of Participants may
----------
designate, by a written notice given to the Secretary of the Market
Reliability Planning Committee, an alternate for the member of the
Market Reliability Planning Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member, the
alternate shall have all the powers of the member, including the power
to vote.
8.6 Officers. At its annual meeting, the Market Reliability Planning
--------
Committee shall elect from its voting members a Chair and a Vice-Chair;
it shall also elect a Secretary who need not be a member of the
Committee. These officers shall have the powers and duties usually
incident to such offices.
<PAGE>
-79-
8.7 Meetings. The Market Reliability Planning Committee shall hold its
--------
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Committee or at the call of the Chair. Any
two members may call a special meeting of the Market Reliability
Planning Committee in the event that the Chair shall fail to call such
a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be
considered at the meeting. Any regular or special meeting of the Market
Reliability Planning Committee may be conducted by means of conference
telephone or other communications equipment by means of which all
persons participating in the meeting can hear each other.
8.8 Notice of Meetings. Written notice of each meeting of the Market
-------------------
Reliability Planning Committee shall be given to each member not less
than five business days prior to the date of the meeting. The principal
subject matter expected to be acted upon at a meeting shall be
specified in the notice of the meeting whenever the meeting is not held
in accordance with the schedule adopted by the Committee.
8.9 Notice to Members of Management Committee. Prior to the end of the
-----------------------------------------
fifth business day following a meeting of the Market Reliability
Planning Committee, the Secretary
<PAGE>
-80-
of the Market Reliability Planning Committee shall give written notice
to the ISO and each member of the Management Committee of any action
taken by the Market Reliability Planning Committee at such meeting.
8.10 Appeal of Actions to Management Committee. The ISO or any Participant
------------------------------------------
may appeal to the Management Committee any action taken by the Market
Reliability Planning Committee. Such an appeal shall be taken prior to
the end of the tenth business day following the meeting of the Market
Reliability Planning Committee to which the appeal relates by giving to
the Secretary of the Management Committee a signed and written notice
of appeal and by mailing a copy of the notice to the ISO and each
member of the Management Committee. Pending action on the appeal by the
Management Committee, the giving of a notice of appeal as aforesaid
shall suspend the action appealed from.
8.11 Responsibilities. The Market Reliability Planning Committee shall be
----------------
responsible, either directly or through its Functional Planning
Committees, and in conjunction with the ISO and the Regional
Transmission Planning Committee, as appropriate, for the following:
<PAGE>
-81-
(a) providing overall direction to, and coordination of,
joint studies of supply and demand-side resources and
environmental considerations in order to achieve the
objectives of NEPOOL;
(b) recommending to the Management Committee the NEPOOL
Objective Capability for each Power Year;
(c) periodically reviewing the procedures used to
calculate NEPOOL Installed Capability, NEPOOL
Objective Capability and NEPOOL Capability
Responsibility;
(d) causing to be prepared periodic short and long term
load forecasts for use in NEPOOL studies and
operations and to meet requirements of regulatory
agencies;
(e) overseeing communications and liaison between NEPOOL
and governmental authorities on power supply,
environmental and load forecasting issues;
<PAGE>
-82-
(f) coordinating the collection and exchange of necessary
system data and future plans for use in NEPOOL
planning and to meet requirements of regulatory
agencies;
(g) following appropriate studies, recommending to the
Management Committee reliability standards for the
bulk power system of NEPOOL; and
(h) coordinating the review of proposed supply and
demand-side resource plans of Participants pursuant
to Section 18.4 and the submission of recommendations
to the Management Committee regarding such proposed
plans.
8.12 Functional Planning Committees. The Market Reliability Planning
---------------------------------
Committee's Functional Planning Committees shall remain subject to
policy-level direction and control by the Market Reliability Planning
Committee. Functional Planning Committees may participate in joint
studies with each other and with other NEPOOL committees or task
forces, but shall submit reports and recommendations directly to the
<PAGE>
-83-
Management Committee only pursuant to the request of the Market
Reliability Planning Committee.
The members of each Functional Planning Committee shall be appointed in
the same manner as the members of the Market Reliability Planning
Committee, and, if requested by the ISO, shall include a non-voting
member appointed by the ISO. The Chair, Vice-Chair and Secretary of
each Functional Planning Committee shall be appointed in accordance
with procedures specified by the Market Reliability Planning Committee.
Except as expressly directed by the Market Reliability Planning
Committee, its Functional Planning Committees shall be study, research
and deliberative bodies and shall not resolve by vote differences of
opinion as to proposed plans or other matters on which they may make
reports or recommendations. Functional Planning Committees shall
regularly report the results of their work to the Market Reliability
Planning Committee, and whenever a Functional Planning Committee is
unable to reach a consensus resolution of a policy issue, that issue
shall be reported to the Market Reliability Planning Committee.
Functional Planning Committee reports shall contain such personal
opinions and conclusions as any member may request. Where a vote of a
<PAGE>
-84-
Functional Planning Committee is required for election of officers or
other organizational matters, the action shall be effective only upon
an affirmative vote of 60% of the voting members present at the
meeting.
8.13 Appointment of Task Forces. The Market Reliability Planning Committee
--------------------------
and its Functional Planning Committees shall have the authority, within
the Market Reliability Planning Committee's budget or with the approval
of the Management Committee if beyond its budget, to appoint task
forces for particular studies and to name thereto available employees
of Participants.
8.14 Consultants, Computer Time and Expenses. The Market Reliability
--------------------------------------------
Planning Committee and its Functional Planning Committees shall have
the authority, within the Market Reliability Planning Committee's
budget or with the approval of the Management Committee if beyond its
budget, to retain the services of the ISO, to hire other consultants,
to procure computer time and to incur such expenses as may be required
to enable the Market Reliability Planning Committee, its Functional
Planning Committees and their task forces properly to perform their
duties.
<PAGE>
-85-
8.15 Further Powers and Duties. The Market Reliability Planning Committee
-------------------------
shall have such further powers and duties as may be prescribed by the
Management Committee or as set forth in this Agreement.
8.16 Reports to Management Committee. The Market Reliability Planning
----------------------------------
Committee shall report to the Management Committee periodically the
results of its work and such reports shall contain such alternative
programs as the Market Reliability Planning Committee may consider
appropriate. Market Reliability Planning Committee reports shall also
contain such minority opinions and conclusions as any member shall
request.
8.17 Joint Meetings With Regional Transmission Planning Committee. The
-----------------------------------------------------------------
Market Reliability Planning Committee is authorized and encouraged to
hold its meetings, and to conduct studies and exercise its
responsibilities, jointly with the Regional Transmission Planning
Committee to the extent appropriate.
<PAGE>
-86-
SECTION 9
REGIONAL TRANSMISSION PLANNING COMMITTEE
----------------------------------------
9.1 Organization. There shall be a Regional Transmission Planning Committee
------------
which shall have the responsibilities specified in Section 9.11. It may
provide from time to time for the creation of one or more Functional
Planning Committees to act in particular functional transmission
planning areas and to exercise such of the Regional Transmission
Planning Committee's responsibilities as it may delegate to them.
9.2 Membership. The Regional Transmission Planning Committee shall be
----------
constituted as follows: following its activation, the ISO shall have
the right to appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 3% of the aggregate
Voting Shares of all Participants shall have the right to appoint a
voting member of the Committee; the remaining Participants whose Voting
Shares are less than 3% of the aggregate Voting Shares of all
Participants shall be divided into the following five groups, with each
having the right to appoint one voting member of the Committee:
<PAGE>
-87-
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owned
utilities;
(b) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in the business of owning or
operating generation facilities and selling the
output of such generation;
(c) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than the
business of owning or operating generation or PTF
facilities and selling the output of such generation;
(d) One group consisting of the remaining Participants,
if any, which (i) own PTF, (ii) are not engaged in
electric generation or distribution and do not
participate in the wholesale bulk power market, and
(iii) are not Related Persons of any other
Participant; and
<PAGE>
-88-
(e) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional utility rate regulation or other Entities
which do not qualify to be included in any of the
other four groups.
Notwithstanding the foregoing, any such Participant may elect to join a
different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any Participant is a Related Person of
another Participant which has the individual right to appoint a member
of the Committee on the basis of its individual Voting Share, the
Participant shall be represented in the Committee by the member
appointed by the Participant which is its Related Person and shall not
be assigned to any of the five groups.
9.3 Term of Members. The member of the Regional Transmission Planning
----------------
Committee appointed by the ISO shall serve until replaced by the ISO.
Other members of the Regional Transmission Planning Committee shall
serve until replaced by the Participant or Participants which appointed
them or until such Participant or Participants shall lose their status
as Participants or otherwise lose their right to appoint the member.
Appointment or replacement of a member shall be effected by the ISO or
a Participant
<PAGE>
-89-
or group of Participants by giving written notice of such appointment
or replacement to the Secretary of the Regional Transmission Planning
Committee.
9.4 Voting. Each voting member of the Regional Transmission Planning
------
Committee shall have one vote which may be cast in person by the member
or the member's alternate or by another person pursuant to a written
proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Regional Transmission Planning
Committee at or prior to the meeting at which the proxy vote is cast.
If a Participant which has the individual right to appoint a member of
the Regional Transmission Planning Committee both participates in the
wholesale bulk power market and owns PTF, the member appointed by the
Participant shall be entitled to divide the member's vote on the basis
specified in a notice given to the Secretary of the Committee at or
prior to the meeting at which the vote is to be cast, to reflect the
Participant's market and transmission interests. In such case the
portion of the member's vote reflecting its transmission interest may
be cast by the member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given to the Secretary of the Committee
at or prior to the meeting
<PAGE>
-90-
at which the vote is to be cast, to reflect the different positions o
the members of the group.
The adoption of actions by the Regional Transmission Planning Committee
shall require affirmative votes by voting members aggregating at least
60% of the number of votes which the members in attendance at a meeting
at which a quorum is present are entitled to cast. A majority of the
voting members at any time shall constitute a quorum.
9.5 Alternates. The ISO, or a Participant or group of Participants may
----------
designate, by a written notice given to the Secretary of the Regional
Transmission Planning Committee, an alternate for any member of the
Regional Transmission Planning Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member, the
alternate shall have all the powers of the member, including the power
to vote.
9.6 Officers. At its annual meeting, the Regional Transmission Planning
--------
Committee shall elect from its voting members a Chair and a Vice-Chair;
it shall also elect a Secretary
<PAGE>
-91-
who need not be a member of the Committee. These officers shall have
the powers and duties usually incident to such offices.
9.7 Meetings. The Regional Transmission Planning Committee shall hold its
--------
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Committee or at the call of the Chair. Any
two members may call a special meeting of the Regional Transmission
Planning Committee in the event that the Chair shall fail to call such
a meeting within three business days following the Chair's receipt from
such members of a request specifying the subject matters to be
considered at the meeting. Any regular or special meeting of the
Regional Transmission Planning Committee may be conducted by means of
conference telephone or other communications equipment by means of
which all persons participating in the meeting can hear each other.
9.8 Notice of Meetings. Written notice of each meeting of the Regional
-------------------
Transmission Planning Committee shall be given to each member not less
than five business days prior to the date of the meeting. The principal
subject matter expected to be acted upon at a meeting shall be
specified in the notice of the meeting whenever the meeting is not held
in accordance with the schedule adopted by the Committee.
<PAGE>
-92-
9.9 Notice to Members of Management Committee. Prior to the end of the
---------------------------------------------
fifth business day following a meeting of the Regional Transmission
Planning Committee, the Secretary of the Regional Transmission Planning
Committee shall give written notice to the ISO and each member of the
Management Committee of any action taken by the Regional Transmission
Planning Committee at such meeting.
9.10 Appeal of Actions to Management Committee. The ISO or any Participant
------------------------------------------
may appeal to the Management Committee any action taken by the Regional
Transmission Planning Committee. Such an appeal shall be taken prior to
the end of the tenth business day following the meeting of the Regional
Transmission Planning Committee to which the appeal relates by giving
to the Secretary of the Management Committee a signed and written
notice of appeal and by mailing a copy of the notice to the ISO and
each member of the Management Committee. Pending action on the appeal
by the Management Committee, the delivery of a notice of appeal as
aforesaid shall suspend the action appealed from.
<PAGE>
-93-
9.11 Responsibilities. The Regional Transmission Planning Committee shall be
----------------
responsible, either directly or through Functional Planning Committees,
and in conjunction with the ISO and the Market Reliability Planning
Committee, as appropriate, for the following:
(a) providing overall direction to, and coordination of,
joint studies of transmission facilities and the
development of a regional transmission plan in order
to achieve the objectives of NEPOOL;
(b) overseeing communications and liaison between NEPOOL
and governmental authorities on transmission issues;
(c) coordinating the collection and exchange of necessary
system data and future plans for use in NEPOOL
planning and to meet requirements of regulatory
agencies;
(d) following appropriate studies, recommending to the
Management Committee proposed reliability standards
for the bulk power system of NEPOOL;
<PAGE>
-94-
(e) coordinating the review of proposed transmission
plans of Participants pursuant to Section 18.4 and
the submission of recommendations to the Management
Committee regarding such proposed plans; and
(f) to the extent appropriate, establishing criteria,
guidelines and methodologies to assure consistency in
monitoring and assessing conformance of Participant
and regional transmission plans to accepted
reliability criteria.
9.12 Functional Planning Committees. The Regional Transmission Planning
------------------------------
Committee's Functional Planning Committees shall remain subject to
policy-level direction and control by the Regional Transmission
Planning Committee. Functional Planning Committees may participate in
joint studies with each other and with other NEPOOL committees or task
forces, but shall submit reports and recommendations directly to the
Management Committee only pursuant to the request of the Regional
Transmission Planning Committee.
The members of each Functional Planning Committee shall be appointed in
the same manner as the members of the Regional Transmission Planning
Committee, and, if
<PAGE>
-95-
requested by the ISO, shall include a non-voting member appointed by
the ISO. The Chair, Vice-Chair and Secretary of each Functional
Planning Committee shall be appointed in accordance with procedures
specified by the Regional Transmission Planning Committee.
Except as expressly directed by the Regional Transmission Planning
Committee, its Functional Planning Committees shall be study, research
and deliberative bodies and shall not resolve by vote differences of
opinion as to proposed plans or other matters on which they may make
reports or recommendations. Functional Planning Committees shall
regularly report the results of their work to the Regional Transmission
Planning Committee, and whenever a Functional Planning Committee is
unable to reach a consensus resolution of a policy issue, that issue
shall be reported to the Regional Transmission Planning Committee.
Functional Planning Committee reports shall contain such personal
opinions and conclusions as any member may request. Where a vote of a
Functional Planning Committee is required for election of officers or
other organizational matters, the action shall be effective only upon
an affirmative vote of 60% of the voting members present at a meeting.
<PAGE>
-96-
9.13 Appointment of Task Forces. The Regional Transmission Planning
-----------------------------
Committee and its Functional Planning Committees shall have the
authority, within the Regional Transmission Planning Committee's budget
or with the approval of the Management Committee if beyond its budget,
to appoint task forces for particular studies and to name thereto
available employees of Participants.
9.14 Consultants, Computer Time and Expenses. The Regional Transmission
------------------------------------------
Planning Committee and its Functional Planning Committees shall have
the authority, within the Regional Transmission Planning Committee's
budget or with the approval of the Management Committee if beyond its
budget, to retain the services of the ISO, to hire other consultants,
to procure computer time and to incur such expenses as may be required
to enable the Regional Transmission Planning Committee, its Functional
Planning Committees and their task forces properly to perform their
duties.
9.15 Further Powers and Duties. The Regional Transmission Planning Committee
-------------------------
shall have such further powers and duties as may be prescribed by the
Management Committee or as set forth in this Agreement.
<PAGE>
-97-
9.16 Reports to Management Committee. The Regional Transmission Planning
--------------------------------
Committee shall report to the Management Committee periodically the
results of its work and such reports shall contain such alternative
programs as the Regional Transmission Planning Committee may consider
appropriate. Regional Transmission Planning Committee reports shall
also contain such minority opinions and conclusions as any member shall
request.
9.17 Joint Meetings With Market Reliability Planning Committee. The Regional
---------------------------------------------------------
Transmission Planning Committee is authorized and encouraged to hold
its meetings, and to conduct studies and exercise its responsibilities,
jointly with the Market Reliability Planning Committee to the extent
appropriate.
SECTION 10
REGIONAL MARKET OPERATIONS COMMITTEE
------------------------------------
10.1 Organization. There shall be a Regional Market Operations Committee
------------
which shall be responsible for establishing or approving market
operation rules and for monitoring the operation of NEPOOL supply and
demand-side resources and the wholesale bulk power market.
<PAGE>
-98-
10.2 Membership. The Regional Market Operations Committee shall be
----------
constituted as follows: following its activation, the ISO shall have
the right to appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 3% of the aggregate
Voting Shares of all Participants shall have the right to appoint one
voting member and each Participant whose Voting Share equals or exceeds
15% of the aggregate Voting Shares of all Participants shall have the
right, so long as such condition continues, to appoint one additional
voting member, provided that the aggregate number of members which a
Participant and its Related Persons shall have the right to appoint
shall be limited to two members; the remaining Participants shall be
divided into the following five groups, with each having the right to
appoint one voting member of the Regional Market Operations Committee:
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owned
traditional utilities;
(b) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the
<PAGE>
-99-
NEPOOL Control Area principally in the business of
owning or operating generation facilities and selling
the output of such generation;
(c) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than the
business of owning or operating generation or PTF
facilities and selling the output of such generation;
(d) One group consisting of the remaining Participants,
if any, which (i) own PTF, (ii) are not engaged in
electric generation or distribution and do not
participate in the wholesale bulk power market, and
(iii) are not Related Persons of any other
Participant; and
(e) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional utility rate regulation or other Entities
which do not qualify to be included in any of the
other four groups.
<PAGE>
-100-
Notwithstanding the foregoing, any such Participant may elect to join a
different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any such Participant is a Related
Person of another Participant which has the individual right to appoint
one or two members of the Committee, the Participant shall be
represented in the Committee by the member or members appointed by the
Participant which is its Related Person and shall not be assigned to
any of the five groups.
10.3 Terms of Members. The member of the Regional Market Operations
------------------
Committee appointed by the ISO shall serve until replaced by the ISO.
Other members of the Regional Market Operations Committee shall serve
until replaced by the Participant or Participants which appointed them
or until such Participant or Participants shall lose their status as
Participants or otherwise lose the right to appoint the member.
Appointment or replacement of a member shall be effected by the ISO or
a Participant or group of Participants giving written notice of such
appointment or replacement to the Secretary of the Regional Market
Operations Committee.
10.4 Voting. Each voting member of the Regional Market Operations Committee
------
shall have one vote, which may be cast in person by the member or the
member's alternate or by
<PAGE>
-101-
another person pursuant to a written proxy dated not more than one year
previous to the meeting and delivered to the Secretary of the Regional
Market Operations Committee at or prior to the meeting at which the
proxy vote is cast. If a Participant which has the individual right to
appoint a member or members of the Regional Market Operations Committee
both participates in the wholesale bulk power market and owns PTF, the
member or members appointed by the Participant shall each be entitled
to divide its vote on the basis specified in a notice given by it to
the Secretary of the Committee at or prior to the meeting at which the
vote is to be cast, to reflect the Participant's market and
transmission interests. In such case the portion of a member's vote
reflecting its transmission interest may be cast by the member's
alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
The adoption of actions by the Regional Market Operations Committee
shall require affirmative votes by voting members aggregating at least
60% of the number of votes
<PAGE>
-102-
which the members in attendance at a meeting at which a quorum is
present are entitled to cast. A majority of the voting members at any
time shall constitute a quorum.
10.5 Alternates. The ISO or a Participant or group of Participants may
----------
designate, by a written notice delivered to the Secretary of the
Regional Market Operations Committee, an alternate for any member of
the Regional Market Operations Committee appointed by the ISO or such
Participant or group of Participants. In the absence of the member, the
alternate shall have all of the powers of the member, including the
power to vote.
10.6 Officers. At its annual meeting, the Regional Market Operations
--------
Committee shall elect from its voting members a Chair and a Vice-Chair;
it shall also elect a Secretary who need not be a member. These
officers shall have the powers and duties usually incident to such
offices.
10.7 Meetings. The Regional Market Operations Committee shall hold its
--------
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Regional Market Operations Committee or at
the call of the Chair. Any two members may call a special meeting of
the Regional Market Operations Committee in the event that the Chair
shall
<PAGE>
-103-
fail to call such a meeting within three business days following the
Chair's receipt from such members of a request specifying the subject
matters to be acted upon at the meeting. In the event of emergency, any
member may call a special meeting of the Regional Market Operations
Committee to be held forthwith. Any annual, special or other meeting of
the Regional Market Operations Committee may be conducted by means of
conference telephone or other communications equipment by means of
which all persons participating in the meeting can hear each other.
10.8 Notice of Meetings. Written notice of each meeting of the Regional
-------------------
Market Operations Committee shall be given to each member not less than
three business days prior to the date of the meeting. The notice shall
normally specify the principal subject matters expected to be acted
upon; provided, however, that no written notice shall be required for a
meeting called in the event of an emergency, although the Secretary or
the member calling the meeting shall use his or her best efforts to
notify every member of the meeting.
10.9 Notice to Members of Management Committee. Prior to the end of the
---------------------------------------------
fifth business day following a meeting of the Regional Market
Operations Committee, the Secretary of the Regional Market Operations
Committee shall give written notice to the ISO and
<PAGE>
-104-
each member of the Management Committee of any action taken by the
Regional Market Operations Committee at such meeting.
10.10 Appeal of Actions to Management Committee. The ISO or any Participant
------------------------------------------
may appeal to the Management Committee any action taken by the Regional
Market Operations Committee. Such an appeal shall be taken prior to the
end of the tenth business day following the meeting of the Regional
Market Operations Committee to which the appeal relates by giving to
the Secretary of the Management Committee a signed and written notice
of appeal and by mailing a copy of the notice to the ISO and each
member of the Management Committee. Pending action on the appeal by the
Management Committee, the filing of a notice of appeal as aforesaid
shall suspend the action appealed from.
10.11 Appointment of Task Forces. The Regional Market Operations Committee
--------------------------
shall have the authority, within its budget or with the approval of the
Management Committee if beyond its budget, to appoint task forces for
particular studies and may name thereto available employees of
Participants.
<PAGE>
-105-
10.12 Consultants, Computer Time and Expenses. The Regional Market Operations
---------------------------------------
Committee shall have the authority, within its budget or with the
approval of the Management Committee if beyond its budget, to retain
the services of the ISO, to hire consultants, to procure computer time,
and to incur such expenses as may be required to enable the Regional
Market Operations Committee and its task forces properly to perform
their duties.
10.13 Responsibilities. The Regional Market Operations Committee, in
----------------
conjunction with the ISO and the Regional Transmission Operations
Committee, as appropriate, shall be responsible for the following:
(a) until the ISO is activated, supervising the
scheduling and coordination of the day-to-day
operations of the Participants' supply and
demand-side resources and transmission facilities and
their arrangements with Non-Participants;
(b) making or causing to be made, from time to time,
necessary studies and establishing or approving
procedures based thereon to assure the reliable
<PAGE>
-106-
operation and facilitate the efficient operation of
the NEPOOL Control Area bulk power supply;
(c) performing the following: (i) coordinating studies
of, and providing information to Participants on,
maintenance schedules for the supply and demand-side
resources and transmission facilities of the
Participants, (ii) until the ISO is activated,
establishing or approving maintenance schedules for
the supply and demand-side resources and transmission
facilities of the Participants and, to the extent
necessary, standards for durations for maintenance of
the supply and demand-side resources of the
Participants, and (iii) adopting and implementing
uniform rules or procedures, until the Second
Effective Date, for determining when a generating
unit's outages for maintenance shall be approved for
Scheduled Outage Service and for determining whether
the applicable Capability for a unit to be used in
determining the amount of a Participant's Scheduled
Outage Service shall be the unit's Reserve Capability
or its Temporary Reserve Capability;
<PAGE>
-107-
(d) until the ISO is activated, supervising the
maintenance and operation of the NEPOOL control
center;
(e) to the extent appropriate to assure the reliable
operation of the bulk power supply of NEPOOL
establishing or approving reasonable standards,
criteria and rules relating to protective equipment,
switching, voltage control, load shedding, emergency
and restoration procedures, and the operation and
maintenance of supply and demand-side resources and
transmission facilities of the Participants;
(f) determining the seasonal capabilities of each
electric generating unit or combination of units in
which a Participant has an Entitlement in a uniform
manner applying generally accepted engineering
principles;
(g) determining as appropriate from time to time the
current Annual Peak, Adjusted Annual Peak, Monthly
Peak, Adjusted Monthly Peak, Installed Capability
Responsibility, Operable Capability Requirements, and
obligations for Energy, Operating Reserve and AGC of
each Participant;
<PAGE>
-108-
(h) until the Second Effective Date, determining the
Incremental Costs and Decremental Costs for each
generating unit in which a Participant has an
Entitlement under the varying circumstances affecting
such costs;
(i) establishing or approving market operation rules
governing the submission of Bid Prices and the
determination of prices for Installed Capability,
Operable Capability, Energy, each category of
Operating Reserve and AGC, and establishing or
approving appropriate billing procedures for
transactions pursuant to this Agreement; and
(j) calculating and equitably apportioning losses
incurred in connection with Interchange Transactions.
10.14 Further Powers and Duties. The Regional Market Operations Committee
-------------------------
shall have such further powers and duties as may be prescribed by the
Management Committee or as set forth in this Agreement.
10.15 Development of Rules Relating to Non-Participant Supply and Demand-side
-----------------------------------------------------------------------
Resources. It is recognized that arrangements between Participants an
---------
Non-Participants with
<PAGE>
-109-
respect to the Non-Participants' supply and demand-side resources may
create special problems in the application of Sections 12 and 14.
Accordingly, the Regional Market Operations Committee shall analyze
such special problems and develop appropriate rules for reflecting such
resources in the Installed or Operable System Capability of a
Participant which enters into such an arrangement and for the treatment
of such arrangements for Energy, Operating Reserve and AGC purposes.
Upon approval by the Regional Market Operations Committee, such rules
shall supersede the provisions of Sections 12 and 14 (and the related
definitions in Section 1) to the extent of any conflict therewith.
10.16 Joint Meetings with Regional Transmission Operations Committee. The
-----------------------------------------------------------------
Regional Market Operations Committee is authorized and encouraged to
hold its meetings, and to conduct studies and exercise its
responsibilities, jointly with the Regional Transmission Operations
Committee to the extent appropriate.
<PAGE>
-110-
SECTION 11
REGIONAL TRANSMISSION OPERATIONS COMMITTEE
------------------------------------------
11.1 Organization. There shall be a Regional Transmission Operations
------------
Committee which shall be responsible for monitoring the operation of
NEPOOL transmission and the administration of the Tariff.
11.2 Membership. The Regional Transmission Operations Committee shall be
----------
constituted as follows: following its activation, the ISO shall have
the right to appoint a non-voting member of the Committee; each
Participant whose Voting Share equals or exceeds 3% of the aggregate
Voting Shares of all Participants shall have the right to appoint one
voting member of the Committee; the remaining Participants whose Voting
Shares are less than 3% of the aggregate Voting Shares of all
Participants shall be divided into the following five groups, with each
having the right to appoint one voting member of the Committee:
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owned
traditional utilities;
<PAGE>
-111-
(b) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in the business of owning or
operating generation facilities and selling the
output of such generation;
(c) One group consisting of the remaining Participants
which are not subject to traditional utility rate
regulation and which are engaged in the NEPOOL
Control Area principally in a business other than the
business of owning or operating PTF or generation
facilities and selling the output of such generation;
(d) One group consisting of the remaining Participants,
if any, which (i) own PTF, (ii) are not engaged in
electric generation or distribution and do not
participate in the wholesale bulk power market, and
(iii) are not Related Persons of any other
Participant; and
(e) One group consisting of the remaining Participants
which are investor-owned utilities subject to
traditional utility rate regulation or other
<PAGE>
-112-
Entities which do not qualify to be included in any
of the other four groups.
Notwithstanding the foregoing, any such Participant may elect to join a
different group than the one to which it would be assigned under the
foregoing provisions if this is acceptable to the members of the group
it elects to join. In the event any such Participant is a Related
Person of another Participant which has the individual right to appoint
a member of the Committee, the Participant shall be represented in the
Committee by the member appointed by the Participant which is its
Related Person and shall not be assigned to any of the five groups.
11.3 Terms of Members. The member of the Regional Transmission Operations
----------------
Committee appointed by the ISO shall serve until replaced by the ISO.
Other members of the Regional Transmission Operations Committee shall
serve until replaced by the Participant or Participants which appointed
them or until such Participant or Participants cease to be Participants
or otherwise lose the right to appoint the member. Appointment or
replacement of a member shall be effected by the ISO or a Participant
or group of Participants by giving written notice of such appointment
or replacement to the Secretary of the Regional Transmission Operations
Committee.
<PAGE>
-113-
11.4 Voting. Each voting member of the Regional Transmission Operations
------
Committee shall have one vote, which may be cast in person by the
member or the member's alternate or by another person pursuant to a
written proxy dated not more than one year previous to the meeting and
delivered to the Secretary of the Regional Transmission Operations
Committee at or prior to the meeting at which the proxy vote is cast.
If a Participant which has the individual right to appoint a member of
the Regional Transmission Operations Committee both participates in the
wholesale bulk power market and owns PTF, the member appointed by the
Participant shall be entitled to divide the member's vote on the basis
specified in a notice given by it to the Secretary of the Committee at
or prior to the meeting at which the vote is to be cast, to reflect its
market and transmission interests. In such case the portion of the
member's vote reflecting its transmission interest may be cast by the
member's alternate.
The voting member appointed by a group may divide the member's vote on
the basis specified in a notice given by it to the Secretary of the
Committee at or prior to the meeting at which the vote is to be cast,
to reflect the different positions of the members of the group.
<PAGE>
-114-
The adoption of actions by the Regional Transmission Operations
Committee shall require affirmative votes of voting members aggregating
at least 60% of the number of votes which the members in attendance at
a meeting at which a quorum is present are entitled to cast. A majority
of the voting members at any time shall constitute a quorum.
11.5 Alternates. The ISO or a Participant or group of Participants may
----------
designate, by a written notice delivered to the Secretary of the
Regional Transmission Operations Committee, an alternate for any member
of the Regional Transmission Operations Committee appointed by the ISO
or such Participant or group of Participants. In the absence of the
member, the alternate shall have all of the powers of the member,
including the power to vote.
11.6 Officers. At its annual meeting, the Regional Transmission Operations
--------
Committee shall elect from its voting members a Chair and a Vice-Chair;
it shall also elect a Secretary who need not be a member. These
officers shall have the powers and duties usually incident to such
offices.
<PAGE>
-115-
11.7 Meetings. The Regional Transmission Operations Committee shall hold its
--------
annual meeting in December or January at such time and place as the
Chair shall designate and shall hold other meetings in accordance with
a schedule adopted by the Regional Transmission Operations Committee or
at the call of the Chair. Any two members may call a special meeting of
the Regional Transmission Operations Committee in the event that the
Chair shall fail to call such a meeting within three business days
following the Chair's receipt from such members of a request specifying
the subject matters to be acted upon at the meeting. In the event of
emergency, any member may call a special meeting of the Regional
Transmission Operations Committee to be held forthwith. Any annual,
special or other meeting of the Regional Transmission Operations
Committee may be conducted by means of conference telephone or other
communications equipment by means of which all persons participating in
the meeting can hear each other.
11.8 Notice of Meetings. Written notice of each meeting of the Regional
-------------------
Transmission Operations Committee shall be given to each member not
less than three business days prior to the date of the meeting. The
notice shall normally specify the principal subject matters expected to
be acted upon; provided, however, that no written notice shall be
required for a meeting called in the event of an emergency, although
the Secretary or
<PAGE>
-116-
the member calling the meeting shall use his or her best efforts to
notify every member of the meeting.
11.9 Notice to Members of Management Committee. Prior to the end of the
---------------------------------------------
fifth business day following a meeting of the Regional Transmission
Operations Committee, the Secretary of the Regional Transmission
Operations Committee shall give written notice to the ISO and each
member of the Management Committee of any action taken by the Regional
Transmission Operations Committee at such meeting.
11.10 Appeal of Actions to Management Committee. The ISO or any Participant
------------------------------------------
may appeal to the Management Committee any action taken by the Regional
Transmission Operations Committee. Such an appeal shall be taken prior
to the end of the tenth business day following the meeting of the
Regional Transmission Operations Committee to which the appeal relates
by giving to the Secretary of the Management Committee a signed and
written notice of appeal and by mailing a copy of the notice to the ISO
and each member of the Management Committee. Pending action on the
appeal by the Management Committee, the filing of a notice of appeal as
aforesaid shall suspend the action appealed from.
<PAGE>
-117-
11.11 Appointment of Task Forces. The Regional Transmission Operations
-----------------------------
Committee shall have the authority, within its budget or with the
approval of the Management Committee if beyond its budget, to appoint
task forces for particular studies and may name thereto available
employees of Participants.
11.12 Consultants, Computer Time and Expenses. The Regional Transmission
------------------------------------------
Operations Committee shall have the authority, within its budget or
with the approval of the Management Committee if beyond its budget, to
retain the services of the ISO, to hire consultants, to procure
computer time, and to incur such expenses as may be required to enable
the Regional Transmission Operations Committee and its task forces
properly to perform their duties.
11.13 Responsibilities. The Regional Transmission Operations Committee, in
----------------
conjunction with the ISO and the Regional Market Operations Committee,
as appropriate, shall be responsible for the following:
(a) until the ISO is activated, overseeing the scheduling
and coordination of the day-to-day operations of the
Participants' supply and demand-side resources and
transmission facilities;
<PAGE>
-118-
(b) making or causing to be made, from time to time,
necessary studies and establishing or approving
procedures based thereon to assure the reliable
operation and facilitate the efficient operation of
the NEPOOL Control Area bulk power supply;
(c) coordinating studies of, and providing information to
Participants on, maintenance schedules for the supply
and demand-side resources and transmission facilities
of the Participants; and, until the ISO is activated,
establishing or approving procedures for scheduling
the maintenance of the supply and demand-side
resources and transmission facilities of the
Participants;
(d) to the extent appropriate to assure the reliable
operation of the bulk power supply of the NEPOOL
Control Area, establishing or approving reasonable
standards, criteria and rules relating to protective
equipment, switching, voltage control, load shedding,
emergency and restoration procedures, and the
operation and maintenance of supply and demand-side
resources and transmission facilities of the
Participants;
<PAGE>
-119-
(e) establishing or approving appropriate billing
procedures for transmission service pursuant to this
Agreement and the Tariff; and
(f) until the ISO is activated, establishing procedures
for, and thereafter monitoring, the administration of
the Tariff and the reservation of transmission
capacity pursuant to the Tariff.
11.14 Further Powers and Duties. The Regional Transmission Operations
----------------------------
Committee shall have such further powers and duties as may be
prescribed by the Management Committee or as set forth in this
Agreement.
11.15 Joint Meetings with Regional Market Operations Committee. The Regional
--------------------------------------------------------
Transmission Operations Committee is authorized and encouraged to hold
its meetings, and to conduct studies and exercise its responsibilities,
jointly with the Regional Market Operations Committee to the extent
appropriate.
<PAGE>
-120-
PART THREE
MARKET PROVISIONS
SECTION 12
INSTALLED CAPABILITY AND OPERABLE CAPABILITY
--------------------------------------------
OBLIGATIONS AND PAYMENTS
------------------------
12.1 Obligations to Provide Installed Capability and Operable Capability.
-------------------------------------------------------------------
(a) Each Participant shall have Installed System Capability during
each hour of each month at least sufficient to satisfy its
Installed Capability Responsibility for the month.
(b) Each Participant shall have Operable System Capability in each
hour at least sufficient to satisfy its Operable Capability
Requirement for such hour.
<PAGE>
-121-
12.2 Computation of Installed Capability Responsibilities.
----------------------------------------------------
(a) (1) At the conclusion of each month, the Regional
Market Operations Committee shall determine each
Participant's tentative Installed Capability
Responsibility in Kilowatts for such month in
accordance with the following formula:
X = (P(A-N)+Np)(1+T) + OTA
As used in this Section 12.2(a)(1), the symbols used
in the formula and the additional symbols defined
below have the following meanings:
X is the Participant's tentative Installed
Capability Responsibility for the month.
P is the value of the Participant's fraction
for the month as determined in accordance
with the following formula:
P = Fp/F, wherein:
<PAGE>
-122-
Fp is the Participant's Adjusted
Monthly Peak for the month.
F is the aggregate for the month of
the Adjusted Monthly Peaks for all
Participants.
A is the NEPOOL Objective Capability in
megawatts for the month as fixed by the
Management Committee pursuant to Section
6.14(e).
N is the aggregate of the New Unit Adjustments
for all Participants for the month as
determined by the Regional Market Operations
Committee in accordance with Section
12.2(a)(2).
Np is the aggregate of the Participant's New
Unit Adjustments for the month, as
determined by the Regional Market Operations
Committee, and is equal to the aggregate of
the Participant's adjustments for each New
Unit included in its Installed System
Capability during the hour of the coincident
peak load of the Participants for the month.
The Participant's adjustment for each
<PAGE>
-123-
New Unit may be positive or negative and
shall be the product of (i) the
Participant's Installed Capability
Entitlement in the New Unit during the hour
of the coincident peak load of the
Participants for the month, times (ii) the
New Unit Adjustment Factor applicable to the
New Unit as determined in accordance with
Section 12.2(a)(2).
OTA is the Participant's Outside Transaction
Adjustment for the month for all interfaces
as determined in accordance with Section
12.2(a)(3).
T is the Participant's Unit Availability
Adjustment Factor for the month. T may be
positive or negative and shall be determined
in accordance with the following formula:
T = (I-H) x J x R, wherein:
------------
100
I for the Participant for the month is the
percentage which represents the weighted
average (using the Installed Capability of
<PAGE>
-124-
each Installed Capability Entitlement for
such month for the weighting) of the Four
Year Installed Capability Target
Availability Rates of the Installed
Capability Entitlements which are included
in the Participant's Installed System
Capability during the hour of the coincident
peak load of the Participants for the month.
The Four Year Target Availability Rate for
an Installed Capability Entitlement for any
month is the average of the monthly Target
Availability Rates for the forty-eight
months which comprise the period of four
consecutive calendar years ending within the
Power Year which includes such month, as
determined on the basis of the Target
Availability Rates for each of the
forty-eight months, and as applied on a
basis which is consistent with the fuel or
maturity status of the unit for each of the
forty-eight months. The Target Availability
Rates shall be those utilized by the
Management Committee in its most recent
determination of NEPOOL Objective Capability
pursuant to Section 6.14(e).
<PAGE>
-125-
H for the Participant for the month is the
percentage which represents the weighted
average (using the Installed Capability of
each Installed Capability Entitlement for
such month for the weighting) of the Four
Year Actual Availability Rates of the
Installed Capability Entitlements which are
included in the Participant's Installed
System Capability during the hour of the
coincident peak load of the Participants for
the month. The Four Year Actual Availability
Rate for an Installed Capability Entitlement
for any month is the percentage which
represents the average of the amounts
determined for H1 for the four applicable
Twelve-Month Measurement Periods within the
forty-eight months which comprise the period
of four consecutive calendar years ending
within the Power Year which includes such
month. A Twelve-Month Measurement Period is
a period of twelve sequential months. For
purposes of this sequence, the first month
in the four years and the immediately
succeeding months shall be considered to
follow the forty-eighth month in the four-
year period. The four applicable
Twelve-Month Measurement Periods to be used
in the determination of H1 for an Installed
<PAGE>
-126-
Capability Entitlement shall be the four
sequential Twelve-Month Measurement Periods
out of the twelve possible combinations
which yield the highest H1.
H1 for an Installed Capability Entitlement in a
unit or combination of units for a
Twelve-Month Measurement Period is its
Actual Availability Rate. The Actual
Availability Rate of an Installed Capability
Entitlement for a Twelve-Month Measurement
Period is a percentage and shall be the
greater of:
(i) the percentage of (a) the amount of
generation which could have been
received with respect to the
Installed Capability Entitlement if
the unit or combination of units had
been fully available at its full
Installed Capability throughout the
Twelve-Month Measurement Period,
which is represented by (b) the
amount of generation which was
actually available during such
period, or
<PAGE>
-127-
(ii) the average Target Availability Rate
expressed as a percentage for the
Installed Capability Entitlement for
the Twelve-Month Measurement Period
less twenty percentage points. The
average Target Availability Rate of
an Installed Capability Entitlement
for a Twelve-Month Measurement
Period is a percentage and is the
average of the monthly Target
Availability Rates for the months
which comprise the Twelve-Month
Measurement Period, as determined on
the basis of the Target Availability
Rates for each of the twelve months,
and as applied on a basis which is
consistent with the fuel or maturity
status of the unit or combination of
units for each month in the
Twelve-Month Measurement Period. The
Target Availability Rates shall be
those utilized by the Management
Committee in its most recent
determination of NEPOOL Objective
Capability pursuant to Section
6.14(e).
<PAGE>
-128-
J for the month is the estimated percentage
point change in NEPOOL Objective Capability
which would be required as a result of a one
percentage point change in the weighted
average equivalent availability rate of the
generating units in which the Participants
have Installed Capability Entitlements. The
value for J shall be adopted by the
Management Committee each time it fixes
NEPOOL Objective Capability pursuant to
Section 6.14(e).
R for the month is the phase-out factor for
the month, which shall be as follows:
R=0.75 for the Power Year beginning
November 1, 1997.
R=0.50 for the Power Year beginning
November 1, 1998.
R=0.25 for the Power Year beginning
November 1, 1999.
R=0 for the Power Year beginning
November 1, 2000 and all
subsequent Power Years.
(2) A New Unit Adjustment Factor for a New Unit shall be
determined to assign the effects of the New Unit on
NEPOOL Objective Capability to
<PAGE>
-129-
those Participants with Entitlements in the New Unit.
The New Unit Adjustment Factor for each New Unit for
each month shall be determined by the Regional Market
Operations Committee in accordance with the following
formula:
n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) + K5(f-F)c2)
As used in this Section 12.2(a)(2), the symbols used
in the formula have the following meanings:
R is the phase out factor as defined in
Section 12.2(a)(1) above.
n is the New Unit Adjustment Factor, expressed
as a fraction, for the month for a New Unit.
c is the Winter Capability of the New Unit.
C is the Winter Capability of the Proxy Unit,
which shall be the number of Kilowatts, as
determined by the Management
<PAGE>
-130-
Committee, which would result in the NEPOOL
Objective Capability being approximately the
same if the generating units in which the
Participants have Installed Capability
Entitlements were all units possessing Proxy
Unit characteristics.
f is the equivalent forced outage rate of the
New Unit, expressed as a fraction of a year,
utilized in the determination by the
Management Committee of NEPOOL Objective
Capability for the month.
F is the equivalent forced outage rate of the
Proxy Unit. F, a fraction, shall be the
weighted average equivalent forced outage
rate (using the Winter Capability of each
generating unit for such weighting) of the
generating units in which the Participants
have Installed Capability Entitlements,
adjusted to compensate for the rounding of
the annual maintenance outage requirement of
the Proxy Unit.
<PAGE>
-131-
m is the four-year average annual maintenance
outage requirement of the New Unit,
expressed as a fraction of a year. The data
used to determine m shall include the annual
maintenance outage requirements for the
current Power Year and the next three Power
Years, as utilized for the New Unit in the
most recent determination by the Management
Committee of NEPOOL Objective Capability
pursuant to Section 6.14(e).
M is the annual maintenance outage requirement
of the Proxy Unit. M shall be a fraction,
the numerator of which shall be the number
of weeks (rounded to the nearest full
number) that most closely approximates the
weighted four-year average annual
maintenance outage requirement (using the
Winter Capability of each generating unit
for such weighting) for the generating units
in which the Participants have Installed
Capability Entitlements, and the denominator
of which shall be 52 weeks.
d is the summer derating of the New Unit,
expressed as a fraction of the Winter
Capability of the New Unit.
<PAGE>
-132-
D is the summer derating of the Proxy Unit. D
shall be a fraction and shall be equal to
the weighted average fractional summer
derating (using the Winter Capability of
each generating unit for such weighting) of
the generating units in which the
Participants have Installed Capability
Entitlements.
K1, K2, K3, K4, and K5
are conversion coefficients for each of the
Summer and Winter Periods, determined by
regression analysis such that the product
for the Installed Capability of a New Unit
times its New Unit Adjustment Factor
approximates the effect on NEPOOL Objective
Capability of the New Unit.
Proxy Unit characteristics and conversion
coefficients contained in the formula shall be
adopted by the Management Committee and reviewed
every five years (or more frequently if the
Management Committee determines that exceptional
circumstances require an earlier review) and revised
as necessary.
<PAGE>
-133-
If a New Unit has unique characteristics affecting
NEPOOL Objective Capability which are not adequately
reflected in the New Unit Adjustment Factor formula,
the Management Committee shall determine for such New
Unit a New Unit Adjustment Factor which accounts for
the New Unit's unique characteristics.
The New Unit Adjustment Factor for any Restricted
Unit (as defined in Section 15.37B of the Prior
NEPOOL Agreement) for which proposed plans were
submitted subsequent to November 1, 1990 for review
pursuant to Section 18.4 or its predecessor section
in the Prior NEPOOL Agreement (or, in the case of a
unit with a rated capacity of less than 5MW, for
which notification was first given to NEPOOL
subsequent to November 1, 1990) and for the Peabody
Municipal Light Plant's Waters River #2 unit shall be
determined in accordance with the formula previously
specified in Section 12.2(a)(2), modified as follows:
n = R(K1(c-C) + K2(f-F) + K3(m-M) + K4(d-D) +
K5(f-F)c2) + K6(2500-a)
<PAGE>
-134-
The symbols used in the above formula, as modified,
shall have the meanings previously specified, except
that the symbols "K6" and "a" shall have the
following meanings:
K6 is a scaling factor of 0.0001.
a is as follows:
for units with more than 2500 annual hours
available for operation, "a" = 2500,
for units with annual hours available for
operation between 500 and 2500, inclusive,
"a" = annual hours available for operation,
and
for units with annual hours available for
operation less than 500 hours, "a" = -7500;
<PAGE>
-135-
provided, however, that a Participant may elect to
-------- -------
avoid, in whole or part, the effect on its Installed
Capability Responsibility of a Restricted Unit's
availability being limited to 2500 hours or less a
year by agreeing to leave unfilled a portion of its
dispatchable load allocation in accordance with rules
adopted by the Regional Market Operations Committee.
(3) An Outside Transaction Adjustment (OTA) shall be
determined for each Participant for each month to
assign to the Participant the net impact on
reliability in the NEPOOL Control Area of its uses in
the month of each interface with a neighboring
control area other than the HQ Interconnection which
is addressed in the definitions in Part One through
the use of transfer credits and related adjustments.
When the Management Committee determines the NEPOOL
Objective Capability for the month, it reduces the
required NEPOOL Objective Capability by taking into
account the reliability benefits of available
transmission capacity in interfaces with these
neighboring control areas. If the Participant engages
in transactions across the interfaces ("External
Transactions"), the result is an increase or decrease
in the reliability
<PAGE>
-136-
benefits to the entire region of such interfaces. As
a result, in order to maintain the same level of
reliability in the NEPOOL Control Area, the minimum
required NEPOOL Installed Capability must be
increased or decreased, as appropriate. The OTA is
designed so that any such increases or decreases in
the minimum required NEPOOL Installed Capability
which result from External Transactions are assigned
to the Participants engaged in such Transactions. To
calculate the OTA, the External Transactions are
divided into two broad types of Transactions: (1)
Transactions that were entered into prior to December
1, 1996, (a) with the New York Power Authority (NYPA)
to purchase preference power produced by the Niagara
and St. Lawrence hydroelectric projects or by Vermont
utilities with Hydro-Quebec and NYPA using the New
York PV-20 line to import up to 105 megawatts during
the May through October time period and 140 megawatts
during the November through April time period or (b)
by Vermont utilities under contracts with New York
State Electric & Gas Corporation or Niagara Mohawk
Power Corporation, but no extension thereof not
expressly provided for in the contract as in effect
on December 1, 1996, provided that the transactions
under such contracts shall be subject, together with
the other Vermont
<PAGE>
-137-
utility transactions identified in clause (a), to the
105 megawatt and 140 megawatt limits specified in
clause (a), or (c) by Central Maine Power Company to
purchase for a period ending no later than January 1,
2010 the output of the generating unit in northern
Maine owned by its AVEC subsidiary (collectively,
"Grandfathered Imports"); and (2) all other External
Transactions ("Other External Transactions").
At the conclusion of each month, the System Operator
shall identify all of the Participants that engaged
in Grandfathered Imports and Other External
Transactions for the month. For each Participant, the
System Operator shall determine an OTA in accordance
with the following formula:
OTA = [OCg x (GIi/GI)] + [OCo x (IPi/NP)] - [OCo x (XPi/NP)],
wherein
OTA is the Participant's Outside Transaction
Adjustment for the month;
<PAGE>
-138-
OCg is the increase in NEPOOL Objective
Capability for the month in Kilowatts that
would have resulted, from the Grandfathered
Imports, if there were no Other External
Transactions for the month;
GIi is the amount in Kilowatts of the
Participant's Grandfathered Imports for the
month that qualify as Installed Capability
Entitlements for the Participant;
GI is the aggregate in Kilowatts of all
Participants' Grandfathered Imports for the
month that qualify as Installed Capability
Entitlements;
OCo is the increase, if any, in NEPOOL Objective
Capability for the month in Kilowatts that
resulted, after taking into account
Grandfathered Imports, from the net imports
of all Participants that were net importers
in the month under Other External
Transactions, minus the net exports of all
Participants that were net exporters for the
month under Other External Transactions;
<PAGE>
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IPi is the amount, if any, in Kilowatts of
Installed Capability of the
Participant's net imports for the month
under Other External Transactions;
NP is the aggregate in Kilowatts for the month
for all Participants that were net importers
under Other External Transactions of their
net imports of Installed Capability under
Other External Transactions, minus the
-----
aggregate in Kilowatts for the month for all
Participants that were net exporters under
Other External Transactions of their net
exports of Installed Capability Entitlements
under Other External Transactions; and
XPi is the amount, if any, in Kilowatts of
Installed Capability of the Participant's
net exports for the month under Other
External Transactions.
If NP is zero or negative for a month, the second and
third bracketed terms, which both relate to OCo,
shall be equal to zero and the
<PAGE>
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Participant's OTA for the month shall be affected
only by its Grandfathered Imports, if any.
(b) The tentative Installed Capability Responsibilities of the
Participants for any month, as determined in accordance with
Section 12.2(a), shall be adjusted in accordance with this
Section 12.2(b) in the event the value of H for any
Participant for any of the Twelve-Month Measurement Periods
applicable to the Participant for the month is increased in
accordance with Section 12.2(a) because of the application of
paragraph (ii) of the definition of H1. In such event the
Regional Market Operations Committee shall determine each
Participant's tentative Installed Capability Responsibility
for the month with and without the application of said
paragraph (ii). The difference between the sum of all
Participants' tentative Installed Capability Responsibilities,
with and without the application of said paragraph (ii) for
the month, shall be added to the tentative Installed
Capability Responsibilities of the Participants, as determined
in accordance with Section 12.2(a), in proportion to said
tentative Installed Capability Responsibilities, thereby
establishing each Participant's adjusted tentative Installed
Capability Responsibility for the month.
<PAGE>
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(c) For each month, the Regional Market Operations Committee shall
determine the sum of all Participants' adjusted tentative
Installed Capability Responsibilities, as initially determined
in accordance with Section 12.2(a) and as adjusted in
accordance with Section 12.2(b), if Section 12.2(b) is
applicable for such month. If the sum is less than, or equal
to, the minimum NEPOOL Installed Capability during the month,
then the adjusted tentative Installed Capability
Responsibility as determined pursuant to Section 12.2(a) or
12.2(b), whichever is applicable, for each Participant is the
final Installed Capability Responsibility for each
Participant. If the sum is greater than such minimum NEPOOL
Installed Capability, then each Participant's final Installed
Capability Responsibility shall be its adjusted tentative
Installed Capability Responsibility as determined pursuant to
Section 12.2(a) or 12.2(b), whichever is applicable,
multiplied by the ratio of the minimum NEPOOL Installed
Capability during the month to the sum of the adjusted
tentative Installed Capability Responsibilities for the month.
(d) It is recognized that the treatment of fuel conversions, dual
fuel units, immature units, new Installed Capability
Entitlements, cogeneration and small power-producing
facilities, Unit Contracts and other contract arrangements,
units with
<PAGE>
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unusual maintenance cycles, and various other matters can
result in special problems in the determination of Unit
Availability Adjustment Factors and New Unit Adjustments.
Accordingly, the Regional Market Operations Committee shall
analyze such special problems and develop appropriate market
operation rules to be applied in taking such matters into
account in the determination of Unit Availability Adjustment
Factors and New Unit Adjustments.
12.3 Computation of Operable Capability Requirements.
-----------------------------------------------
For each hour, the Regional Market Operations Committee shall determine
each Participant's Operable Capability Requirement in Kilowatts in
accordance with the following formula:
OPp = ELp + ORp
As used in this Section 12.3, the symbols used in the formula have the
following meanings:
OPp is the Participant's Operable Capability Requiremen
for the hour.
<PAGE>
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ELp is the Participant's Electrical Load during the hour.
ORp is the amount (in Kilowatts) of Operating Reserve
which the Participant was required to provide during
the hour, as determined in accordance with Section
14.1(b).
12.4 Bids to Furnish Installed Capability or Operable Capability. Each
----------------------------------------------------------------
Participant shall submit to or have on file with the System Operator,
in accordance with the market operation rules approved by the Regional
Market Operations Committee, one or more bids specifying the Bid Price
and Kilowatt amount at which it will furnish any and all surplus
Installed System Capability for a month or Operable System Capability
for an hour through NEPOOL to other Participants. If no bid is
submitted for a month for any surplus Installed System Capability or
for any hour for any surplus Operable System Capability, the Bid Price
for any such surplus for which there are no bids shall be deemed to be
zero.
12.5 Consequences of Deficiencies in Installed Capability Responsibility.
-------------------------------------------------------------------
<PAGE>
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(a) At the conclusion of each month, the System Operator shall
determine whether each Participant has satisfied its Installed
Capability Responsibility obligation for the month. If the
minimum monthly Installed System Capability of a Participant
during the month was less than its Installed Capability
Responsibility, the number of Kilowatts of its deficiency
shall be computed and the Participant shall be deemed to
purchase from other Participants through NEPOOL Kilowatts of
surplus Installed System Capability equal to the amount
of its deficiency and shall pay to NEPOOL for the month any
applicable fees for services assessed pursuant to Section 19.2
plus the product of its total Kilowatts of deficiency and the
----
Installed Capability Clearing Price for the month
determined in accordance with Section 12.5(b). For purposes
of this Section 12, the minimum monthly Installed System
Capability of a Participant for a month is the Participant's
lowest Installed System Capability for any hour during the
month. Retirements made on the last day of any month shall
not be deducted from Installed System Capability for that
month.
(b) At the end of each month, the System Operator shall determine
the Installed Capability Clearing Price for the month as
follows:
<PAGE>
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(i) The System Operator shall determine the aggregate
Kilowatt shortage of Installed System Capability for
the month for all Participants that did not satisfy
their Installed Capability Responsibilities for that
month.
(ii) The System Operator shall rank in the order of lowest
to highest Bid Price all Bid Prices received from
Participants having excess Installed System
Capability for the month.
(iii) For each Participant, its Installed System Capability
with the lowest Bid Prices shall be deemed to have
been furnished first, to the extent required, to meet
its Installed Capability Responsibility. Any
remainder starting with the lowest Bid Prices shall
be deemed to have been furnished, to the extent
required, to other Participants under this Agreement
to meet their shortages of Installed System
Capability for the month.
(iv) The Installed Capability Clearing Price for the month
shall equal the highest Bid Price for Installed
System Capability that is deemed in
<PAGE>
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accordance with Section 12.5(b)(iii) to have been
furnished to another Participant for the month.
12.6 Consequences of Deficiencies in Operable Capability Requirements.
----------------------------------------------------------------
(a) For each hour, the System Operator shall determine whether
each Participant has satisfied its Operable Capability
Requirement obligation for that hour. If the minimum Operable
System Capability of a Participant during any hour was less
than its Operable Capability Requirement, the number of
Kilowatts of its deficiency shall be computed and the
Participant shall be deemed to purchase from other
Participants through NEPOOL Kilowatts of surplus Operable
System Capability equal to the amount of its deficiency and
shall pay for the hour any applicable uplift charge assessed
under Section 14.15 and any applicable fees for services
assessed pursuant to Section 19.2 plus the product of its
----
Kilowatt deficiency for the hour and the Operable Capability
Clearing Price for the hour determined in accordance with
Section 12.6(b). The minimum Operable System Capability of a
Participant for an hour is equal to the Participant's lowest
Operable System Capability at any time during the hour.
<PAGE>
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(b) For each hour, the System Operator shall determine the
Operable Capability Clearing Price as follows:
(i) The System Operator shall determine the aggregate
Kilowatt shortage of Operable System Capability for
the hour for all Participants that did not satisfy
their Operable Capability Requirements in that hour.
(ii) The System Operator shall rank in the order of lowest
to highest Bid Price all Bid Prices received from
Participants having excess Operable System Capability
for the hour.
(iii) For each Participant, its Operable System Capability
with the lowest Bid Prices shall be deemed to have
been furnished first, to the extent required, to meet
its Operable Capability Requirement. Any remainder
starting with the lowest Bid Prices shall be deemed
to have been furnished, to the extent required, to
other Participants under this Agreement to meet their
shortages of Operable System Capability for that
hour.
<PAGE>
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(iv) The Operable Capability Clearing Price for the hour
shall be equal to the highest Bid Price for Operable
System Capability that is deemed in accordance with
Section 12.6(b)(iii) to have been furnished to
another Participant in the hour.
12.7 Payments to Participants Furnishing Installed Capability and Operable
---------------------------------------------------------------------
Capability.
----------
(a) Participants that are deemed pursuant to Section 12.5 to
furnish any surplus in their Installed System Capability to
other Participants shall receive therefor their pro rata
shares on a Kilowatt basis of all payments made by
Participants for the month under Section 12.5, excluding any
applicable fees for services assessed pursuant to Section
19.2. If two or more Participants with excess Installed
System Capability have bid Kilowatts at the Installed
Capability Clearing Price, but not all the excess Installed
System Capability bid at such price is required to meet
shortages of Installed System Capability, then the excess
Installed System Capability bid at the Installed Capability
Clearing Price that each such Participant shall be deemed to
have furnished shall be the Kilowatts of excess Installed
System Capability bid by the Participant at that price
multiplied by the ratio of (i) the total Kilowatts of excess
----------
Installed System Capability bid at the
<PAGE>
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Installed Capability Clearing Price needed to meet the
shortages to (ii) the total Kilowatts of excess Installed
System Capability bid by all Participants at the Installed
Capability Clearing Price.
(b) Participants that are deemed pursuant to Section 12.6 to
furnish any surplus in their Operable System Capability to
other Participants shall receive therefor their pro rata
shares on a Kilowatt basis of all payments made by
Participants for the hour under Section 12.6, excluding any
applicable uplift charges assessed under Section 14.15 and any
applicable fees for services assessed pursuant to Section
19.2. If two or more Participants with excess Operable System
Capability in an hour have bid Kilowatts at the Operable
Capability Clearing Price, but not all the excess Operable
System Capability bid at such price is required to meet
shortages of Operable System Capability, then the excess
Operable System Capability bid at the Operable Capability
Clearing Price that each such Participant shall be deemed to
have furnished shall be the Kilowatts of excess Operable
System Capability bid by the Participant at that price
multiplied by the ratio of (i) the total Kilowatts of excess
----------
Operable System Capability bid at the Operable Capability
Clearing Price needed to meet
<PAGE>
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the shortages to (ii) the Kilowatts of excess Operable System
Capability bid by all Participants at the Operable Capability
Clearing Price.
SECTION 13
OPERATION, GENERATION, OTHER RESOURCES,
--------------------------------------
AND INTERRUPTIBLE CONTRACTS
---------------------------
13.1 Maintenance and Operation in Accordance with Good Utility Practice.
----------------------------------------------------------------------
Each Participant shall, to the fullest extent practicable, cause all
generating facilities and other resources owned or controlled by it to
be designed, constructed, maintained and operated in accordance with
Good Utility Practice.
13.2 Central Dispatch. Subject to the following sentence, each Participant
----------------
shall, to the fullest extent practicable, subject all generating
facilities and other resources owned or controlled by it to central
dispatch by the System Operator; provided, however, that each
Participant shall at all times be the sole judge as to whether or not
and to what extent safety requires that at any time any of such
facilities will be operated at less than full capacity or not at all.
Each Participant may remove from central dispatch a
<PAGE>
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generating facility or other resources owned or controlled by it if and
to the extent such removal is permitted by rules and standards approved
by the Management Committee.
13.3 Maintenance and Repair. Each Participant shall, to the fullest extent
----------------------
practicable: (a) cause generating facilities and other resources owned
or controlled by it to be withdrawn from operation for maintenance an
repair only in accordance with maintenance schedules reported to and
published by the System Operator from time to time in accordance with
procedures established or approved by the Regional Market Operations
Committee, (b) restore such facilities to good operating condition with
reasonable promptness, and (c) accelerate or delay maintenance and
repair at the reasonable request of the System Operator in accordance
with market operation rules approved by the Regional Market Operations
Committee.
13.4 Objectives of Day-to-Day System Operation. The day-to-day scheduling
------------------------------------------
and coordination through the System Operator of the operation of
generating units and other resources shall be designed to assure the
reliability of the bulk power system of the NEPOOL Control Area. Such
activity shall:
<PAGE>
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(a) satisfy the NEPOOL Control Area's Operating Reserve
requirements, including the proper distribution of
those Operating Reserves;
(b) satisfy the Automatic Generation Control requirements
of the NEPOOL Control Area; and
(c) satisfy the Energy requirements of all Electrical
Loads of the Participants.
all at the lowest practicable aggregate dispatch cost to the NEPOOL
Control Area in light of available Bid Prices and Participant-directed
schedules.
13.5 Satellite Membership. Each Participant which is responsible for th
--------------------
operation of transmission facilities rated 69 kV or above in the NEPOOL
Control Area or generating units and other resources which are subject
to central dispatch by NEPOOL, or which is responsible for implementing
voltage reduction and load shedding procedures in the NEPOOL Control
Area, shall become a member of the appropriate satellite dispatching
center; provided that by mutual agreement among the affected
Participants and the appropriate satellite, a Participant may be
excused from joining the
<PAGE>
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satellite if it has arranged with a satellite member to assume
responsibility to the satellite for its facilities or obligations.
SECTION 14
INTERCHANGE TRANSACTIONS
------------------------
14.1 Obligation for Energy, Operating Reserve and Automatic Generation
-----------------------------------------------------------------
Control.
-------
(a) Each Participant shall have for each hour an Energy obligation
equal to its Electrical Load plus the kilowatthours delivered
by such Participant pursuant to other Participants in the hour
pursuant to Firm Contracts or System Contracts, together with
any associated electrical losses.
(b) Each Participant shall have for each hour Operating Reserve
obligations equal to its share of the quantity of each
category of Operating Reserve required for the NEPOOL Control
Area in the hour.
<PAGE>
-154-
Subject to adjustment pursuant to Section 14.6, a
Participant's share of each category of Operating Reserve
required for any hour shall be determined in accordance with
the following formula:
ORp = SAp + [(OR-SA)(ELp/EL)], wherein
ORp is the Participant's share of that category
of Operating Reserve for the hour.
SAp is the number of Kilowatts, if any, of that
category of Operating Reserve for the hour
that the Regional Market Operations
Committee determines should be assigned
specifically to such Participant and not be
shared by all Participants.
OR is the aggregate number of Kilowatts of that
category of Operating Reserve determined by
the System Operator in accordance with the
directions of the Regional Market Operations
Committee to be required for the NEPOOL
Control Area for the hour that is not
assigned to Non-Participants.
<PAGE>
-155-
SA is the aggregate number of Kilowatts of that
category of Operating Reserve for the hour
that the Regional Market Operations
Committee determines should not be shared by
all Participants, but not including
Operating Reserve assigned to
Non-Participants.
ELp is the Participant's Electrical Load for the
hour.
EL is the sum of ELp for all Participants.
(c) Each Participant shall have for each hour an AGC obligation
equal to its share of AGC required for the NEPOOL Control Area
in the hour. Subject to adjustment pursuant to Section 14.6, a
Participant's share of AGC required for any hour shall be
determined in accordance with the following formula:
AGCp = AGC(ELp/EL), wherein
AGCp is the Participant's share of AGC for the hour.
<PAGE>
-156-
AGC is the total amount of AGC determined by the
System Operator in accordance with market
operation rules approved by the Regional
Market Operations Committee to be required
for the NEPOOL Control Area for the hour
that is not assigned to Non-Participants.
ELp and EL are as defined in Section 14.1(b).
14.2 Obligation to Bid or Schedule, and Right to Receive Energy, Operating
---------------------------------------------------------------------
Reserve and Automatic Generation Control.
----------------------------------------
(a) A Participant which has Energy Entitlements shall
submit to or have on file with the System Operator,
in accordance with the market operation rules
approved by the Regional Market Operations Committee,
one or more bids for the Energy Entitlements for
which the Participant is permitted to bid specifying
the Bid Price at which it will furnish Energy through
NEPOOL to other Participants under this Agreement or
to Non-Participants for ancillary services under the
Tariff, or pursuant to arrangements with
Non-Participants entered into under Section 14.6,
<PAGE>
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except to the extent such Entitlements are scheduled
by the Participant consistent with Section 14.2(d).
(b) A Participant which has Operating Reserve
Entitlements or AGC Entitlements shall also submit t
or have on file with the System Operator, in
accordance with the market operation rules approved
by the Regional Market Operations Committee, one or
more bids for each such Entitlement for which the
Participant is permitted to bid specifying the
Bid Prices at which it will furnish 10-Minute
Spinning Reserve, 10-Minute Non-Spinning Reserve,
30-Minute Operating Reserve and/or AGC through NEPOOL
to other Participants under this Agreement or to
Non-Participants for ancillary services under the
Tariff, except to the extent such Entitlements are
scheduled by the Participant consistent with
Section 14.2(d). Prior to the Third Effective Date,
Participants' rights and obligations to submit bids
for Operating Reserve Entitlements in 10-Minute
Spinning Reserve shall be limited to Entitlements in
hydroelectric generating units and pumped storage
hydroelectric generating units.
<PAGE>
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(c) Except as emergency circumstances may result in the
System Operator requiring load curtailments by
Participants, each Participant shall be entitled to
receive from the other Participants (or from the
service made available from Non-Participants pursuant
to arrangements entered into under Section 14.6) such
amounts, if any, of Energy, Operating Reserve, and
AGC as it requires and Non-Participants shall be
entitled to receive from Participants the amount of
ancillary services to which they are entitled
pursuant to the Tariff. If, for any hour, load
curtailments are required, the amount that
Participants and Non-Participants with shortages are
entitled to receive shall be proportionally reduced
by the System Operator in a fair and
non-discriminatory manner in light of the
circumstances.
(d) All Bid Prices for Entitlements shall be submitted in
accordance with market operation rules approved by
the Regional Market Operations Committee. If a Bid
Price is not submitted for any such Entitlement, the
Bid Price shall be deemed to be zero. For a
generating unit in which there are multiple
Entitlement holders, only one Participant shall be
permitted to submit Bid Prices for Energy, Operating
Reserve and/or
<PAGE>
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AGC Entitlements for such unit or to direct the
scheduling of the unit for any Scheduled Dispatch
Period. The Entitlement holders in each unit with
multiple Entitlement holders shall designate a single
Participant that will be permitted to submit Bid
Prices and/or to direct the scheduling of the unit.
In the event that more than one Participant is
designated, or if the Entitlement holders do not
designate a single Participant, then Bid Prices for
the unit shall be based on its replacement cost of
fuel, which shall be furnished to the System Operator
by the Participant responsible for furnishing such
information as of December 1, 1996. Further, any
schedules for the unit will be submitted to the
System Operator by such Participant. Nothing in this
Agreement shall affect the rights of any Entitlement
holder under the contractual arrangements among such
Entitlement holders relating to the unit.
Prior to the Third Effective Date, Bid Prices must be
submitted for the next Scheduled Dispatch Period for
all Energy, Operating Reserve and AGC Entitlements in
generating unit or units and Energy Entitlements
pursuant to Firm Contracts or System Contracts which
may be scheduled by the buyer in accordance with
Section 14.7(b) no later than noon on
<PAGE>
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the preceding day or such later time as is specified
in the market operation rules approved by the
Regional Market Operations Committee. On and after
the Third Effective Date, such Bid Prices shall be
submitted for each hour of the day and the notice
period for such Bid Prices shall be reduced to one
hour or such shorter time as the System Operator
determines from time to time is practical while
maintaining reliability and meeting its other
obligations to the Participants, except that such
notice period shall be longer than one hour if and to
the extent that the System Operator reasonably
determines that such notice is the shortest notice
that is technically feasible at that time to maintain
reliability and meet its other obligations to the
Participants. The System Operator shall notify the
Participants following its receipt of all Bid Prices
of the expected dispatch schedule for the next
Scheduled Dispatch Period. The System Operator shall
reduce the notice required for Bid Prices and the
applicable Scheduled Dispatch Period to the minimum
time technically and practically feasible while
maintaining reliability and meeting its other
obligations to the Participants.
<PAGE>
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Energy, Operating Reserve and/or AGC Entitlements in
a generating unit or units may also be scheduled
directly by the Participants permitted to submit Bid
Prices for such Entitlements, but only in accordance
with this Section 14.2(d) and market operation rules
approved by the Regional Market Operations Committee
consistent herewith. Subject to the right of the
System Operator to direct changes to schedules in
order to ensure reliability in the NEPOOL Control
Area or any neighboring control area, a Participant
permitted to bid its Energy, Operating Reserve,
and/or AGC Entitlements in a generating unit or
units, or required to make Energy deliveries, may
submit an hour-to-hour schedule for the operation or
dispatch of such Entitlements during a Scheduled
Dispatch Period at or before the time that Bid Prices
are required to be submitted for such period. In
addition, prior to the Third Effective Date, a
Participant permitted to bid a unit or units may
submit a short-notice schedule for the operation or
dispatch of any or all of the Energy available from
such unit or units during the current or a subsequent
Scheduled Dispatch Period following the time that the
System Operator notifies the appropriate Participants
of their expected Entitlement commitments for that
Scheduled Dispatch Period; provided that, for each
-------------
<PAGE>
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such short-notice schedule, the Participant has not
been advised by the System Operator that the Energy,
Operating Reserve or AGC Entitlements from the unit
or units covered by the Participant's schedule are
expected to be used during the Scheduled Dispatch
Period to meet the region's Energy, Operating Reserve
and/or AGC requirements, and provided further that
----------------------
the Participant short-notice schedule is only to
facilitate transactions during such period from
resources or to load located outside the NEPOOL
Control Area; and provided further that such schedule
---------------------
is furnished at least one hour in advance of the
start of the transaction. In addition, a Participant
may, on the same short notice, schedule System
Contracts with Non-Participants from resources or to
load located outside of the NEPOOL Control Area.
14.3 Amount of Energy, Operating Reserve and Automatic Generation Control
--------------------------------------------------------------------
Received or Furnished.
---------------------
(a) For purposes of Sections 14.4, 14.5, and 14.8, the amount of
Energy which a Participant is deemed to receive or furnish in
any hour shall be the amount of its Adjusted Net Interchange.
If the Adjusted Net Interchange is negative, the Participant
shall be deemed to be receiving Energy in the hour. If the
Adjusted
<PAGE>
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Net Interchange is positive, the Participant shall be deemed
to be furnishing Energy in the hour.
(b) For purposes of Sections 14.4, 14.5, and 14.9, prior to the
Third Effective Date: the amount of each category of
Operating Reserve which a Participant is deemed to receive in
any hour is the Kilowatts of such Operating Reserve assigned
to the Participant for the hour under Section 14.1(b) less any
----
Kilowatts provided in the hour by the Participant in
accordance with the market operation rules approved by the
Regional Market Operations Committee to meet any Operating
Reserve requirements that were specifically assigned to it and
not shared by all Participants; the amount of Operating
Reserve of each category that the Participant is deemed to
have furnished under the Agreement in the hour is the amount
of such Operating Reserve designated by the System Operator to
be provided in the hour by the Participant's applicable
Operating Reserve Entitlements, minus any Kilowatts used in
-----
the hour by the Participant in accordance with the market
operation rules to meet any Operating Reserve requirements
that were specifically assigned to it and not shared by all
Participants. For purposes of Sections 14.4, 14.5, and 14.9,
on and after the Third Effective Date, the amount of each
category of Operating Reserve which
<PAGE>
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a Participant is deemed to have received or furnished in any
hour is the difference between the Kilowatts of such Operating
Reserve assigned to the Participant for the hour under Section
14.1(b) and the Kilowatts of such Operating Reserve designated
by the System Operator to be provided in the hour by the
Participant's applicable Operating Reserve Entitlements.
(c) For purposes of Sections 14.4, 14.5, and 14.10, prior to the
Third Effective Date, the amount of AGC which a Participant is
deemed to have received in an hour is the AGC assigned to the
Participant for the hour under Section 14.1(c), and the amount
a Participant is deemed to have furnished in the hour is the
AGC designated by the System Operator to be provided in the
hour by the Participant's AGC Entitlements. For purposes of
Sections 14.4, 14.5, and 14.10, on and after the Third
Effective Date, the amount of AGC which a Participant is
deemed to have received or furnished in an hour is the
difference between the AGC assigned to the Participant for the
hour under Section 14.1(c) and the AGC designated by the
System Operator to be provided in the hour by the
Participant's AGC Entitlements.
<PAGE>
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14.4 Payments by Participants Receiving Energy Service, Operating Reserve
--------------------------------------------------------------------
and Automatic Generation Control.
--------------------------------
(a) For every hour in which a Participant's Adjusted Net
Interchange is negative, the number of megawatthours of its
Energy deficiency shall be computed and the Participant shall
pay for the hour the product of its total megawatthours of
deficiency and the Energy Clearing Price applicable for the
hour as determined in accordance with Section 14.8, together
with any applicable uplift charges assessed to the Participant
under Sections 14.14 or 14.15 and any applicable fees for
services assessed pursuant to Section 19.2.
(b) For every hour in which a Participant is deemed to receive
Operating Reserve of any category in accordance with Section
14.3(b), the number of Kilowatts it is deemed to receive for
the hour in each category shall be computed. The Participant
shall pay therefor for the hour any applicable uplift charge
assessed under Section 14.15 and any applicable fees for
services assessed pursuant to Section 19.2 plus the product of
----
(i) the aggregate amount paid to Participants for that
category of Operating Reserve for the hour pursuant to Section
14.5(b) and (ii) a fraction of which the numerator is the
Kilowatts of that category of
<PAGE>
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Operating Reserve deemed under Section 14.3(b) to have been
received by the Participant for the hour and the denominator
is the aggregate Kilowatts of that category of Operating
Reserve deemed under Section 14.3(b) to have been received by
all Participants for the hour.
(c) For every hour in which a Participant is deemed under Section
14.3(c) to have received AGC, the amount it is deemed to
receive shall be computed and the Participant shall pay
therefor any applicable uplift charge assessed under Section
14.15 and any applicable fees for services assessed pursuant
to Section 19.2 plus the product of (i) the aggregate amount
----
paid to Participants for AGC for the hour pursuant to Section
14.5(c) and (ii) a fraction of which the numerator is the AGC
the Participant is deemed under Section 14.3(c) to have
received for the hour and the denominator is the aggregate
amount of AGC all Participants are deemed under Section
14.3(c) to have received for the hour.
14.5 Payments to Participants Furnishing Energy Service, Operating Reserve,
----------------------------------------------------------------------
and Automatic Generation Control.
--------------------------------
(a) Subject to the provisions of Section 14.12, a Participant that
is deemed in an hour to furnish Energy service to other
Participants pursuant to Section 14.3, or
<PAGE>
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to Non-Participants for ancillary services under the Tariff or
pursuant to arrangements entered into under Section 14.6,
shall receive for each megawatthour furnished by it the Energy
Clearing Price for the hour determined in accordance with
Section 14.8 or the Bid Price for that megawatthour, if higher
than the Energy Clearing Price and the unit is either within
the Energy Clearing Price Block (as defined in Section
14.8(c)) or is operated out of merit if such higher Bid Price
is appropriately paid pursuant to market operation rules
governing out-of-merit generation approved by the Regional
Market Operations Committee. In addition, to the extent that
the System Operator reduces Energy production from a
generating unit or units in order to provide VAR support,
Participants with Entitlements in such unit or units may
receive their lost opportunity costs if and to the extent
provided for by market operation rules approved by the
Regional Market Operations Committee.
(b) A Participant that is deemed in an hour to furnish Operating
Reserve under the Agreement shall receive for each Kilowatt of
each category of Operating Reserve furnished by it the
applicable Operating Reserve Selling Price as defined and
determined in accordance with Section 14.9 or the Bid Price to
<PAGE>
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provide such Kilowatt, if higher than the Operating Reserve
Selling Price for the hour.
(c) A Participant that is deemed in an hour to furnish AGC under
the Agreement shall receive therefor an amount calculated as
follows:
(i) the AGC Clearing Price for the hour as defined and
determined in accordance with Section 14.10, times
-----
the change in AGC output of the Participant's AGC
Entitlements which the System Operator requested in
the hour, times an appropriate unit conversion factor
-----
as determined in accordance with market operation
rules approved by the Regional Market Operations
Committee; plus
----
(ii) an AGC reservation payment for each AGC Entitlement
that the System Operator designated for AGC in the
hour calculated as (A) the AGC Clearing Price in
effect for the hour, times (B) the level of AGC the
-----
System Operator determines to be available in the
hour from the Entitlement, times (C) the portion of
-----
the hour during which the System Operator had
designated the Entitlement for AGC; plus
----
<PAGE>
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(iii) a payment that compensates the Participant for its
lost opportunity cost, if any, for the operation of
the generating unit or combination of units
designated for AGC in the hour below the desired
level of output in order to provide AGC, as
determined in accordance with market operation rules
approved by the Regional Market Operations Committee.
14.6 Energy Transactions with Non-Participants.
-----------------------------------------
(a) The Management Committee is authorized to enter into contracts
on behalf of and in the names of all Participants (i) with
power pools or other entities in one or more other control
areas to purchase or furnish emergency Energy (and related
services) that is available for the System Operator to
schedule in order to ensure reliability in the NEPOOL Control
Area or neighboring control areas, and (ii) with
Non-Participants pursuant to which ancillary services will be
provided by the Participants pursuant to the Tariff. The
terms of any such contractual arrangement shall not require
the furnishing of emergency service to any other control area
until the service needs of all Participants have been
provided for with the least expensive resources practicable.
Energy purchased in any hour from Non-Participants under a
contract entered into pursuant to this
<PAGE>
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Section 14.6(a) shall be deemed to be furnished to, and paid
for by, Participants entitled to or requiring such Energy in
the hour pursuant to this Section 14 at the higher of the
Energy Clearing Price for the hour or the price paid to the
Non-Participant for the Energy.
(b) The Regional Market Operations Committee is authorized to
provide for the day-to-day scheduling through the System
Operator of the HQ Phase II Firm Energy Contract, in
accordance with the HQ Use Agreement, as if the Contract were
a contract covering Energy transactions with a Non-Participant
entered into pursuant to Section 14.6(a). The HQ Phase II
Firm Energy Contract shall not be deemed a Firm Contract for
purposes of this Agreement. Energy received in an hour from
Hydro-Quebec pursuant to the HQ Energy Banking Agreement, and
Energy purchased in any hour from Hydro-Quebec pursuant to the
HQ Phase II Firm Energy Contract or any other HQ Contract
shall be deemed to be Energy furnished to each Participant
entitled to such Energy for the hour in the amount reflected
for the Participant in the System Operator's scheduling of
Energy deliveries in the hour from Hydro-Quebec; except that
-----------
emergency Energy received from Hydro-Quebec under the HQ
Interconnection Agreement shall be deemed to be Energy
provided to (and shall be paid for by)
<PAGE>
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Participants requiring such emergency Energy in the hour. The
System Operator shall schedule such Energy deliveries to
accommodate, to the maximum extent possible, the schedule of
Energy deliveries from Hydro-Quebec requested by the
Participant. The Participants deemed to have received such
Energy shall pay therefor the higher of the Energy Clearing
Price (together with any applicable uplift charges under
Sections 14.14 and/or 14.15 and any applicable fees for
services assessed pursuant to Section 19.2) or the price paid
to Hydro-Quebec for the Energy (or in the case of Energy
received under the HQ Energy Banking Agreement, the price paid
for the related Energy deliveries to Hydro-Quebec under the
Agreement and any amount payable to Hydro-Quebec with respect
to the transaction).
14.7 Participant Purchases Pursuant to Firm Contracts and System Contracts.
---------------------------------------------------------------------
(a) For Firm Contracts and System Contracts, the treatment of
Installed Capability, Operable Capability, Energy, Operating
Reserve and AGC between the seller and the purchaser in
determining their respective responsibilities and Entitlements
shall be as agreed between the parties and reported to the
System Operator in accordance with market operation rules
approved by the Regional
<PAGE>
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Market Operations Committee. If and to the extent necessary to
implement the agreement between the parties, such market
operation rules, upon approval by the Management Committee,
shall supersede the provisions of the Agreement that otherwise
apply for determination of the respective responsibilities and
Entitlements of the parties.
(b) In the event a Participant has the right to receive Operable
Capability, Energy, Operating Reserve and/or AGC from a
Non-Participant under a System Contract or a Firm Contract,
such Contract shall be treated as nearly as possible as if it
were a Unit Contract for an Operable Capability Entitlement,
Energy Entitlement, Operating Reserve Entitlement and/or AGC
Entitlement, as applicable, provided that, in the case of
-------------
Energy, Operating Reserve, and/or AGC, the System Contract or
Firm Contract permits the scheduling of deliveries of such
Energy, Operating Reserve and/or AGC to be subject in whole or
part to central dispatch through the System Operator in
accordance with market operation rules approved by the
Regional Market Operations Committee.
<PAGE>
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14.8 Determination of Energy Clearing Price.
--------------------------------------
For each hour, the System Operator shall determine the Energy Clearing
Price as follows:
(a) The System Operator shall rank in the order of lowest to
highest (i) the Dispatch Prices derived from the Bid Prices to
furnish Energy in the hour and (ii) the cost to NEPOOL of any
Energy received from Non-Participants in the hour pursuant to
contracts referenced in Section 14.6.
(b) The Energy Clearing Price shall be the weighted average of the
Dispatch Prices (or NEPOOL cost) of the "Energy Clearing Price
Block" as defined in the next sentence. The Energy Clearing
Price Block shall be identified for each hour in accordance
with market operation rules approved by the Regional Market
Operations Committee to reflect those resources with the
highest Dispatch Prices or NEPOOL cost that were centrally
dispatched by the System Operator for Energy deemed to have
been furnished to the Participants, excluding resources that
were dispatched out of merit as determined in accordance with
market operation rules approved by the Regional Market
Operations Committee.
<PAGE>
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14.9 Determination of Operating Reserve Selling Price and Clearing Price.
-------------------------------------------------------------------
(a) For each hour as necessary, the System Operator shall
determine the Operating Reserve Clearing Price for each
category of Operating Reserve as follows:
(i) The System Operator shall determine the aggregate
Kilowatts of the applicable category of Operating
Reserve that are deemed pursuant to Section 14.3(b)
to have been received by Participants for the hour.
(ii) For 10-Minute Non-Spinning Reserve and 30-Minute
Operating Reserve, the System Operator shall rank in
the order of lowest to highest the Bid Prices of the
resources designated by the System Operator for that
category of Operating Reserve for the hour. The
applicable Operating Reserve Clearing Price for
10-Minute Non-Spinning Reserve or 30-Minute Operating
Reserve shall be the weighted average of the highest
Bid Prices for the 1000 Kilowatts (or such other
number as may be specified by the Regional Market
Operations Committee) of that category of Operating
Reserve that are designated by the System Operator
for use in the hour.
<PAGE>
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(iii) For 10-Minute Spinning Reserve the System Operator
shall rank in order of lowest to highest the sum for
each Operating Reserve Entitlement of (A) the Bid
Price for such Entitlement and (B) the lost
opportunity costs (as defined in Section 14.9(d)
(ii)). The Operating Reserve Clearing Price for
10-Minute Spinning Reserve shall be the weighted
average for the 1000 Kilowatts (or such other number
as may be specified by the Regional Market Operations
Committee) of the highest sums for the hour of the
Entitlements that were designated by the System
Operator for use in the hour.
(b) The Operating Reserve Selling Price for any hour for each
Kilowatt of 10- Minute Non-Spinning Reserve and 30-Minute
Operating Reserve deemed to be furnished by a Participant in
the hour pursuant to Section 14.3(b) shall be the applicable
Operating Reserve Clearing Price determined in accordance with
Section 14.9(a).
(c) Prior to the Third Effective Date, the Operating Reserve
Selling Price for any hour for each Kilowatt of 10-Minute
Spinning Reserve deemed to be furnished by a Participant from
one of its generating units designated for the hour by the
<PAGE>
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System Operator for 10-Minute Spinning Reserve pursuant to
Section 14.3(b) shall be an amount equal to the sum of the
"Lost Opportunity Clearing Price" and the lost opportunity
cost (as defined in Section 14.9(d)(ii)), if any, for the
generating unit, both as determined pursuant to Section
14.9(d) below. On and after the Third Effective Date, the
Operating Reserve Selling Price for an hour for 10-Minute
Spinning Reserve shall be the applicable Operating Reserve
Clearing Price for that hour.
(d) Prior to the Third Effective Date, for each hour, the System
Operator shall determine a Lost Opportunity Clearing Price for
use in determining the Operating Reserve Selling Price for
10-Minute Spinning Reserve. A Lost Opportunity Clearing Price
shall be calculated for every hour as follows:
(i) The System Operator shall determine the Kilowatts of
10-Minute Spinning Reserve that it designated and
required for the hour.
(ii) For that hour, the System Operator shall rank in
order of lowest to highest the lost opportunity costs
for generating units designated by the System
Operator to provide 10-Minute Spinning Reserve in the
hour.
<PAGE>
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For purposes of this Section 14.9, the lost
opportunity cost for a Participant's generating unit
shall be the amount by which the Energy Clearing
Price for the hour exceeds the unit's Dispatch Price
(not less than zero), plus, in the case of
----
hydroelectric generating facilities and pumped
storage hydroelectric generating facilities, the Bid
Price in the hour for each facility to provide
10-Minute Spinning Reserve.
(iii) The Lost Opportunity Clearing Price for an hour shall
be the weighted average of the highest 1000 Kilowatts
(or such other number as may be specified by the
Regional Market Operations Committee) of lost
opportunity costs for generating units that were
designated by the System Operator to provide
10-Minute Spinning Reserve in the hour.
14.10 Determination of AGC Clearing Price.
-----------------------------------
For each hour, the System Operator shall determine the AGC Clearing
Price. The AGC Clearing Price shall be the weighted average "AGC
Capability Price" for the "AGC Clearing Price Block," as both terms are
defined below in this Section 14.10. The AGC Capability Price for each
hour for each AGC Entitlement designated by the
<PAGE>
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System Operator to provide AGC in the hour shall be a cost per unit of
AGC capability based on the Bid Price for the Entitlement for the hour
divided by the amount of AGC available in the hour from that
Entitlement. The AGC Clearing Price Block shall be identified by the
System Operator for each hour in accordance with market operation rules
approved by the Regional Market Operations Committee to reflect those
AGC resources with the highest Bid Prices that were designated by the
System Operator to provide AGC in the hour and were deemed pursuant to
Section 14.3(c) to have been received by Participants for the hour.
14.11 Funds to or from which Payments are to be Made.
----------------------------------------------
(a) All payments for Energy, Operating Reserves or AGC
furnished or received, all uplift charges paid
pursuant to this Section 14, and all fees for
services paid pursuant to Section 19.2, and any
payments by Non-Participants for ancillary services
under Schedules 2-7 to the Tariff or pursuant to
arrangements referenced in Section 14.6, shall be
allocated each month through the Pool Interchange
Fund as follows:
<PAGE>
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Step One. For each week in which Energy is delivered
--------
or received under the HQ Energy Banking Agreement,
all payments with respect to transactions under that
Agreement shall be made to or from the Energy Banking
Fund provided for in Section 14.11(b).
Step Two. (i) For each week in which Pre-Scheduled
--------
Energy (as defined in the HQ Phase I Energy Contract)
is purchased pursuant to the HQ Phase I Energy
Contract, the aggregate amount which is paid pursuant
to Section 14.6(b) for such Energy by each
Participant which is a participant in the Phase I
arrangements with Hydro-Quebec shall be determined
and paid on the Participant's account into the Phase
I Savings Fund.
(ii) For each week in which Energy is purchased
pursuant to the HQ Phase II Firm Energy Contract, the
aggregate amount which is paid pursuant to Section
14.6(b) for such Energy by each Participant which is
a participant in the Phase II arrangements with
Hydro-Quebec shall be determined and paid on the
Participant's account into the Phase II Savings Fund.
<PAGE>
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Step Three. For each week in which Other HQ Energy is
----------
purchased pursuant to the HQ Phase I Energy Contract
or Energy is purchased pursuant to the HQ
Interconnection Agreement, the aggregate amount paid
pursuant to Section 14.6(b) for such Energy shall be
determined for each Participant which is a
participant in the Phase I or Phase II arrangements
with Hydro-Quebec. Such amount shall be allocated
between the Participant's share of the Phase I
Savings Fund and the Participant's share of the Phase
II Savings Fund created under the HQ Use Agreement in
the same ratio as (A) the sum of (x) the number of
kilowatthours of Other HQ Energy deemed to be
purchased by the Participant during the week and (y)
the HQ Phase I Percentage of the number of
kilowatthours deemed to be purchased by the
Participant under the HQ Interconnection Agreement
during the week, bears to (B) the HQ Phase II
Percentage of the number of kilowatthours purchased
under the HQ Interconnection Agreement during the
week.
Step Four. The balance remaining in the Pool
---------
Interchange Fund after Steps One through Three shall
be retained in the Pool Interchange Fund
<PAGE>
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for the month and shall be used and disbursed after
each month in the following order:
(i) (A) amounts owed to Non-Participants (other
than Hydro-Quebec) for the month under
contracts entered into with them pursuant to
Section 14.6(a) shall be paid, and (B)
amounts owed to Hydro-Quebec for the month
for Energy deemed to be furnished pursuant
to Section 14.6(b) to Participants which are
not participants in the Phase I or Phase II
arrangements with Hydro-Quebec shall be paid
and, in the event the price paid by any such
Participant for such Energy is the Energy
Clearing Price, the excess, if any, of the
Energy Clearing Price over the amount owed
to Hydro-Quebec shall be paid to the
Participant;
(ii) amounts paid by Participants for applicable
fees for services assessed pursuant to
Section 19.2 shall be used to reduce NEPOOL
expenses; and
<PAGE>
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(iii) amounts owed to Participants for the month
pursuant to Section 14.5 shall then be paid.
(b) HQ Energy Banking Fund. All amounts allocated to the
----------------------
HQ Energy Banking Fund for each month shall be used
and disbursed as follows:
(i) Participants which furnish Energy for
delivery to Hydro-Quebec under the HQ Energy
Banking Agreement shall receive therefor
from their share of the Energy Banking Fund
the amount to which they are entitled for
such service in accordance with Section
14.5.
(ii) amounts required to be paid to Hydro-Quebec
under the HQ Energy Banking Agreement shall
be paid from the shares of the Fund of the
Participants engaging in transactions under
the HQ Energy Banking Agreement for the
month in accordance with their respective
interests in the transactions for the month.
If there is not enough in any such share,
the Participants with the
<PAGE>
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deficient shares shall be billed and pay
into their shares of the Fund the amounts
required for payments to Hydro-Quebec.
(iii) subject to the remaining provisions of this
Section, at the end of each month any
balance remaining in each Participant's
share of the HQ Energy Banking Fund shall
(I) in the case of any Participant which is
not a participant in the Phase I or Phase II
arrangements with Hydro-Quebec, be paid to
such Participant, and (II) in the case of
any Participant which is a participant in
the Phase I or Phase II arrangements with
Hydro-Quebec, be paid to the Escrow Agent
under the HQ Use Agreement to be held and
disbursed by it through the Phase I Savings
Fund and Phase II Savings Fund created under
the HQ Use Agreement, and shall be allocated
between the Participant's share of said
Funds as follows:
(A) the balance remaining in the
Participant's share of the HQ Energy
Banking Fund for the month shall be
divided by the number of
kilowatthours deemed to be received
by the
<PAGE>
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Participant under the HQ Energy
Banking Agreement during the month
to determine an average savings
amount per kilowatthour;
(B) for any hour during the month in
which the number of kilowatthours
received by NEPOOL under the HQ
Energy Banking Agreement exceeded
the HQ Phase I Transfer Capability,
an amount equal to (A) the
--------
Participant's share of the excess of
(1) the number of kilowatthours
received over (2) the HQ Phase I
Transfer Capability times (B) the
-----
average savings amount per
kilowatthour determined for that
Participant under (i) above shall be
allocated to the Phase II Savings
Fund; and
(C) the remaining balance of the
Participant's share of the HQ Energy
Banking Fund for the month shall be
allocated to the Phase I Savings
Fund.
<PAGE>
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It is recognized that, in view of the time which may
elapse between the delivery of Energy to or by
Hydro-Quebec in an Energy Banking transaction under
the HQ Energy Banking Agreement and the return of the
Energy, the amounts of Energy delivered to and
received from Hydro-Quebec, after adjustment for
losses, may not be in balance at the end of a
particular month.
Further, if as of the end of any month and after
adjustment for electrical losses, the cumulative
amount of Energy so received from Hydro-Quebec
exceeds the amount so delivered, the aggregate amount
paid by Participants for the excess Energy pursuant
to Section 14.6(b) shall be paid to the Energy
Banking Fund. The Escrow Agent under the HQ Use
Agreement shall hold and invest these funds. On the
return of the excess Energy to Hydro-Quebec, the
amount so held by the Escrow Agent shall be repaid to
Hydro-Quebec and Participants in accordance with the
Energy Banking Agreement.
(c) Phase I HQ Savings Fund. The aggregate amount
---------------------------
allocated to each Participant's share of the Phase I
HQ Savings Fund for each month shall
<PAGE>
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be used, first, to pay to Hydro-Quebec the amount
owed to it for the month for Energy furnished under
the Phase I HQ Energy Contract and the HQ Phase I
Percentage of the amount owed to it for the month for
Energy furnished to the Participants under the HQ
Interconnection Agreement. The balance of the amount
allocated to the Fund for the month shall be paid to
the Escrow Agent under the HQ Use Agreement to be
held and disbursed by it through the Phase I HQ
Savings Fund created thereunder in accordance with
each Participant's contribution to such balance.
(d) Phase II HQ Savings Fund. The aggregate amount
------------------------
allocated to the Phase II HQ Savings Fund for each
month shall be used, first, to pay to Hydro-Quebec
the amount owed to it for the month for Energy deemed
to be furnished to the Participant under the Phase II
HQ Firm Energy Contract and the HQ Phase II
Percentage of the amount owed to it for the month for
Energy deemed to be furnished to the Participant
under the HQ Interconnection Agreement. The balance
of the amount allocated to the Fund for the month
shall be paid to the Escrow Agent under the HQ Use
Agreement to be held and disbursed by it through the
<PAGE>
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Phase II HQ Savings Fund created thereunder in
accordance with each Participant's contribution to
such balance.
14.12 Development of Rules Relating to Nuclear and Hydroelectric Generating
-----------------------------------------------------------------------
Facilities, Limited-Fuel Generating Facilities, and Interruptible
-----------------------------------------------------------------------
Loads.
-----
It is recognized that the central dispatch of Energy available from
nuclear generating facilities and from pondage associated with
hydroelectric generating facilities and from interruptible loads and of
pumping Energy for pumped storage hydroelectric generating facilities
and other limited-fuel generating facilities involves special problems
which must be resolved to assure fair and non-discriminatory treatment
of Participants having Entitlements in such generating facilities or
having such interruptible loads or any other Participants involved in
such transactions. Accordingly, the Regional Market Operations
Committee shall analyze such special problems and develop appropriate
rules for dispatching such facilities (including, but not limited to,
bids for dispatchable pumping load at pumped storage facilities), for
handling such interruptible loads and for paying for Operable
Capability, Energy, Operating Reserve and AGC involved in such
transactions on a basis consistent with the principles underlying this
Section 14; and upon approval by the Management Committee such rules
shall supersede the provisions of Sections 12 and 14 to the extent of
any conflict.
<PAGE>
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14.13 Dispatch and Billing Rules During Energy Shortages. It is recognized
----------------------------------------------------
that Energy shortages can result in special problems which must be
resolved to assure that dispatch and billing provisions do not prevent
achievement of the objectives specified in Section 13.4. Accordingly,
the Regional Market Operations Committee shall analyze such special
problems and develop appropriate dispatch and billing rules to be
applied during periods when the Management Committee determines that
there is, or is anticipated to be, an Energy shortage which adversely
affects the bulk power supply of the NEPOOL Control Area and any
adjoining areas served by Participants. Upon approval by the Management
Committee, such rules shall supersede the economic dispatch and billing
provisions of this Agreement to the extent of any conflict therewith
for the duration of such Energy shortage period.
14.14 Congestion Uplift.
-----------------
(a) If limitations in available transmission capacity
over any interface within the NEPOOL Control Area in
any hour require that the System Operator dispatch
out-of-merit resources that are bid by the
Participants, the System Operator shall determine for
the affected area or areas the aggregate of the
Congestion Costs for all such out-of-merit resources
for the hour. The Congestion Costs for each hour in
any month shall be
<PAGE>
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paid as a transmission charge and included in the
charge for Regional Network Service or Through or Out
Service, whichever is applicable, by those
Participants and Non-Participants which are obligated
to pay a Regional Network Service charge or Through
or Out Service charge for the month, in accordance
with the following formula:
(HLi + RCi)
CH = CC o ---------
(HL + RC)
in which
CH = the amount to be paid by a
Participant or Non-Participant
for the hour;
CC = the Congestion Costs for the
hour to be allocated and paid
pursuant to this subsection
(a);
HLi = the Load of the Participant or
Non-Participant for the hour,
if it is obligated to pay a
Regional Network Service
charge for the month;
HL = the aggregate of the Loads for
the hour of all Participants
and Non-Participants which are
obligated to pay a Regional
Network Service charge for the
month;
RCi = the Reserved Capacity, if any,
for Through or Out Service of
the Participant or
Non-Participant for the hour;
and
RC = the aggregate Reserved
Capacity, if any, for Through
or Out Service of all
Participants and Non-
Participants for the hour.
<PAGE>
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Except as provided in the next sentence, this
subsection (a) shall remain in effect no later than
December 31, 1999 and shall then terminate.
Notwithstanding the foregoing, if prior to January 1,
2000, Participants having in the aggregate the
requisite number of Voting Shares have executed and
filed with the Commission an amendment to the
Agreement and/or the Tariff to modify subsection (c)
of this Section or to adopt some other modified or
substitute provision dealing with the allocation of
Congestion Costs in a constrained transmission area,
but such amendment has not become effective, and/or
the preparation of necessary implementing rules and
computer software has not been completed prior to
January 1, 2000, if the Management Committee so
elects this subsection (a) shall continue in effect
until such amendment becomes effective and such rules
and computer software have been completed.
(b) It shall be the responsibility of the Management
Committee to review prior to January 1, 2000 the
Congestion Costs incurred with the new market
arrangements contemplated by Section 14 and with
retail access, and to determine whether subsection
(c) of this Section, together with an
<PAGE>
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amendment specifying the rights of Participants and
Non-Participants across a constrained interface
within the NEPOOL Control Area and to make other
necessary or appropriate changes in subsection (c),
all of the provisions of which shall be considered
for modification, or some other modified or
substitute provision dealing with the allocation of
Congestion Costs in a constrained transmission area,
should be made effective on January 1, 2000 and after
the preparation of necessary implementing rules and
computer software or on an earlier or later effective
date. If the Committee determines that such a
provision should be made effective, it shall
recommend to the Participants any required amendment
to the Agreement and/or the Tariff and a schedule for
implementation which will permit sufficient time for
the development of necessary rules and computer
software. If the Management Committee is unable to
agree on such a determination prior to January 1,
2000 any Participant or group of Participants may
propose such an amendment and schedule in a filing
with the Commission.
(c) Commencing on January 1, 2000, but subject to the
adoption of an amendment specifying the rights of
Participants and Non-Participants
<PAGE>
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across constrained interfaces within the NEPOOL
Control Area and making other necessary or
appropriate changes in the language of this
subsection (c), and the preparation of necessary
implementing rules and computer software, (or on such
earlier or later date as is fixed by the Management
Committee in accordance with subsection (b) of this
Section), whenever limitations in available
transmission capacity in any hour require that the
System Operator dispatch out-of-merit resources that
are bid by the Participants in any area which is
determined to be a constrained transmission area in
accordance with market operation rules approved by
the Regional Market Operations Committee and the
Regional Transmission Operations Committee, the
System Operator shall determine for the constrained
transmission area the aggregate Congestion Costs for
the hour.
Such Congestion Costs for each hour shall be
allocated to and paid by Participants and
Non-Participants as a congestion uplift as follows:
(i) In accordance with market operation rules
approved by the Regional Market Operations
Committee and the Regional
<PAGE>
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Transmission Operations Committee, the
System Operator shall identify for each
Participant and Non-Participant the
difference in megawatt hours, if any,
between (A) Electrical Load served by the
Participant or Non-Participant in the
constrained area and transactions by the
Participant or Non-Participant occurring in
the hour which utilized the constrained
interface to move Energy through the
constrained area and (B) the Participant's
or Non-Participant's in-merit Energy
Entitlements located in the constrained area
that were used in the hour to serve such
Electrical Load, taking into account Firm
Contracts and System Contracts between
Participants and electrical losses, if and
as appropriate.
(ii) The System Operator shall identify for each
Participant and Non-Participant the megawatt
hours, if any, of the rights of that
Participant or Non-Participant to use the
then effective transfer capability across
the constrained interface.
<PAGE>
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(iii) The System Operator shall identify for eac
Participant and Non-Participant the megawatt
hours, if any, by which the amount
determined pursuant to clause (i) above for
that Participant or Non-Participant exceeds
the amount determined for that Participant
or Non-Participant pursuant to clause (ii)
above. If the clause (i) amount exceeds the
clause (ii) amount, the Participant or
Non-Participant shall be responsible for
paying a share of the aggregate Congestion
Costs in proportion to the Participant's or
Non-Participant's share of the aggregate
amount of such excesses for all Participants
and Non-Participants, and such Congestion
Costs shall be included, as a transmission
charge, in the Regional Network Service or
Through or Out Service charge, whichever is
applicable.
(d) As used in this Section 14.14, the "Congestion Cost"
of an out-of-merit resource for an hour means the
product of (i) the difference between its Dispatch
Price and the Energy Clearing Price for the hour,
times (ii) the number of megawatt hours produced by
the resource for the hour.
<PAGE>
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14.15 Additional Uplift Charges. It is recognized that the System Operator
---------------------------
may be required from time to time to dispatch resources out of merit
for reasons other than those covered by Section 14.14. Accordingly, if
and to the extent appropriate, feasible and practical, dispatch and
operational costs shall be categorized and allocated as uplift costs to
those Participants and Non-Participants that are responsible for such
costs. Such allocations shall be determined in accordance with market
operation rules that are consistent with this Agreement and any
applicable regulatory requirements and approved by the Regional Market
Operations Committee.
PART FOUR
TRANSMISSION PROVISIONS
SECTION 15
OPERATION OF TRANSMISSION FACILITIES
------------------------------------
15.1 Definition of PTF. PTF or pool transmission facilities are the
-------------------
transmission facilities rated 69 kV or above owned by Participants
required to allow Energy from significant power sources to move freely
on the New England transmission network, and include:
<PAGE>
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(1) All transmission lines rated 69 kV and above, except:
(a) Those which are required to serve local load only,
thereby contributing little or no parallel capability
to the interconnected system.
(b) Generator leads, which are defined as transmission
from a generation bus to the nearest significant load
bus or radial transmission from a generator bus to
the nearest point on the interconnected network.
(c Lines that are normally operated open.
(2) Necessary linkages (includes substation facilities such as
transformers, circuit breakers and associated equipment)
required to interconnect the lines which constitute PTF.
(3) If a Participant with significant generation in its
transmission and distribution system (initially 25 MW) is
connected to the New England network and none of the
transmission facilities owned by the Participant qualify to be
included in PTF as defined in (1) and (2) above, then such
Participant's connection to PTF
<PAGE>
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will constitute PTF if both of the following requirements are
met for this connection:
(a) The connection is rated 69 kV or above.
(b) The connection is the principal transmission link
between the Participant and the remainder of the New
England PTF network.
The Regional Transmission Planning Committee shall review at least
annually the status of transmission lines and related facilities and
determine whether such facilities constitute PTF and shall prepare and
keep current a schedule of PTF facilities.
The following examples indicate the intent of the above
definitions:
(i) Radial tap lines to local load are excluded.
(ii) Lines which loop (supply from more than one
substation) a load bus into the
interconnected network are included.
<PAGE>
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(iii) Lines which loop (supply to more than one
substation) a generator bus into the
interconnected network are included.
(iv) Radial connections or connections from a
generating station to a single substation on
the interconnected network are excluded
unless the requirements of paragraph 3 above
are met.
Transmission facilities owned by a Related Person of a
Participant which are rated 69 kV or above and are required to
allow Energy from significant power sources to move freely on
the New England transmission network shall also constitute PTF
provided (i) such Related Person files with the Secretary of
the Management Committee its consent to such treatment; and
(ii) the Management Committee determines that treatment of the
facility as PTF will facilitate accomplishment of NEPOOL's
objectives. If a facility constitutes PTF pursuant to this
paragraph, it shall be treated as "owned" by a Participant for
purposes of the Tariff and the other provisions of Part Four
of the Agreement.
15.2 Maintenance and Operation in Accordance with Good Utility Practice.
------------------------------------------------------------------
Each Participant which owns or operates PTF or other transmission
facilities rated 69 kV or
<PAGE>
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above shall, to the fullest extent practicable, cause all such
transmission facilities owned or operated by it to be designed,
constructed, maintained and operated in accordance with Good Utility
Practice.
15.3 Central Dispatch. Each Participant which owns or operates PTF or other
----------------
transmission facilities rated 69 kV or above shall, to the fullest
extent practicable, subject all such transmission facilities owned or
operated by it to central dispatch by the System Operator; provided,
however, that each Participant shall at all times be the sole judge as
to whether or not and to what extent safety requires that at any time
any of such facilities will be operated at less than their full
capability or not at all.
15.4 Maintenance and Repair. Each Participant shall, to the fullest extent
----------------------
practicable: (a) cause transmission facilities owned or operated by it
to be withdrawn from operation for maintenance and repair only in
accordance with maintenance schedules reported to and published by the
System Operator in accordance with procedures approved or established
by the Regional Transmission Operations Committee from time to time,
(b) restore such facilities to good operating condition with reasonable
promptness, and (c) in emergency situations, accelerate maintenance and
repair at the reasonable request of
<PAGE>
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the System Operator in accordance with rules approved by the Regional
Transmission Operations Committee.
15.5 Additions to or Upgrades of PTF. The need for an addition to or upgrade
-------------------------------
for PTF may be determined in connection with an application or request
for service under the Tariff, or may be separately identified by a
NEPOOL committee, a Participant or the System Operator. In accordance
with the Tariff, if it is likely that a Direct Assignment Facility will
be required, a study to assess available transmission capacity and, if
necessary, a System Impact Study and a Facilities Study shall be
performed by the affected Participant in whose Local Network the
addition or upgrade would be effected and may be effected by the
Participant in any other case, subject to review by the System
Operator. A study may also be conducted by the Regional Transmission
Planning Committee and/or the System Operator with review of the study
by the System Operator if it does not perform the study. Studies to
assess available transmission capacity and System Impact Studies and
Facilities Studies shall be conducted in accordance with the applicable
methodology specified in Attachments C and D to the Tariff and the
applicable procedures specified in the Tariff with respect to the
payment of the costs of the study shall apply.
<PAGE>
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If the studies conducted in connection with an application or request
for service under the Tariff, or as part of a separate review by a
Participant, the Regional Transmission Planning Committee or the System
Operator, indicate that new facilities or a facility modification or
other upgrade of PTF facilities are necessary to ensure adequate,
economic and reliable operation of the bulk power supply systems of the
Participants for regional purposes, whether or not a particular
customer is benefited, one or more Participants or other entities, may
be designated by the Regional Transmission Planning Committee, subject
to review by the System Operator, to design or effect the construction
or modification. The Participants shall be obligated to support all of
the carrying costs of the facility which are not designated for support
by particular Participants or Non-Participants as Direct Assignment
Facilities or on some other basis in accordance with the Tariff or by
mutual agreement, on a load ratio share basis during the Transition
Period and thereafter as part of the Annual Transmission Revenue
Requirements to be paid through the Regional Network Service rate.
In determining the support obligations ("Support Shares") for a
particular PTF upgrade or addition, the Regional Transmission Planning
Committee, subject to review by the System Operator, may determine that
the proposed facilities exceed regional system and regulatory or other
public requirements. In such a case, the Regional Transmission
<PAGE>
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Planning Committee, subject to review by the System Operator, may
require the Participant in whose Local Network the addition or upgrade
is to be effected, to bear the excess cost and include it in the costs
to be recovered under the Participant's Local Network Service tariff.
In fixing the support obligations of a PTF addition or upgrade, the
Regional Transmission Planning, subject to review by the System
Operator, may require that a portion or all of the costs be paid by
particular users. The designation of the users of a particular facility
supporting the facility may be changed by the Regional Transmission
Planning Committee, subject to review by the System Operator, from time
to time as the use changes.
Upon the designation of a Participant or other entity to design and
effect a PTF addition or upgrade and the fixing of the support payments
to be made by the Participants and Non-Participants, the designated
Participant or other entity shall, subject to Sections 18.4 and 18.5
and the receipt of any necessary public approvals or permits and the
acquisition of any required rights of way or other property, use its
best efforts to effect the proposed construction or modification.
<PAGE>
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The terms of the support arrangement for a particular PTF addition or
upgrade with respect to continued support of the facility in the event
of a termination of NEPOOL, the cancellation of the project due to a
failure to obtain regulatory approvals or permits or required rights of
way or other property, or action to terminate the project before its
completion for whatever reason shall be determined by agreement between
the designated Participant(s) or other entity and the Regional
Transmission Planning Committee, subject to review by the System
Operator, as a part of the designation process on a case-by-case basis.
SECTION 16
SERVICE UNDER TARIFF
--------------------
16.1 Effect of Tariff. The Tariff specifies the terms and conditions under
----------------
which the Participants will provide regional transmission service
through NEPOOL. This Section 16 specifies various rights and
obligations with respect to the revenues to be collected by NEPOOL for
the Participants under the Tariff and related matters. The usage in
this Section 16 of terms which are defined in the Tariff and not
otherwise defined in this Agreement is in accordance with the
definitions of such terms in the Tariff.
<PAGE>
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16.2 Obligation to Provide Regional Service. The Participants which own PTF
--------------------------------------
shall collectively provide through NEPOOL regional transmission service
over their PTF facilities, and the facilities of their Related Persons
which constitute PTF in accordance with Section 15.1, to other
Participants and other Eligible Customers pursuant to the Tariff. The
Tariff provides open access for all of the types of regional
transmission service required by Participants and other Eligible
Customers over PTF and it is intended to be the only source of such
service, except for service provided for Excepted Transactions.
16.3 Obligation to Provide Local Network Service. Each Participant which
--------------------------------------------
owns transmission facilities other than PTF shall provide service over
such facilities to other Participants or other Eligible Customers
connected to the Transmission Provider's transmission system pursuant
to a tariff (a "Local Network Service Tariff") filed by the
Transmission Provider with the Commission. A Participant is also
obligated to provide Local Point-to-Point Service under its Local
Network Service Tariff or otherwise, to permit a Participant or other
Entity with an Entitlement in a generating unit in the Participant's
local network to deliver the output of the generating unit to an
interconnection point on PTF.
<PAGE>
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A Local Network Service Tariff shall provide:
(i) for a pro rata allocation of monthly revenue requirements
between the Participant which is the Transmission Provider and
the Participants and other Eligible Customers receiving
service under the tariff on the basis of their loads during
the hour in the month in which the total connected load to the
Local Network is at its maximum, without any adjustment for
credits for generation;
(ii) for the recovery under the Local Network Service Tariff of
that portion of the Transmission Provider's Annual
Transmission Revenue Requirements with respect to PTF which is
not recovered through the distribution of revenues from
Regional Network Service pursuant to Section 16.6(a);
(iii) that where all or a part of the load of a Participant or other
Eligible Customers taking service under the tariff is
connected directly to PTF, the Participant or other Eligible
Customers receiving the service shall pay each Year during the
Transition Period for such service with respect to the load
directly connected to PTF the percentage specified in the
schedule below of the applicable Local Network Service Tariff
charge for service across non-PTF transmission facilities
<PAGE>
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and shall have no obligation to pay charges for service across
non-PTF transmission facilities with respect to that portion
of the connected load after the Transition Period, but shall
continue to pay its share of any other Local Network Service
costs directly associated with the PTF-connected load;
provided that in the event of any inconsistency between the
foregoing provisions and the terms of any Excepted Transaction
which is listed in Attachment G-1 to the Tariff, the Excepted
Transaction shall control:
Year One Year Two Year Three Year Four Year Five
-------- -------- ---------- --------- ---------
% of charge
to be paid 100% 80% 60% 40% 20%
(iv) that if the Transmission Provider provides Tie Benefit
Service, amounts received by it from NEPOOL pursuant to
Section 16.6 out of revenues received for such service shall
reduce its Local Network Service revenue requirements;
(v) that if the Transmission Provider receives a distribution
pursuant to Section 16.6 from NEPOOL out of revenues paid for
Through or Out Service, the amounts received shall reduce its
Local Network Service revenue requirements;
<PAGE>
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(vi) that if the Transmission Provider receives transmission
revenues with respect to an Excepted Transaction, the amounts
received shall reduce its Local Network Service revenue
requirements; and
(vii) any Transition Payment paid or received by the Transmission
Provider shall increase or reduce, as appropriate, its Local
Network Service revenue requirements.
16.4 Transmission Service Availability. The availability of transmission
-----------------------------------
capacity to provide transmission service under the Tariff shall be
determined in accordance with the Tariff. In determining the
availability of transmission capacity, existing committed uses of the
Participants' transmission facilities shall include uses for existing
firm loads and reasonably forecasted changes in such loads, and for
Excepted Transactions.
16.5 Transmission Information. Information concerning (i) available
--------------------------
transmission capacity, (ii) transmission rates and (iii) system
conditions that may give rise to Interruptions or Curtailments shall be
made available to all Participants and Non-Participants through the
OASIS on a timely and non-discriminatory basis. All Participants owning
PTF or other transmission facilities rated 69 kV or higher shall make
available to the System
<PAGE>
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Operator the information required to permit the maintenance of the
OASIS in compliance with Commission Order 889 and any other applicable
Commission orders; provided that no Participant shall be required to
furnish information which is required to be treated as confidential in
accordance with NEPOOL policy without appropriate arrangements to
protect the confidentiality of such information.
16.6 Distribution of Transmission Revenues. Payments required by the Tariff
-------------------------------------
for the use of the NEPOOL Transmission System shall be made to NEPOOL
and shall be distributed by it in accordance with this Section 16.6.
A. Regional Network Service Revenues. Revenues received by NEPOOL
---------------------------------
for providing Regional Network Service each month during the
Transition Period shall be distributed to the Participants
owning or supporting PTF in part on the basis of allocated
flows for the region as determined in accordance with the
methodology specified in Attachment A to this Agreement and in
part in proportion to the respective Annual Transmission
Revenue Requirements for PTF of the owners and supporters, in
accordance with the following Schedule:
<PAGE>
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Year One Year Two Year Three Year Four Year Five
-------- -------- ---------- --------- ---------
Allocated
flows: 25% 20% 15% 10% 5%
Annual
Transmission
Revenue
Requirements 75% 80% 85% 90% 95%
Revenues received by NEPOOL for providing Regional Network
Service each month after the Transition Period shall be
distributed to the Participants owning or supporting PTF in
proportion to their respective Annual Transmission Revenue
Requirements for PTF.
B. Through or Out Service Revenues. The revenues received by
-------------------------------
NEPOOL each month for providing Through or Out Service shall
be distributed among the Participants owning PTF on the basis
of allocated flows for the transaction determined in
accordance with the methodology specified in Attachment A to
this Agreement; provided that for service provided during the
Transition Period but not thereafter, for an "Out" transaction
which originates on the system of a Participant which owns the
PTF interconnection facilities on the New England side of the
interface with the other Control Area over which the
transaction is
<PAGE>
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delivered, 100% of the megawatt mile flows with respect to the
transaction shall be deemed to occur on such Participant's
system.
C. Tie Benefit Service Revenues. The revenues received each month
----------------------------
by NEPOOL for Tie Benefit Service with respect to the
transmission ties to New York and New Brunswick shall be
distributed as follows during and after the Transition Period:
1. New York Ties
-------------
The revenues derived relating to Tie Benefits
received from the New York ties will be distributed
as follows:
Northeast Utilities System Companies 72%
New England Power Company 14%
Vermont Electric Power Company 14%
<PAGE>
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2. New Brunswick Ties
------------------
The revenues derived relating to Tie Benefits
received from the New Brunswick tie will be
distributed as follows:
Central Maine Power Company 78.32%
Bangor Hydro-Electric Company 14.19%
Maine Public Service Company 7.49%
D. Transition Payments. Transition Payments received by NEPOOL
-------------------
each month shall be distributed to the Participants in
accordance with Schedule 11 to the Tariff.
E. Ancillary Service Payments. The revenues received by NEPOOL
----------------------------
pursuant to Schedule 1 to the Tariff (scheduling, system
control and dispatch service) will be used to reimburse
NEPOOL, the System Operator and Participants for the costs
which are reflected in the charges for such service. The
revenues received by NEPOOL pursuant to Schedules 2-7 to the
Tariff shall be distributed prior to the Second Effective Date
in accordance with the continuing provisions of the
<PAGE>
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Prior NEPOOL Agreement and the rules adopted thereunder, and
shall be distributed on or after the Second Effective Date in
accordance with Section 14.
F. External Tie Payments. Any Non-Use Charges received pursuant
---------------------
to Section 22D of the Tariff for any month shall be allocated
among the Transmission Customers that are obligated to pay the
Regional Network Service charge for the month, pro rata in
accordance with their respective loads for the month, and
shall be used to reduce the charges required to be paid by
such Transmission Customers for that month pursuant to Section
16 of the Tariff.
G. Congestion Payments. Any congestion uplift charge received as
-------------------
a payment for transmission service pursuant to Section 14.14
for any hour shall be applied in accordance with Section
14.5(a) in payment for Energy service.
16.7 Changes to Tariff. The Tariff constitutes part of the Agreement and
-----------------
shall be subject to change either in accordance with Section 21.11 or
by an affirmative vote of members of the Management Committee having at
least 70% of the aggregate Voting Shares to which all members are
entitled; provided, however, that the negative votes of any two or more
-------- -------
members representing Participants which are not Related Persons of each
other
<PAGE>
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and which have at least 20% of the aggregate Voting Shares to which all
members are entitled shall defeat any proposed change. In determining
whether the negative vote total specified above has been reached, the
following limitation shall be applied: if the member or members
representing any Participant and its Related Persons would be entitled
to cast against the proposed action more than 18% of the aggregate
Voting Shares to which all members are entitled, such member or members
shall be entitled to vote negatively only 18% of such aggregate Voting
Shares. Nothing in this Agreement shall be deemed to affect in any way
the ability of any Participant or Non-Participant to apply to the
Commission under Section 205 or 206 of the Federal Power Act for a
change in any rate, charge, term, condition or classification of
service under the Tariff.
SECTION 17
POOL-PLANNED UNIT SERVICE
-------------------------
17.1 Effective Period. The provisions contained in this Section 17 shall
-----------------
continue in effect until the fifth anniversary of the effective date of
the Tariff, and shall be of no effect after that date.
<PAGE>
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17.2 Obligation to Provide Service. Until the fifth anniversary of the
--------------------------------
effective date of the Tariff, each Participant shall provide service
over its PTF facilities under this Section 17 rather than under the
Tariff, for the following purposes:
(a) the transfer to a Participant's system of its
ownership interest or its Unit Contract Entitlement
under a contract entered into by it before November
1, 1996 in a Pool-Planned Unit which is off its
system;
(b) the transfer to a Participant's system of its
Entitlement in a purchase under a contract entered
into by it before November 1, 1996 (including a
purchase under the HQ Phase II Firm Energy Contract)
from Hydro-Quebec where the line over which the
transfer is made into New England is the HQ
Interconnection; and
(c) the transfer to a Non-Participant of its Entitlement
in a Pool-Planned Unit pursuant to an arrangement
which has been approved prior to November 1, 1996 by
the Management Committee.
<PAGE>
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17.3 Rules for Determination of Facilities Covered by Particular
-----------------------------------------------------------------------
Transactions. It is anticipated that it may be necessary with respect
------------
to a particular transmission use under subsection (a), (b) or (c) of
Section 17.2 to determine whether the transaction is effected entirely
over PTF, entirely over facilities that are not PTF, or partially over
each.
The following rules shall be controlling in the determination of the
facilities required to effect the use:
(a) To the extent that EHV PTF is available to effect the
transaction, over all or part of the distance to be
covered, the use shall be deemed to be effected on
such EHV PTF over such portion of the distance to be
covered.
(b) To the extent that EHV PTF is not available for the
entire distance to be covered by the use, but Lower
Voltage PTF is available to cover all or part of the
distance not covered by EHV PTF, the transaction
shall be deemed to be effected on such Lower Voltage
PTF.
<PAGE>
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If a Participant has ownership or contractual rights with
respect to an Excepted Transaction which are independent of
this Agreement and the Tariff and are adequate to provide for
a transfer of the types specified in subsections 17.2(a), (b)
or (c), and such rights are not limited to the transfer in
question, the transfer shall be deemed to have been effected
pursuant to such rights and not pursuant to the provisions of
this Agreement. A copy of each instrument establishing such
rights, or an opinion of counsel describing and authenticating
such rights, shall be filed with the Secretary of the
Management Committee.
17.4 Payments for Uses of EHV PTF During the Transition Period.
---------------------------------------------------------
(a) Each Participant shall pay each month for its uses of EHV PTF
for transfers of Entitlements pursuant to subsections (a) or
(b) of Section 17.2, one-twelfth of the NEPOOL EHV PTF
Participant Summer or Winter Wheeling Rate in effect for the
calendar year ending December 31, 1996, as determined in
accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its current Entitlements which qualify for transfer
pursuant to subsections (a) or (b) of Section 17.2, except as
otherwise provided in Section 17.3; provided that such
<PAGE>
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payment shall be required with respect to only one-half the
Kilowatts covered by a NEPOOL Exchange Arrangement (as
hereinafter defined).
Each Participant which is a party to the HQ Phase II Firm
Energy Contract (other than a Participant (i) whose system is
directly interconnected to the HQ Interconnection or (ii)
which has contractual rights independent of this Agreement and
the Tariff which give it direct access to the HQ
Interconnection and which are not limited to transfers of
Energy delivered over the HQ Interconnection) shall also pay
each month for the use of EHV PTF for deliveries under the
Phase II Firm Energy Contract during the Base Term of the HQ
Phase II Firm Energy Contract, one-twelfth of the NEPOOL EHV
PTF Participant Summer or Winter Wheeling Rate in effect for
the calendar year ending December 31, 1996, as determined in
accordance with the Prior NEPOOL Agreement, for each Kilowatt
of its HQ Phase II Net Transfer Responsibility for the month.
If, and to the extent that, such Responsibility continues for
any period by which the term of said Contract extends beyond
the Base Term, each such Participant shall continue to pay the
above rate during the extension period with respect to its
continuing Responsibility. A Participant shall not be deemed
to be directly interconnected to the HQ Interconnection for
<PAGE>
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purposes of this paragraph solely because of its participation
in arrangements for the support and/or use of PTF facilities
installed or modified to effect reinforcements of the New
England AC transmission system required in connection with the
HQ Interconnection. A copy of each contract establishing
rights independent of this Agreement and the Tariff which
provides direct access to the HQ Interconnection, or an
opinion of counsel describing and authenticating such rights,
shall be filed with the Secretary of the Management Committee.
The NEPOOL EHV PTF Participant Summer Wheeling Rate for any
calendar year shall be applicable to the months in the Summer
Period.
The NEPOOL EHV PTF Participant Winter Wheeling Rate for any
calendar year shall be applicable to the months in the Winter
Period.
A NEPOOL Exchange Arrangement is one entered into by two
Participants each of which has an ownership interest in a
Pool-Planned Unit on its own system pursuant to which each
sells out of its ownership interest, a Unit Contract
Entitlement to the other for a period of time which is, in
whole or part, the
<PAGE>
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same for both sales. Such an arrangement shall constitute a
NEPOOL Exchange Arrangement even though the beginning and
ending dates of the two Unit Contract sale periods are
different, but only for the period for which both sales are in
effect. If for any period the number of Kilowatts covered by
the two Unit Contract Entitlements of a NEPOOL Exchange
Agreement are not the same, the portion of the larger
Entitlement which exceeds the amount of the smaller
Entitlement shall not be deemed to be covered by such NEPOOL
Exchange Arrangement for purposes of this Section 17.4.
(b) Each Participant shall pay each month for its use of EHV PTF
for a transfer of an Entitlement in a Pool-Planned Unit to a
Non-Participant pursuant to Section 17.2(c) such charge as is
fixed by the Management Committee at the time of its approval
of the sale, and filed with the Commission.
(c) Fifty percent of all amounts required to be paid with respect
to transfers by a Participant pursuant to subsection (a) or
(b) of Section 17.2 shall be paid to a pool transmission fund
and distributed monthly among the Participants in proportion
to the respective amounts of their costs with respect to EHV
PTF for
<PAGE>
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the calendar year 1996 as determined in accordance with the
Prior NEPOOL Agreement.
(d) The remaining 50% of all amounts required to be paid with
respect to transfers by a Participant pursuant to subsections
(a) or (b) of Section 17.2 shall be paid to, and retained by,
the Participant on whose system the transfer originates, or in
the event the EHV PTF system of such Participant is supported
in part by other Participants, then to the Participant on
whose system the transfer originates and such other
Participants in proportion to the respective shares of the
costs of such EHV PTF system borne by each of them or in such
other manner as the Participants involved may jointly direct;
provided that the Participant on whose system the transfer
originates shall have the right to waive such 50% payment in
whole or part as to a particular transfer except that no such
waiver may adversely affect the payments to any other
Participant which is supporting in part the originating
system's EHV PTF system.
17.5 Payments for Uses of Lower Voltage PTF. Each Participant which uses
---------------------------------------
another Participant's Lower Voltage PTF pursuant to this Section 17
shall pay each month to the owner of such Lower Voltage PTF (1) for
each Kilowatt of its use of such Lower
<PAGE>
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Voltage PTF for transfer of Entitlements pursuant to Subsections
17.2(a), (b) or (c) during the month, and (2) during the Base Term of
the HQ Phase II Firm Energy Contract (and during any extension of the
term of said Contract if and to the extent its HQ Phase II Net Transfer
Responsibility continues during the extension period) for each Kilowatt
of its HQ Phase II Net Transfer Responsibility for the month, the
owner's Lower Voltage PTF Winter Wheeling Rate or Summer Wheeling Rate
for the 1996 calendar year, as determined in accordance with the Prior
NEPOOL Agreement.
17.6 Use of Other Transmission Facilities by Participants. Each Participant
----------------------------------------------------
which has no direct connection between its system and PTF shall be
entitled to use the non-PTF transmission facilities of any other
Participant required to reach its system for any of the purposes for
which PTF may be used under Section 17.2. Such use shall be effected,
and payment made, in accordance with the other Participant's filed open
access tariff.
17.7 Limits on Individual Transmission Charges.
-----------------------------------------
Any charges for transmission service pursuant to this Section 17 by any
Participant to another Participant shall be just, reasonable and not
unduly discriminatory or
<PAGE>
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preferential. No provision of this Section 17 shall be construed to
waive the right of any Participant to seek review of any charge, term
or condition applicable to such transmission service by another
Participant by the Commission or any other regulatory authority having
jurisdiction of the transaction.
PART FIVE
GENERAL
SECTION 18
GENERATION AND TRANSMISSION FACILITIES
--------------------------------------
18.1 Designation of Pool-Planned Facilities.
--------------------------------------
At the request of a Participant, the Management Committee shall
designate as "pool-planned" a generating or transmission facility to be
constructed by the Participant or its Related Person if the Management
Committee determines that the facility is consistent with NEPOOL
planning. The Management Committee may not unreasonably withhold
designation as a Pool-Planned Facility of a generation unit or other
facility proposed by one or more Participants in order to satisfy their
anticipated Installed Capability
<PAGE>
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Responsibilities with a mix of generation and other resources
reasonably comparable as to economics and types to that being developed
for New England.
18.2 Construction of Facilities.
--------------------------
Subject to Sections 13.1, 15.2, 15.5, 18.3, 18.4 and 18.5, and to the
provisions of the Tariff, each Participant shall have the right to
determine whether, and to what extent, additions to and modifications
in its generating and transmission facilities shall be made. However,
each Participant shall give due consideration to recommendations made
to it by the Management Committee or the System Operator for any such
additions or modifications and shall follow such recommendations unless
it determines in good faith that the recommended actions would not be
in its best interest.
18.3 Protective Devices for Transmission Facilities and Automatic Generation
-----------------------------------------------------------------------
Control Equipment.
-----------------
Each Participant shall install, maintain and operate such protective
equipment and switching, voltage control, load shedding and emergency
facilities as the Management Committee may determine to be required in
order to assure continuity of service and the stability of the
interconnected transmission facilities of the Participants. Until the
Second Effective Date, each Participant shall also install, maintain
and operate such
<PAGE>
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Automatic Generation Control equipment as the Management Committee may
determine to be required in order to maintain proper frequency for the
interconnected bulk power system of the Participants and to maintain
proper power flows into and out of the NEPOOL Control Area.
18.4 Review of Participant's Proposed Plans.
--------------------------------------
Each Participant shall submit to the System Operator, Management
Committee, the Market Reliability Planning Committee or the Regional
Transmission Planning Committee, as appropriate, and the Regional
Market Operations Committee or the Regional Transmission Operations
Committee, as appropriate, for review by them, in such form, manner and
detail as the Management Committee may reasonably prescribe, (i) any
new or materially changed plan for additions to, retirements of, or
changes in the capacity of any supply and demand-side resources or
transmission facilities rated 69 kV or above subject to control of such
Participant, and (ii) any new or materially changed plan for any other
action to be taken by the Participant which may have a significant
effect on the stability, reliability or operating characteristics of
its system or the system of any other Participant. No significant
action (other than preliminary engineering action) leading toward
implementation of any such new or changed plan
<PAGE>
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shall be taken earlier than sixty days (or ninety days, if the System
Operator or the Management Committee determines that it requires
additional time to consider the plan and so notifies the Participant in
writing within the sixty days) after the plan has been submitted to the
Committees. Unless prior to the expiration of the sixty or ninety days,
whichever is applicable, the Management Committee notifies the
Participant in writing that it has determined that implementation of
the plan will have a significant adverse effect upon the reliability or
operating characteristics of its system or of the systems of one or
more other Participants, the Participant shall be free to proceed. The
time limits provided of this Section 18.4 may be changed with respect
to any such submission by agreement between the Management Committee
and the Participant required to submit the plan.
18.5 Participant to Avoid Adverse Effect.
-----------------------------------
If the Management Committee notifies a Participant pursuant to Section
18.4 that implementation of the Participant's plan has been determined
to have a significant adverse effect upon the reliability or operating
characteristics of its system or the systems of one or more other
Participants, the Participant shall not proceed to implement such plan
unless the Participant takes such action or constructs at its expense
<PAGE>
-226-
such facilities as the Management Committee determines to be reasonably
necessary to avoid such adverse effect; provided that if the plan is
for the retirement of a supply or demand-side resource, the Participant
may proceed with its plan only if, after engaging in good faith
negotiations with persons designated by the Management Committee to
address the adverse effects on reliability or operating
characteristics, the negotiations either address the adverse effects to
the satisfaction of the Management Committee, or no satisfactory
resolution can be achieved on terms acceptable to the parties within 90
days of the Participant's receipt of the Management Committee's notice.
Any agreement resulting from such negotiations shall be in writing and
shall be filed in accordance with the Commission's filing requirements
if it requires any payment.
SECTION 19
EXPENSES
--------
19.1 Annual Fee.
----------
Each Participant shall pay to NEPOOL in January of each year an annual
fee of $500, which shall be applied toward NEPOOL expenses.
<PAGE>
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19.2 NEPOOL Expenses.
---------------
It is an objective of the Participants to work with the System Operator
to establish to the maximum extent possible fees for services rendered
that fairly allocate NEPOOL and System Operator costs directly to the
Participants and Non-Participants responsible for such costs, rather
than through the general expense allocation identified below. Subject
to the continued payment of a portion of NEPEX Expenses from the
Savings Fund until the Second Effective Date in accordance with the
Prior NEPOOL Agreement, the balance of NEPOOL expenses remaining to be
paid after the application of (i) the annual fee to be paid pursuant to
Section 19.1, and (ii) any fees or other charges for services or other
revenues received by NEPOOL, or collected on its behalf by the System
Operator, shall be allocated among and paid monthly by the Participants
in accordance with their respective Voting Shares.
<PAGE>
-228-
SECTION 20
INDEPENDENT SYSTEM OPERATOR
---------------------------
(a) The Management Committee is authorized and directed to approve
one or more agreements to be entered into with the ISO upon
its activation (the "ISO Agreement") and any amendments to the
ISO Agreement which the Committee may deem necessary or
appropriate from time to time. The ISO Agreement shall
specify the rights and responsibilities of NEPOOL and the ISO,
for the continued operation of the NEPOOL control center by
the ISO as the control center operator for the NEPOOL Control
Area and the administration of the Tariff. In addition, the
ISO shall be responsible for the furnishing of billing and
other services required by NEPOOL.
(b) The fees and charges of the ISO (other than fees and charges
for services which are separately billed), and any
indemnification payable under the ISO Agreement, shall be
shared by the Participants in accordance with Section 19.
(c) The Participants shall provide to the ISO the financial
support, information and other resources necessary to enable
the ISO to provide the services specified in
<PAGE>
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the ISO Agreement, or in this Agreement, in accordance with
Good Utility Practice and subject to the budgeting, approval
and dispute resolution provisions of the ISO Agreement and
this Agreement.
(d) The Participants shall provide appropriate funding for the
acquisition of land, structures, fixtures, equipment and
facilities, and other capital expenditures for the ISO, which
are included in the annual budget for the ISO in accordance
with the provisions of the ISO Agreement, or otherwise
specifically approved by the Management Committee. All such
land, structures, fixtures, equipment and facilities, and
other capital assets, and all software or other intellectual
property or rights to intellectual property or other assets,
acquired or developed by the ISO in order to carry out its
responsibilities under the ISO Agreement shall be the property
of the Participants or shall be acquired by the Participants
under lease in accordance with arrangements approved by the
Management Committee. Unless otherwise agreed by the
Participants, the funding of the acquisition, or lease, of
land, structures, fixtures, equipment and facilities, and
other capital expenditures, or the acquisition of other
assets, and the ownership thereof, or the obligations of
Participants as lessees, shall be in proportion to the Voting
Shares of each Participant in effect from time to time. The
Participants
<PAGE>
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shall make all such assets (including the assets of the
existing NEPOOL headquarters and control center) available for
use by the ISO in carrying out its responsibilities under the
ISO Agreement. The ISO Agreement shall require the ISO, on
behalf of the Participants, to maintain and care for, insure
as appropriate, and pay any property taxes relating to, assets
made available for its use.
(e) The ISO Agreement shall require the ISO to refrain from any
action that would create any lien, security interest or
encumbrance of any kind upon the facilities, equipment or
other assets of any Participant, or upon anything that becomes
affixed to such facilities, equipment or other assets. The
Participants and the ISO shall include in the ISO Agreement a
provision that, upon the request of any Participant, the ISO
shall (i) provide a written statement that it has taken no
action that would create any such lien, security interest or
encumbrance, and (ii) take all actions within the control of
the ISO, at the direction and expense of the requesting
Participant, required for compliance by such Participant with
the provisions of its mortgage relating to such facilities,
equipment or other assets.
<PAGE>
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(f) The ISO shall have the right to appoint a non-voting member
and an alternate to each NEPOOL committee other than the
Management Committee. The member appointed to each committee
shall have all of the rights of any other member of the
committee except the right to vote.
(g) The ISO shall have the same rights as a Participant to appeal
to the Management Committee any action taken by any other
NEPOOL committee, and shall be entitled to appear before the
Management Committee on any such appeal. Further, the ISO
shall be entitled to submit any dispute with respect to a vote
of the Management Committee to approve, modify, or reject a
proposed action to resolution in accordance with Section 21.1,
whether or not the action could have been submitted by a
Participant in accordance with Section 21.1A. In addition,
the ISO shall be entitled to submit any dispute with respect
to a vote of the Management Committee which denies an appeal
to the Management Committee by the ISO or which takes action
on any rulemaking issue to the Board of Directors of the ISO
for determination, subject to the right of the Management
Committee to seek a review in accordance with the Alternate
Dispute Resolution procedures or by the Commission. The ISO
shall give notice of any such submission to the Secretary of
the Management Committee within ten days of
<PAGE>
-232-
the action of the Management Committee and shall mail a copy
of such notice to each member of the Management Committee.
Pending final action on the submission in accordance with
Section 21.1 or by the Board of Directors of the ISO or the
Commission, as appropriate, the giving of notice of the
submission shall suspend the Management Committee's action.
Unless the Board of Directors of the ISO acts within 60 days
of the ISO's notice to the Management Committee, the
Management Committee action will be deemed to be approved.
(h) The ISO Agreement shall specify the ISO's independent
authority with respect to rulemaking.
(i) NEPOOL and its committees and the ISO shall consult and
coordinate from time to time with the relevant state
regulatory, siting and other authorities of the six New
England states on operating, planning and other issues of
concern to the states. The New England Conference of Public
Utilities Commissioners, Inc. (NECPUC) or its designee shall
be furnished notices of meetings of all NEPOOL committees and
the Board of Directors of the ISO, and minutes of their
meetings. NECPUC and other state authorities shall be
provided an appropriate opportunity to appear at meetings of
the NEPOOL committees and
<PAGE>
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the Board of Directors of the ISO and to present their views.
Representatives of NEPOOL and the ISO shall be designated to
attend meetings of NECPUC or any committee or task force of
NECPUC, to the extent NECPUC or its committee or task force
may deem such attendance appropriate.
SECTION 21
MISCELLANEOUS PROVISIONS
------------------------
21.1 Alternative Dispute Resolution.
------------------------------
A. General:
-------
If the ISO is aggrieved by a vote of the Management Committee
to approve, modify or reject a proposed action under this
Agreement, including the Tariff, it may submit the matter for
resolution hereunder. If the Management Committee is aggrieved
by an action of the ISO Board of Directors ("ISO Board") under
this Agreement, including the Tariff or the ISO Agreement (as
defined in Section 20(a)), the Management Committee may submit
the matter for resolution hereunder; provided, however, that
if the action of the ISO relates to
<PAGE>
-234-
rulemaking, the Management Committee may submit the matters
for resolution under this Section 21.1 only with the
concurrence of the ISO. Any Participant which is aggrieved by
a vote of the Management Committee to approve, modify or
reject a proposed action under this Agreement, including the
Tariff, may, as provided below, submit the matter for
resolution hereunder if the vote:
(1) requires such Participant to make a payment or to
take any action pursuant to this Agreement; or
(2) reduces the amount of any receipt or forbids,
pursuant to this Agreement, the taking of any action
by the Participant; or
(3) fails to afford it any right to which it is entitled
under the provisions of this Agreement or imposes on
it a burden to which it is not subject under the
provisions of this Agreement; or
(4) results in the termination of the Participant's
status as a Participant or imposes any penalty on the
Participant; or
<PAGE>
-235-
(5) results in an allocation of transmission or other
facilities support obligations; or
(6) fails to grant in full an application for
transmission service pursuant to the Tariff.
No legal or regulatory proceeding (except those reasonably
necessary to toll statutes of limitations, claims for laches
or other bars to later legal or regulatory action) shall be
initiated by any Participant with respect to any such matter
while proceedings are pending under this Section with respect
to the matter.
B. Procedure:
---------
(1) Submission of a Dispute: The ISO or a Participant
-------------------------
seeking review of a vote of the Management Committee
shall give written notice to the Secretary of the
Management Committee within ten business days of the
vote, and shall mail or telecopy a copy of its notice
to each member of the Management Committee. Where the
Management Committee is seeking review of an action
of the ISO Board, the Management
<PAGE>
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Committee shall give written notice to the Secretary
of the ISO Board. The provider of notice under this
Section shall be referred to herein as the "Aggrieved
Party."
(2) Suspension of Action: If the ISO seeks review of a
---------------------
vote of the Management Committee pursuant to this
Section, the vote to be reviewed shall be suspended
pending resolution of such review by the arbitrator
or the Commission if raised in regulatory
proceedings. If a Participant seeks such a review,
the vote to be reviewed shall be suspended for up to
90 days following the giving of the Participant's
notice pending resolution of any arbitration
proceeding unless the Management Committee determines
that the suspension will imperil the stability or
reliability of the NEPOOL Control Area bulk power
supply.
(3) Aggrieved Party Options: (i) If the notice is to seek
-----------------------
review of a vote of the Management Committee, the
Aggrieved Party's notice to the Management Committee
shall invoke arbitration as described herein in its
notice pursuant to paragraph B(1), and may also
initiate mediation with the agreement of the
Management Committee, while reserving such
<PAGE>
-237-
Party's right to proceed with the arbitration if
mediation does not resolve the matter within 20 days
of the giving of the Party's notice or such longer
period as may be fixed by mutual agreement of the
Management Committee and the Aggrieved Party.
Notwithstanding the initiation of mediation, the
arbitration proceeding shall proceed concurrently
with the selection of the arbitrator pursuant to
paragraph C(1) of this Section 21.1.
(ii) If the notice is to seek review of an ISO action, the
Management Committee's notice to the ISO Board shall
(subject to the concurrence of the ISO for actions
relating to rulemaking as provided in Section 21.1A)
invoke arbitration as described herein in its notice
pursuant to paragraph B(1), and may also initiate
mediation with the agreement of the ISO Board, while
reserving the Management Committee's right to proceed
with the arbitration if mediation does not resolve
the matter within 20 days of the giving of the
Management Committee's notice or such longer period
as may be fixed by mutual agreement of the ISO Board
and the Management Committee. Notwithstanding the
initiation of mediation,
<PAGE>
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the arbitration proceeding shall proceed concurrently
with the selection of the arbitrator pursuant to
paragraph C(1) of this Section 21.1.
(4) Mediation Positions not to be Used Elsewhere: All
-----------------------------------------------
mediation proceedings pursuant to this Section are
confidential and shall be treated as compromise and
settlement negotiations for purposes of applicable
rules of evidence.
(5) Time Limits; Duration: Any other Participant that
----------------------
wishes to participate in an arbitration proceeding
hereunder shall give signed written notice to the
Secretary of the Management Committee, and to the
Secretary of the ISO Board if the ISO is involved in
such arbitration, no later than ten calendar days
after the giving of the notice of arbitration. The
arbitration procedure shall not exceed 90 calendar
days from the date of the Aggrieved Party's notice
invoking arbitration to the arbitrator's decision
unless the parties agree upon a longer or shorter
time. All agreements by the ISO or the aggrieved
Participant and the Management Committee to use
mediation shall establish a schedule which will
control unless later changed by mutual agreement.
<PAGE>
-239-
C. Arbitration:
-----------
(1) Selection of Arbitrator: The ISO or the
-------------------------
aggrieved Participant and the Management
Committee shall attempt to choose by mutual
agreement a single neutral arbitrator to
hear the dispute. If the ISO or the
Participant and the Management Committee
fail to agree upon a single arbitrator
within ten calendar days of the giving of
notice of arbitration to the Secretary of
the Management Committee or the Secretary of
the ISO Board, as the case may be, the
American Arbitration Association shall be
asked to appoint an arbitrator. In either
case, the arbitrator shall be knowledgeable
in matters involving the electric power
industry, including the operation of control
areas and bulk power systems, and shall not
have any substantial business or financial
relationships with the ISO, NEPOOL or its
Participants (other than previous experience
as an arbitrator) unless otherwise mutually
agreed by the ISO or the aggrieved
Participant and the Management Committee.
<PAGE>
-240-
(2) Costs: NEPOOL shall be responsible for all
-----
of the costs of the proceeding if it is
initiated by the ISO or by the Management
Committee. If a proceeding is initiated by
an aggrieved Participant, each party shall
be responsible for the following costs, if
applicable:
(i) its own costs incurred during the
arbitration process (except that
this does not preclude billing the
aggrieved Participant for its share
of NEPOOL Expenses that may include
the Management Committee's
arbitration costs); plus
----
(ii) One half of the common costs of the
arbitration including, but not
limited to, the arbitrator's fee and
expenses, the rental charge for a
hearing room and the cost of a court
reporter and transcript, if
required.
(3) Hearing Location: Unless otherwise mutually
----------------
agreed, the site for all arbitration
hearings shall be NEPOOL counsel's office.
<PAGE>
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D. Rules and Procedures:
--------------------
(1) Procedure and Discovery: The procedural
-------------------------
rules (if any), the conduct of the
arbitration and the availability, extent and
duration of pre-hearing discovery (if any),
which shall be limited to the minimum
necessary to resolve the matters in dispute,
shall be determined by the arbitrator in
his/her sole discretion at or prior to the
initial hearing.
(2) Pre-hearing Submissions: The Aggrieved Party
-----------------------
shall provide the arbitrator with a brief
written statement of its complaint and a
statement of the remedy or remedies it
seeks, accompanied by copies of any
documents or other materials it wishes the
arbitrator to review. The Management
Committee will provide the arbitrator with a
copy of this Agreement and all relevant
implementing documents, a brief description
of the action being arbitrated, copies of
the minutes of all NEPOOL committee meetings
at which the matter was discussed, a brief
statement explaining why the Management
Committee believes its decision
<PAGE>
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should be upheld by the arbitrator, and
copies of any documents or other materials
the Management Committee wishes the
arbitrator to review. If the Management
Committee is the Aggrieved Party, the ISO
Board will provide copies of minutes of the
ISO Board meetings at which the matter was
discussed, a brief statement explaining why
the ISO Board believes its decision should
be upheld by the arbitrator, and copies of
any documents or other materials the ISO
Board wishes the arbitrator to review. These
submissions shall be made within five days
after the selection of the arbitrator.
In addition, each party shall designate one
or more individuals to be available to
answer questions the arbitrator may have on
the documents or other materials submitted
by that party. The answers to all such
questions shall be reduced to writing by the
party providing the answer and a copy shall
be furnished to the other party.
<PAGE>
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(3) Initial Hearing: An initial hearing will be
---------------
held no later than 10 days after the
selection of the arbitrator and shall be
limited to issues raised in the pre-hearing
filings. The scheduling of further hearings
at the request of either party or on the
arbitrator's own motion shall be within the
sole discretion of the arbitrator.
(4) Decision: The arbitrator's decision shall be
--------
due, unless the deadline is extended by
mutual agreement of the ISO or the aggrieved
Participant and the Management Committee,
within sixty days of the initial hearing or
within ninety days of the Aggrieved Party's
initiation of arbitration, whichever occurs
first. The arbitrator shall be authorized
only to interpret and apply the provisions
of this Agreement and the arbitrator shall
have no power to modify or change the
Agreement in any manner.
(5) Effect of Arbitration Decision: The decision
------------------------------
of the arbitrator will be conclusive in a
subsequent regulatory or legal proceeding as
to the facts determined by the arbitrator
but will not be conclusive
<PAGE>
-244-
as to the law or constitute precedent on issues of
law in any subsequent regulatory or legal
proceedings.
An aggrieved party may initiate a proceeding with a
court or with the Commission with respect to the
arbitration or arbitrator's decision only:
o if the arbitration process does not
result in a decision within the time
period specified and the proceeding
is initiated within thirty days
after the expiration of such time
period; or
o on the grounds specified in Sections
10 and 11 of Title 9 of the United
States Code for judicial vacation or
modification of an arbitration award
and the proceeding is initiated
within thirty days of the issuance
of the arbitrator's decision.
(6) Other Disputes: In the event a dispute
---------------
arises with a Non-Participant which receives
or is eligible to receive service under
<PAGE>
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this Agreement or the Tariff with respect to
such service, the Non-Participant shall have
the right to have the dispute considered by
the Management Committee. In the event the
Non-Participant is aggrieved by the
Management Committee's vote on the dispute,
and the vote has any of the effects
specified in paragraph A of this Section
21.1, the aggrieved Non-Participant may
require that the dispute be resolved in
accordance with this Section 21.1. To the
extent that NEPOOL provides services to
Non-Participants under separate agreements,
the Management Committee shall incorporate
the provisions of this Section by reference
in any such agreement, in which case the
term "Participant" shall be deemed for
purposes of the dispute resolution
provisions to include such Non-Participant
purchasers of NEPOOL services.
<PAGE>
-246-
21.2 Payment of Pool Charges; Termination of Status as Participant.
-------------------------------------------------------------
(a) Any Participant shall have the right to terminate its status
as a Participant upon no less than six months' prior written
notice given to the Secretary of the Management Committee.
(b) If at any time during the term of this Agreement a receiver or
trustee of a Participant is appointed or a Participant is
adjudicated bankrupt or an order for relief is entered under
the Federal Bankruptcy Code against a Participant or if there
shall be filed against any Participant in any court (pursuant
to the Federal Bankruptcy Code or any statute of Canada or any
state or province) a petition in bankruptcy or insolvency or
for reorganization or for appointment of a receiver or trustee
of all or a portion of the Participant's property, and within
ninety days after the filing of such a petition against the
Participant, the Participant shall fail to secure a discharge
thereof, or if any Participant shall file a petition in
voluntary bankruptcy or seeking relief under any provision of
any bankruptcy or insolvency law or shall make an assignment
for the benefit of creditors, the Management Committee may
terminate such Participant's status as a Participant as of any
time thereafter.
<PAGE>
-247-
(c) Each Participant is obligated to pay when due in accordance
with NEPOOL procedures all amounts invoiced to it by NEPOOL,
or by the ISO on behalf of NEPOOL. If a Participant disputes
a NEPOOL invoice in whole or part, it shall be entitled to
continue to receive service under the Agreement and the
Tariff, so long as the Participant (i) continues to make all
payments not in dispute, and (ii) pays into an independent
escrow account the portion of the invoice in dispute, pending
resolution of the dispute. If the Participant fails to meet
these two requirements for continuation of service, NEPOOL may
suspend service, in whole or part, to the Participant sixty
days after the giving of notice to the Participant of NEPOOL's
intention to suspend service, in accordance with Commission
policy.
(d) In the event a Participant fails, for any reason other than a
billing dispute as described in subsection (c) of this Section
21.2, to pay when due in accordance with NEPOOL procedures all
amounts invoiced to it by NEPOOL, or by the ISO on behalf of
NEPOOL, or the Participant fails to perform any other
obligation under the Agreement or the Tariff, and such failure
continues for at least ten days, NEPOOL may notify the
Participant that it is in default and may initiate a
proceeding before the Commission to terminate such
Participant's
<PAGE>
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status as a Participant. Pending Commission action on such
termination, NEPOOL may suspend service, in whole or part, to
the Participant on or after 50 days after the giving of such
notice and the initiation of such proceeding, in accordance
with Commission policy, unless the Participant cures the
default within such 50-day period.
(e) If the status of a Participant as a Participant is terminated
pursuant to this Section 21.2 or any other provision of this
Agreement, such former Participant's generation and
transmission facilities shall continue to be subject to such
NEPOOL or other requirements relating to reliability as the
Commission may approve in acting on the termination, for so
long as the Commission may direct. Further, if any of such
former Participant's transmission facilities are required in
order to permit transactions among any of the remaining
Participants pursuant to this Agreement or the Tariff, all
pending requests for transmission service under the Tariff
relating to such Participant's facilities shall be followed to
completion under the Participant's own tariff and all existing
service over the Participant's facilities shall continue to be
provided under the Tariff for a period of three years. It is
the intent of this subsection that no such termination should
be allowed to jeopardize the reliability of the bulk power
facilities of any
<PAGE>
-249-
remaining Participant or should be allowed to impose any
unreasonable financial burden on any remaining Participant.
(f) No such termination of a Participant's status as a Participant
shall affect any obligation of, or to, such former Participant
arising prior to the effective time of such termination.
21.3 Assignment. The Agreement shall inure to the benefit of, and shall be
----------
binding upon, the successors and assigns of the respective signatories
hereto, but no assignment of a signatory's interests or obligations
under the Agreement or any portion thereof shall be made without the
written consent of the Management Committee, except as otherwise
permitted by the Tariff, or except in connection with a sale, merger,
or consolidation which results in the transfer of all or a portion of a
signatory's generation or transmission assets to, and the assumption of
all of the obligations of the signatory under this Agreement (or in the
case of a transfer of a portion of a signatory's generation or
transmission assets, the assumption of obligations of the signatory
under this Agreement with respect to such assets) by, an acquiring or
surviving Entity which either is, or concurrently becomes, a
Participant, or agrees to assume such of the signatory's obligations
with respect to such assets as the Management Committee may
<PAGE>
-250-
reasonably require, or except in connection with the grant of a
security interest in a Participant's assets as security for bonds or
other financing.
21.4 Force Majeure. A Participant shall not be considered to be in default
-------------
in respect of any obligation hereunder if prevented from fulfilling
such obligation by an event of Force Majeure. An event of Force Majeure
means any act of God, labor disturbance, act of the public enemy, war,
insurrection, riot, fire, storm or flood, explosion, breakage or
accident to machinery or equipment not due to lack of proper care or
maintenance, any order, regulation or restriction imposed by a court or
governmental military or lawfully established civilian authorities, or
any other cause beyond a Participant's control, provided that no event
of Force Majeure affecting any Participant shall excuse that
Participant from making any payment that it is obligated to make under
this Agreement. A Participant whose performance under this Agreement is
hindered by an event of Force Majeure shall make all reasonable efforts
to perform its obligations under this Agreement, and shall promptly
notify the Management Committee of the commencement and end of any
event of Force Majeure.
21.5 Waiver of Defaults. No waiver of the performance by a Participant of
------------------
any obligation under this Agreement or with respect to any default or
any other matter arising in
<PAGE>
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connection with this Agreement shall be effective unless given by the
Management Committee. Any such waiver by the Management Committee in
any particular instance shall not be deemed a waiver with respect to
any subsequent performance, default or matter.
21.6 Other Contracts. No Participant shall be a party to any other agreement
---------------
which in any manner is inconsistent with its obligations under this
Agreement.
21.7 Liability and Insurance.
-----------------------
(a) Each Participant will indemnify and save each of the other
Participants, its officers, directors and Related Persons
(each an "Indemnified Party") harmless from and against all
actions, claims, demands, costs, damages and liabilities
asserted by a third party against the Indemnified Party
seeking indemnification and arising out of or relating to
bodily injury, death or damage to property caused by or
sustained on facilities owned or controlled by such
Participant that are the subject of this Agreement, or caused
by a failure to act in accordance with this Agreement by the
Participant from which indemnification is sought, except (i)
to the extent that such liabilities result from the negligence
or willful
<PAGE>
-252-
misconduct of the Participant seeking indemnification, and
(ii) each Participant shall be responsible for all claims of
its own employees, agents and servants growing out of any
workmen's compensation law. The amount of any indemnity
payment under the provisions of this Section 21.7 shall be
reduced (including, without limitation, retroactively) by any
insurance proceeds or other amounts actually recovered by the
Indemnified Party in respect of the indemnified action, claim,
demand, cost, damage or liability. Notwithstanding the
foregoing, no Participant shall be liable to any Indemnified
Party for any claim for loss of profits or revenues, attorneys
fees or costs, cost of capital or financing, loss of goodwill
or cost of replacement power arising from a Participant's
carrying out, or failing to carry out, any obligations
contemplated by this Agreement or for any other indirect,
incidental, special, consequential, punitive, or multiple
damages or loss; provided, however, that nothing herein shall
reduce or limit the obligations of any Participant to
Non-Participants.
(b) Each Participant shall furnish, at its sole expense, such
insurance coverage as the Management Committee may reasonably
require with respect to its obligation pursuant to Section
21.7(a).
<PAGE>
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21.8 Records and Information. Each Participant shall keep such records as
-----------------------
may reasonably be required by a NEPOOL committee or the System
Operator, and shall furnish to such committee or the System Operator
such records, reports and information (including forecasts) as it may
reasonably require, provided the confidentiality thereof is protected
in accordance with NEPOOL's information policy.
21.9 Consistency with NPCC and NERC Standards. The standards, criteria and
----------------------------------------
rules adopted by NEPOOL committees under this Agreement shall be
consistent with those adopted by the Northeast Power Coordinating
Council and the North American Electric Reliability Council or any
successor to either.
21.10 Construction.
------------
(a) The Table of Contents contained in this Agreement and the
headings of the Sections of this Agreement are intended for
convenience only and shall not be deemed to be part of this
Agreement or considered in construing it.
(b) This Agreement shall be interpreted, construed and governed in
accordance with the laws of the State of Connecticut.
<PAGE>
-254-
21.11 Amendment. This Agreement, including the Tariff, and any attachment or
---------
exhibit hereto may be amended from time to time by an instrument signed
by Participants having aggregate Voting Shares equal to at least 70% of
the Voting Shares of all Participants; provided that an amendment shall
not become effective if two or more Participants which are not Related
Persons of each other and which have aggregate Voting Shares at least
equal to 20% of the Voting Shares of all Participants give notice to
the Secretary of the Management Committee that they object to the
amendment within thirty days after the giving of notice to them of the
prospective effectiveness of the amendment. In determining whether the
20% requirement has been met, the following limitation shall be
applied: if the aggregate Voting Share of any objecting Participant and
its Related Persons exceeds 18%, the aggregate Voting Share of such
Participant and its Related Persons for this purpose shall be reduced
to 18%.
Any amendment to this Agreement shall be in writing and shall become
effective on the date specified in the amendment, subject to acceptance
or approval by the Commission, whether or not the remaining
Participants agree, provided that the remaining Participants shall have
been given written notice of the prospective effectiveness of such
amendment at least thirty days prior to the effective date of such
amendment, and provided further, that such an amendment does not impose
a burden on such remaining
<PAGE>
-255-
Participants which is materially different in nature or materially
greater in degree than that imposed on the Participants which have
agreed to such amendment. Such notice shall be accompanied by a form of
notice which may be signed and returned to the Secretary of the
Management Committee to state a Participant's objection to the
amendment. Any Participant which has given notice of its objection to
such amendment shall be entitled to terminate its status as a
Participant effective as of the effective date of such amendment by
giving to the Secretary of the Management Committee written notice of
such termination within thirty days after notice has been given to it
of the prospective effectiveness of such amendment. Effective as of
thirty days after the giving of such notice of the prospective
effectiveness of such amendment, any Participant which has not
previously given notice of its objection to such amendment and which
does not give notice of termination of status as herein provided within
such thirty-day period shall thereafter be bound by such amendment;
provided that nothing herein shall be construed to prevent any
Participant from challenging any proposed amendment before a court or
regulatory agency on the ground that the proposed amendment or its
application to the Participant is in violation of law or of this
Section 21.11.
<PAGE>
-256-
21.12 Termination. This Agreement shall continue in effect until terminated,
-----------
in accordance with the Commission's regulations, by Participants
represented by members of the Management Committee having Voting Shares
equal to at least 70% of the Voting Shares of all Participants. No such
termination shall relieve any party of any obligation arising prior to
the effective time of such termination.
21.13 Notices to Participants.
-----------------------
(a) Any notice, demand, request or other communication required or
authorized by this Agreement to be given to any Participant
shall be in writing, and shall be (1) personally delivered to
the Management Committee member or alternate appointed by the
Participant; (2) mailed, postage prepaid, to the Participant
at the address of its member on the Management Committee as
set out in the NEPOOL roster; (3) sent by facsimile ("faxed")
to the Participant at the fax number of its member on the
Management Committee as set out in the NEPOOL roster; or (4)
delivered electronically to the Participant at the electronic
mail address of its member on the Management Committee or at
the address of its principal office. The designation of any
such address may be changed at any time by written notice
delivered to the Secretary of the
<PAGE>
-257-
Management Committee, who shall cause such change to be
reflected in the NEPOOL roster.
(b) Any notice, demand, request or other communication required or
authorized by this Agreement to be given to any NEPOOL
committee shall be in writing and shall be delivered to the
Secretary of the committee. Each such notice shall either be
personally delivered to the Secretary, mailed, postage
prepaid, or sent by facsimile ("faxed") to the Secretary at
the address or fax number set out in the NEPOOL roster, or
delivered electronically to the Secretary. The designation of
such address may be changed at any time by written notice
delivered to each Participant.
(c) Any such notice, demand or request so addressed and mailed by
registered or certified mail shall be deemed to be given when
so mailed. Any such notice, demand, request or other
communication sent by regular mail or by facsimile ("faxed")
or delivered electronically shall be deemed given when
received by the Participant or by the Secretary of the
committee, whichever is applicable.
<PAGE>
-258-
21.14 Severability and Renegotiation. If any provision of this Agreement is
-------------------------------
held by a court or regulatory authority of competent jurisdiction to be
invalid, void or unenforceable, the remainder of the terms, provisions,
covenants and restrictions of this Agreement shall continue in full
force and effect and shall in no way be affected, impaired or
invalidated, except as otherwise explicitly provided in this Section.
If any provision of this Agreement is held by a court or regulatory
authority of competent jurisdiction to be invalid, void or
unenforceable, or if the Agreement is modified or conditioned by a
regulatory authority exercising jurisdiction over this Agreement, the
Participants shall endeavor in good faith to negotiate such amendment
or amendments to this Agreement as will restore the relative benefits
and obligations of the Participants under this Agreement immediately
prior to such holding, modification or condition. If after sixty days
such negotiations are unsuccessful the Participants may exercise their
withdrawal or termination rights under this Agreement.
21.15 No Third-Party Beneficiaries. Except for the provisions of this
------------------------------
Agreement and the Tariff which provide for service to Non-Participants,
this Agreement is intended to be solely for the benefit of the
Participants and their respective successors and permitted assigns and,
unless expressly stated herein, is not intended to and shall not confer
any
<PAGE>
-259-
rights or benefits on any third party (other than successors and
permitted assigns) not a signatory hereto.
21.16 Counterparts. This Agreement may be executed in any number of
------------
counterparts, and each executed counterpart shall have the same force
and effect as an original instrument and as if all the parties to all
of the counterparts had signed the same instrument. Any signature page
of this Agreement may be detached from any counterpart of this
Agreement without impairing the legal effect of any signatures thereon,
and may be attached to another counterpart of this Agreement identical
in form hereto but having attached to it one or more signature pages.
IN WITNESS WHEREOF, the signatories have caused this Agreement to be
executed by their duly authorized officers or representatives.
<PAGE>
ATTACHMENT A
TO RESTATED
NEPOOL AGREEMENT
METHODOLOGY FOR
DETERMINATION OF
TRANSMISSION FLOWS
<PAGE>
The methodology for determining parallel path transmission flows to be
used in determining the distribution of revenues received for Regional Network
Service provided during the Transition Period, or for Through or Out Service, is
as follows, and shall be determined (1) on the basis of the flows for all
transactions in the NEPOOL Control Area ("Regional Flows") for the purpose of
allocating during the Transition Period Regional Network Service revenues, and
(2) on the basis of the flows for the particular transaction ("Transaction
Flows") for the purpose of allocating revenues during or after the Transition
Period from the furnishing of Through or Out Service:
A. Responsibility for Calculations
-------------------------------
The calculation of megawatt mile allocations in accordance with this
methodology shall be performed under the direction of the Regional Transmission
Planning Committee ("RTPC").
B. Periodic Review
---------------
Calculations of MW-Mile allocations shall be performed whenever
significant changes to the transmission system load flows, as determined by the
RTPC, occur.
<PAGE>
-2-
C. Facilities Included in the Analysis
-----------------------------------
1. Transmission Lines
A calculation of MW-miles shall be determined for all
PTF lines.
2. Generators
The analysis shall include all generators with a
Winter Capability equal to or greater than 10.0 MW.
Multiple generators connected to a single bus with a
total Winter Capability equal to or greater than 10.0
MW shall also be included.
3. Transformers
All transformers connecting PTF transmission lines
shall be included in the analysis.
<PAGE>
-3-
D. Determination of Rate Distribution
----------------------------------
1. General
Modeling of the transmission system shall be
performed using a system simulation program and
associated cases as approved by the RTPC.
2. Determination of Regional Flows
The change in real power flow (MW) over each
transmission line and transformer shall be determined
for each generator (or group of generators on a
single bus) by determining the absolute value of the
difference between the flows on each facility with
the generator(s) modeled off and while operating at
its net Winter Capability. In addition, a generator
shall be simulated at each transmission line tie to
the NEPOOL Control Area and changes in flow
determined for this generator off or while generating
at a level of 100 MW. Loads throughout the NEPOOL
Control Area shall be proportionally scaled to
account for differences in generator output and
electrical losses. The
<PAGE>
-4-
changes in flow shall be multiplied by the length of
each respective line. Changes in flow through
transformers shall be multiplied by a factor of five.
Changes in flow through phase-shifting transformers
shall be multiplied by a factor of ten. The resulting
values represent the MW-miles associated with each
facility.
3. Determination of Transaction Flows
a. Definition of Supply and Receipt Areas
For the purposes of these calculations,
areas of supply and receipt shall be
determined by the RTPC. These areas shall be
based on the system boundaries of each Local
Network.
b. Calculation of MW-Miles
The change in real power flow (MW) over each
transmission line and transformer shall be
determined for each combination of supply
and receipt areas by determining the
absolute value of the
<PAGE>
-5-
difference between the flows on each
facility following a scaled increase of the
supplying areas generation by 100 MW. Loads
in the area of receipt shall be scaled to
account for changes in generation and
electrical losses. In instances where the
areas of supply and/or receipt are outside
the NEPOOL Control Area, the changes in real
power flow will be determined only for
facilities within the NEPOOL Control Area.
The changes in flow shall then be multiplied
by the length of each respective line.
Changes in flow through transformers shall
be multiplied by a factor of five. Changes
in flow through phase-shifting transformers
shall be multiplied by a factor of ten. The
resulting values represent the MW-miles
associated with each facility.
4. Assignment of MW-Miles to Participants
Each Participant shall have assigned to it the
MW-miles associated with each PTF facility for which
it has full ownership. Each Participant shall also be
assigned MW-miles in proportion to the percentage of
its
<PAGE>
-6-
ownership of jointly-owned facilities or the
percentage of its support for facilities for which it
provides support.
EXHIBIT 10.13a
FIRST AMENDMENT TO AMENDED AND
RESTATED EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 1st day of February, 1998, to the
Amended and Restated Employment Agreement, made as of the 1st day of January,
1988, and amended as of July 23, 1990, June 1, 1995 and March 1, 1997, (the
"Agreement") between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation
(the "Company") and Richard J. Grossi, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2) and (3) below:
(2) By deleting the final sentence of Section (4)(b) in its entirety.
(3) By inserting, following the second sentence of Section (4)(f), the
following sentence: "For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program."
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of
the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Robert L. Fiscus
-----------------------------------
Its President and
Chief Financial Officer
/s/ Kurt Mohlman
---------------------------------
Treasurer and
/s/ Richard J. Grossi Secretary
-----------------------------------
Richard J. Grossi
EXHIBIT 10.14a
FIRST AMENDMENT TO AMENDED AND
RESTATED EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 1st day of February, 1998, to the
Amended and Restated Employment Agreement, made as of the 1st day of January,
1988, and amended as of July 23, 1990, June 1, 1995 and March 1, 1997, (the
"Agreement") between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation
(the "Company") and Robert L. Fiscus, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2) and (3) below:
(2) By deleting the final sentence of Section (4)(b) in its entirety.
(3) By inserting, following the second sentence of Section (4)(f), the
following sentence: "For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program."
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of
the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Richard J. Grossi
-------------------------------------
Its Chairman of the
Board of Directors and
Chief Executive Officer
/s/ Kurt Mohlman
----------------------------
Treasurer and
/s/ Robert L. Fiscus Secretary
-------------------------------------
Robert L. Fiscus
EXHIBIT 10.15a
FIRST AMENDMENT TO AMENDED AND
RESTATED EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 1st day of February, 1998, to the
Amended and Restated Employment Agreement, made as of the 1st day of January,
1988, and amended as of July 23, 1990, June 1, 1995 and March 1, 1997, (the
"Agreement") between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation
(the "Company") and James F. Crowe, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2) and (3) below:
(2) By deleting the final sentence of Section (4)(b) in its entirety.
(3) By inserting, following the second sentence of Section (4)(f), the
following sentence: "For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program."
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of
the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Richard J. Grossi
----------------------------------
Its Chairman of the
Board of Directors and
Chief Executive Officer
/s/ Kurt Mohlman
------------------------------
Treasurer and
/s/ James F. Crowe Secretary
----------------------------------
James F. Crowe
EXHIBIT 10.16a
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 1st day of February, 1998, to the
Employment Agreement, made as of the 1st day of March, 1997, (the "Agreement")
between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation (the
"Company") and ALBERT N. HENRICKSEN, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2) and (3) below:
(2) By deleting the final sentence of Section (4)(b) in its entirety.
(3) By inserting, following the second sentence of Section (4)(f), the
following sentence: "For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program."
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of
the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Richard J. Grossi
-----------------------------------
Its Chairman of the
Board of Directors and
Chief Executive Officer
/s/ Kurt Mohlman
------------------------------
Treasurer and
/s/ Albert N. Henricksen Secretary
-----------------------------------
Albert N. Henricksen
EXHIBIT 10.17a
FIRST AMENDMENT TO
EMPLOYMENT AGREEMENT
This FIRST AMENDMENT, made as of the 1st day of February, 1998, to the
Employment Agreement, made as of the 1st day of March, 1997, (the "Agreement")
between THE UNITED ILLUMINATING COMPANY, a Connecticut corporation (the
"Company") and ANTHONY J. VALLILLO, an individual (the "Executive"),
WITNESSETH THAT:
(1) The Company and the Executive hereby agree to amend the Agreement as
set forth in sections (2) and (3) below:
(2) By deleting the final sentence of Section (4)(b) in its entirety.
(3) By inserting, following the second sentence of Section (4)(f), the
following sentence: "For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program."
(4) All the terms and conditions of the Agreement, as amended hereby are
and shall remain in full force and effect.
(5) This First Amendment to the Agreement may be executed in one or more
counterparts, each of which shall be deemed an original but all of which
together will constitute one and the same instrument.
IN WITNESS WHEREOF, the parties hereto have executed this instrument as of
the day and year first above written.
THE UNITED ILLUMINATING COMPANY
ATTEST:
By /s/ Richard J. Grossi
-------------------------------
Its Chairman of the
Board of Directors and
Chief Executive Officer
/s/ Kurt Mohlman
------------------------------
Treasurer and
/s/ Anthony J. Vallillo Secretary
------------------------------
Anthony J. Vallillo
EXHIBIT 10.28
EMPLOYMENT AGREEMENT
THIS AGREEMENT, made as of the 23rd day of February, 1998, between THE
UNITED ILLUMINATING COMPANY, a Connecticut corporation (the Company) and
NATHANIEL D. WOODSON, an individual (the Executive),
WITNESSETH THAT
WHEREAS, the Company desires to employ the Executive as its President,
effective February 23, 1998, and the Executive desires to be employed by the
Company as its President, effective February 23, 1998; and
WHEREAS, the Company and the Executive desire to enter into a written
agreement conferring upon the Executive certain rights and benefits and imposing
upon the Executive certain duties and obligations,
NOW THEREFORE, in consideration of the foregoing and the respective
covenants and agreements of the parties herein contained and the services to be
rendered to the Company pursuant hereto, and in order to provide an incentive to
the Executive to remain in the employ of the Company hereafter and, in
particular, in the event of any Change in Control (as herein defined) of the
Company, thereby establishing and preserving continuity of management, the
Parties hereby agree as follows:
(1) EMPLOYMENT
(a) The Company hereby agrees to employ the Executive, and the
Executive hereby agrees to serve the Company all upon the terms and conditions
set forth herein.
(b) Unless and until terminated pursuant to Section (5)(a), Section
(5)(b)(i) or Section (5)(c)(i) hereof, the employment of the Executive by the
Company shall be for a term expiring on the date specified in a Notice of
Termination pursuant to Section (5)(d) hereof.
(2) POSITION AND DUTIES
The Executive shall be employed by the Company as President, effective
February 23, 1998, and as President and Chief Executive Officer, effective May
20, 1998, and thereafter
<PAGE>
in the same or in such other equivalent executive position as the Company's
Board of Directors may determine, without diminishment in his officership
status, privileges or working conditions. The Executive shall accept such
employment and shall perform and discharge, faithfully, diligently and to the
best of his abilities, the duties and obligations of his office and such other
duties as may from time to time be assigned to him by the Board of Directors of
the Company, and shall devote substantially all his working time and efforts to
the business and affairs of the Company; provided, however, that, to an extent
consistent with the needs of the Company, the Executive shall be entitled to
expend a reasonable amount of time on civic and philanthropic activities and the
management of his own and his family's business investments and activities.
Although a Change in Control of the Company shall not affect the obligations of
the Company and the Executive as set forth in the two preceding sentences, at
and after the date of any Change in Control the Company's employment of the
Executive shall also be without diminishment in his management responsibilities,
duties or powers.
(3) PLACE OF PERFORMANCE
In his employment by the Company, the Executive shall be based at the
executive offices of the Company situated within the Company's statutory service
area.
(4) COMPENSATION
(a) Base Salary. During the term of his employment hereunder, the
Executive shall receive a base salary (Base Salary) at an annual rate of Four
Hundred Thousand Dollars ($400,000). The Executive's Base Salary rate shall be
reviewed by the Board of Directors of the Company contemporaneously with each
review of the salary rates of the Company's other officers by said Board of
Directors, and may be revised upwards as a result of any such review. The
Executive's Base Salary may be revised downwards by said Board of Directors
contemporaneously with any general reduction of the salary rates of the
Company's other officers.
(b) Phantom Stock Options. The Executive will be awarded 80,000 phantom
stock options on shares of the Company's Common Stock, under which the option
price is the average of the high and low per share sale prices of said Common
Stock on the New York Stock Exchange on February 20, 1998, vesting at the rate
of 16,000 options on each of the first five anniversaries
- 2 -
<PAGE>
of February 23, 1998 occurring during the term of this Agreement, and
exercisable by the Executive and/or his personal representative only during a
period ending on the earlier of (A) the first anniversary of the Date of
Termination of this Agreement, or (B) February 23, 2008.
(c) Long-Term Incentive Program. The Executive will be designated as a
participant in the Company's 1996 Long-Term Incentive Program for the three-year
Performance Period commencing on January 1, 1998 and awarded 5,000 Contingent
Performance Shares for said Performance Period; and the Executive will be
designated as a participant in said Program for each succeeding three-year
Performance Period that commences during the term of this Agreement.
(d) Incentive Compensation. During the term of his employment
hereunder, the Executive shall be entitled to participate in each other
incentive compensation program established for officers of the Company,
including, in the case of the Company's 1998 Executive Incentive Compensation
Program, incentive award amounts for achieving pre-established performance
levels ranging from 35% of the Executive's Base Salary at the target performance
level to 52.5% of the Executive's Base Salary at the maximum performance level.
(e) Business Expenses. During the term of his employment hereunder, the
Executive shall be entitled to receive prompt reimbursement for all reasonable
expenses incurred by him (in accordance with the policies and procedures
established by the Board of Directors of the Company from time to time for the
Company's senior executive officers) in performing services hereunder, provided
that the Executive properly accounts therefor.
(f) Fringe Benefits. During the term of his employment hereunder, the
Executive shall be entitled to participate in and receive full benefits under
all of the Company's employee benefit plans, programs and arrangements for its
officers, including, without limitation, its Pension Plan. Nothing paid to the
Executive under any such plan, program or arrangement presently in effect or
made available by the Company in the future shall be deemed to be in lieu of
compensation to the Executive under any other Section of this Agreement.
(g) Vacations. During the term of his employment hereunder, the
Executive shall be entitled to the number of paid vacation days in each calendar
year determined by the Board of
- 3 -
<PAGE>
Directors of the Company from time to time for the Company's senior executive
officers, and shall also be entitled to all paid holidays given by the Company
to its employees.
(h) Supplemental Retirement. Upon termination of the Executive's
employment, a supplemental retirement benefit shall be payable to him or his
beneficiary in accordance with the provisions of this Section (4)(h). The annual
supplemental retirement benefit, expressed in the form of a single life annuity
beginning at the Executive's Normal Retirement Date (as defined in the Company's
Pension Plan), shall be the excess, if any, of (A) less (B), where (A) is 2.0%
(.02) of the Executive's highest three-year average Total Compensation times the
number of years at termination (not to exceed thirty) of the Executive's service
deemed as an employee of the Company, and (B) is the benefit payable under the
Company's Pension Plan. For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program. For purposes of this Agreement, the Executive's service
deemed as an employee of the Company will be calculated by adding to the period
of his actual service as an employee of the Company, on each of the first five
anniversaries of February 23, 1998 occurring during the term of this Agreement,
two additional years of service. Payment of the supplemental retirement benefit
shall begin at the same time as the Executive's Pension Plan benefit payments
and shall be subject to the same reductions for early commencement, except that
the reductions shall be based on the Executive's service deemed as an employee
of the Company. The supplemental retirement benefit may be paid in any form
available under the Pension Plan, as elected by the Executive prior to benefit
payment commencement. The conversion factors between forms of benefits used for
purposes of the Pension Plan shall be used for purposes of the supplemental
retirement benefit. The form of payment of the supplemental retirement benefit
may be the same or different from the form of payment of the Executive's
benefits under the Pension Plan. If the form of payment provides for a death
benefit, such benefit shall be payable to the Executive's estate, unless another
beneficiary has been designated by the Executive. If the Executive dies prior to
the commencement of benefit payments, the death benefit provisions of the
Pension Plan shall apply, mutatis mutandis, to the supplemental retirement
benefit payable pursuant to this Section (4)(h).
- 4 -
<PAGE>
(5) TERMINATION
(a) The Executive's employment hereunder shall terminate upon his
death.
(b) Termination by the Company.
(i) The Company may terminate the Executive's employment
hereunder for Cause. Prior to the date of a Change in Control, the Company shall
be deemed to have Cause to terminate the Executive's employment hereunder only
upon the Executive's (A) continued failure to perform and discharge the duties
or obligations of his office, or such other duties as may from time to time be
assigned to him by the Chief Executive Officer or by the Board of Directors,
faithfully, diligently, to the best of his abilities, and in accordance with
standards accepted in the electric utility industry, after written notice by the
Board of Directors of the Company specifying the alleged failure in reasonably
detailed terms and including in said notice the opinion of a majority of the
entire membership of said Board of Directors that there has been such failure,
or (B) willful misconduct that is materially and demonstrably injurious to the
Company, or (C) conviction of a felony involving the personal dishonesty or
moral turpitude of the Executive (unless such conviction is reversed in any
final appeal therefrom), or (D) total and permanent physical or mental
disability, or (E) absence from work on a full-time basis, due to physical or
mental illness, for an uninterrupted 365-day period. On and after the date of a
Change in Control, the Company shall be deemed to have Cause to terminate the
Executive's employment hereunder only upon the Executive's (F) conviction of a
felony involving the personal dishonesty or moral turpitude of the Executive
(unless such conviction is reversed in any final appeal therefrom), or (G) total
and permanent physical or mental disability, or (H) absence from work on a
full-time basis, due to physical or mental illness, for an uninterrupted 365-day
period. Notwithstanding the foregoing, the Executive shall not be deemed to have
been terminated for Cause unless and until there shall have been delivered to
the Executive (I) a copy of a resolution, duly adopted by the affirmative vote
of not less than a majority of the entire membership of the Board of Directors
of the Company, at a meeting of said Board of Directors called and held for the
purpose (after reasonable notice to the Executive and an opportunity for him,
together with his counsel, to be heard before said Board of Directors), finding
that, in the good faith opinion of such majority of said
- 5 -
<PAGE>
Board of Directors, the Executive was guilty of conduct described in an
applicable clause of this Section (5)(b)(i), and specifying the particulars
thereof, or that the events described in an applicable clause of this Section
(5)(b)(i) have occurred, and (II) an affidavit of the Secretary or an Assistant
Secretary of the Company stating that such resolution was in fact adopted by the
affirmative vote of not less than a majority of the entire membership of the
Board of Directors of the Company; and (III) delivery of a Notice of Termination
pursuant to Section (5)(d) hereof.
(ii) Without Cause. The Company may terminate the Executive's
employment without Cause, effective upon at least three (3) years' prior Notice
of Termination delivered to the Executive pursuant to Section (5)(d) hereof; and
during such three-year period all of the terms and provisions of this Agreement,
other than this Section (5)(b)(ii), shall continue in full force and effect.
(c) Termination by the Executive.
(i) Upon Breach by the Company. The Executive may terminate his
employment hereunder, upon thirty (30) days' prior Notice of Termination
delivered to the Company pursuant to Section (5)(d) hereof, for failure of the
Company to observe and perform one or more of its obligations under Sections
(1), (2), (3) and/or (4) hereof (a Breach by the Company) at a time when the
Executive is not in default of any of his obligations under Sections (1) and/or
(2) hereof.
(ii) Absent Breach by the Company. The Executive may terminate
his employment hereunder in the absence of a Breach by the Company, effective
upon at least six (6) months' prior Notice of Termination delivered to the
Company pursuant to Section (5)(d) hereof; and during such six-month period all
of the terms and provisions of this Agreement, other than this Section
(5)(c)(ii), shall continue in full force and effect.
(d) Notice of Termination. Any termination of employment, by the
Company or by the Executive, shall be communicated by delivery of a written
Notice of Termination to the other party.
(e) Date of Termination. For purposes of this Agreement, the Date of
Termination is defined as the earlier of (i) if the Executive's employment is
terminated pursuant to Section (5)(b)(ii) hereof, the date specified in the
Notice of
- 6 -
<PAGE>
Termination, or (ii) if the Executive's employment is terminated (A) by his
death, the date of his death, (B) pursuant to Section (5)(b)(i) or Section
(5)(c) hereof, the date specified in the Notice of Termination, or (C) in any
other event, the date on which a Notice of Termination is delivered.
(6) CONSEQUENCES OF TERMINATION
(a) If the Executive's employment terminates pursuant to Section
(5)(a) hereof, the Company shall pay to the personal representative and/or
spouse of the Executive his Total Compensation earned prior to the Date of
Termination, any amounts payable pursuant to Sections (4)(e), (4)(f), (4)(g) and
(4)(h) hereof and any benefits or amounts payable on account of the Executive's
exercise of his phantom stock options and/or under the Company's 1996 Long-Term
Incentive Program and/or any deferred compensation plan in which the Executive
had been a participant, and the Company shall have no further obligation under
this Agreement.
(b) If the Executive's employment terminates pursuant to Section
(5)(b)(ii) or Section (5)(c)(ii) hereof, the Company shall pay to the Executive
and/or his personal representative and/or spouse his Total Compensation earned
prior to the Date of Termination, any amounts payable pursuant to Sections
(4)(e), (4)(f), (4)(g) and (4)(h) hereof and any benefits or amounts payable on
account of the Executive's exercise of his phantom stock options and under the
Company's 1996 Long-Term Incentive Program and any deferred compensation plan in
which the Executive had been a participant, and the Company shall have no
further obligation to the Executive and/or his personal representative and/or
spouse under this Agreement or on account of, or arising out of, the termination
of the Executive's employment. The Executive may elect to receive an immediate
lump sum payment, in lieu of any amounts payable pursuant to Section (4)(h)
hereof on account of the Executive's termination of employment pursuant to
Section (5)(b)(ii) or Section (5)(c)(ii) hereof, in an amount equal to the
actuarial present value of a supplemental retirement benefit, expressed in the
form of a single life annuity beginning at Executive's termination of employment
equal to the excess if any of (A) less (B) where (A) is 2.0% (.02) of the
Executive's highest three-year average Total Compensation times the number of
years at termination (not to exceed thirty) of the Executive's service deemed as
an employee of the Company, and
- 7 -
<PAGE>
(B) is the benefit payable under the Company's Pension Plan at the Executive's
termination of employment. For purposes of this Agreement, Total Compensation is
defined as the sum of the Executive's Base Salary and any amount paid or payable
to the Executive pursuant to the Company's annual Executive Incentive
Compensation Program. For purposes of this Agreement, the Executive's service
deemed as an employee of the Company will be calculated by adding to the period
of his actual service as an employee of the Company, on each of the first five
anniversaries of February 23, 1998 occurring during the term of this Agreement,
two additional years of service. The actuarial present value of such
supplemental retirement benefit shall be calculated on the basis of the annual
yield on thirty-year United States Treasury bonds on the final business day of
the month preceding the termination of his employment and the 1983 Group Annuity
table.
(c) If the Executive's employment is terminated pursuant to Section
(5)(b)(i) hereof, or if the Executive terminates his employment in the absence
of a Breach by the Company and not in accordance with Section (5)(c)(ii) hereof,
the Company shall pay to the Executive his full Base Salary earned prior to the
Date of Termination, any amounts payable pursuant to Sections (4)(e), (4)(f),
(4)(g) and 4(h) hereof and any benefits or amounts payable under any deferred
compensation plan in which the Executive had been a participant, and, provided
that the Company is not in default of any of its obligations hereunder, the
Company shall have no further obligation to the Executive under this Agreement
or on account of, or arising out of, the termination of the Executive's
employment.
(d) If the Executive's employment is terminated pursuant to Section
(5)(c)(i) hereof, or if the Company terminates the Executive's employment
without Cause and not in accordance with Section (5)(b)(ii) hereof:
(i) The Company shall pay to the Executive his Total Compensation
earned prior to the Date of Termination, any amounts payable pursuant to
Sections (4)(e), (4)(f), (4)(g), and 4(h) hereof and any benefits or amounts
payable on account of the Executive's exercise of his phantom stock options and
under the Company 1996 Long-Term Incentive Program and any deferred compensation
plan in which the Executive had been a participant; and if the Notice of
Termination is delivered on or after the
- 8 -
<PAGE>
date of, and in connection with, a Change in Control, the Company shall afford
the Executive the severance benefits set forth on Schedule C attached hereto.
(ii) In lieu of any amounts payable pursuant to Section (4)(h)
hereof on account of the Executive's termination of employment, the Executive
may elect to receive an immediate lump sum amount equal to the actuarial present
value of a supplemental retirement benefit, expressed in the form of a single
life annuity beginning at Executive's termination of employment, equal to the
excess if any of (A) less (B), where (A) is 2.0% (.02) of the Executive's
highest three-year average Total Compensation times the number of years at
termination (not to exceed thirty) of the Executive's service deemed as an
employee of the Company, and (B) is the benefit payable under the Company's
Pension Plan at the Executive's termination of employment. For purposes of this
Agreement, Total Compensation is defined as the sum of the Executive's Base
Salary and any amount paid or payable to the Executive pursuant to the Company's
annual Executive Incentive Compensation Program. For purposes of this Agreement,
the Executive's service deemed as an employee of the Company will be calculated
by adding to the period of his actual service as an employee of the Company, on
each of the first five anniversaries of February 23, 1998 occurring during the
term of this Agreement, two additional years of service. The actuarial present
value of such supplemental retirement benefit shall be calculated on the basis
of the annual yield on thirty-year United States Treasury bonds on the final
business day of the month preceding the termination of his employment and the
1983 Group Annuity table.
(iii) The Company shall maintain in full force and effect, for
the continued benefit of the Executive for the period ending on the first
anniversary of the Date of Termination, all employee benefit plans and programs
in which the Executive was entitled to participate immediately prior to the Date
of Termination, provided that the Executive's continued participation is
possible under the general terms and provisions of such plans and programs. If
the Executive's participation in any such plan or program is barred as a result
of such termination, the Company shall arrange to provide the Executive with
benefits substantially similar on an after-tax basis to those which the
Executive was entitled to receive under such plan or program.
(iv) The Company shall pay to the Executive and/or his personal
representative his full Base Salary, during
- 9 -
<PAGE>
the period commencing on the date following the Date of Termination and ending
on the first anniversary of the Date of Termination, at the rate in effect at
the time the Notice of Termination is delivered; provided, however, that if the
Notice of Termination is delivered after February 23, 1999 and on or before
February 23, 2000, the aforesaid payment period shall end on the second
anniversary of the Date of Termination; and provided, further, that if the
Notice of Termination is delivered after February 23, 2000, the aforesaid
payment period shall end on the third anniversary of the Date of Termination;
and provided, further, that if the Notice of Termination is delivered after the
date of, and in connection with, a Change in Control the Company shall pay to
the Executive, in lieu of the payments prescribed by the foregoing clauses, an
immediate lump sum amount equal to the aggregate sum of all of the payments
prescribed by the next preceding clause.
(v) The Executive shall not be required to mitigate the amount of
any payment provided for in this Section (6)(d) by seeking employment or
otherwise. The benefits payable under this Section (6)(d) shall not be reduced
by reason of the Executive's securing other employment or for any other reason,
unless the Notice of Termination is delivered on or after, and in connection
with, a Change in Control, in which event the provisions of the following three
sentences shall apply. If, prior to the third anniversary of the Date of
Termination, the Executive obtains employment as the Chairman and Chief
Executive Officer (or an equivalent executive position) of another business
organization, the Executive shall refund to the Company a portion of the lump
sum payment provided for in Section (6)(d)(iv) equal to the amounts earned by
the Executive from his subsequent employer prior to said anniversary date, but
in no event more than the amount of said lump sum payment prorated over the
number of months in the period commencing on the date following his Date of
Termination and ending on the third anniversary of the Date of Termination,
multiplied by the number of months remaining between the Executive's
date-of-hire in his new employment and the third anniversary of his Date of
Termination. The Executive shall refund to the Company any amount required by
the preceding sentence within one hundred and eighty (180) days after the
date-of-hire in his new employment. The employee benefit plans and programs to
be provided by the Company pursuant to Section (6)(d)(iii) shall be reduced as
and to the extent that such benefits are provided to the Executive by a
subsequent employer during the period covered by said Section (6)(d)(iii).
- 10 -
<PAGE>
(vi) The payment to, and acceptance by, the Executive of any sum
of money or benefit prescribed in this Section (6)(d) shall effect and evidence
a release by the Executive of any and all claims against the Company on account
of, or arising out of, the termination of the Executive's employment, except as
prescribed in this Section (6)(d).
(7) CHANGE IN CONTROL
For purposes of this Agreement, Change in Control shall mean any of the
following events:
(a) any merger or consolidation of the Company with any corporate
shareholder or group of corporate shareholders holding twenty-five percent (.25)
or more of the Common Stock of the Company or with any other corporation or
group of corporations which is, or after such merger or consolidation would be,
or be affiliated with, a shareholder owning at least twenty-five percent (.25)
of the Common Stock of the Company; or
(b) any sale, lease, exchange, mortgage, pledge, transfer or other
disposition to or with any shareholder or group of shareholders holding
twenty-five percent (.25) or more of the Common Stock of the Company, or any
affiliate of such shareholder or group of shareholders, of any assets of the
Company having an aggregate fair market value of $50 million or more; or
(c) the issuance or sale by the Company of any securities of the
Company to any shareholder or group of shareholders holding twenty-five percent
(.25) or more of the Common Stock of the Company, or to any affiliate of such
shareholder or group of shareholders, in exchange for cash, securities or other
consideration having an aggregate fair market value of $50 million or more; or
(d) the implementation of any plan or proposal for the liquidation or
dissolution of the Company proposed by or on behalf of any shareholder or group
of shareholders owning at least twenty-five percent (.25) of the Common Stock of
the Company, or any affiliate of such shareholder or group of shareholders; or
(e) any reclassification of securities (including a reverse stock
split), or recapitalization of the Company or any other transaction which has
the effect, directly or indirectly, of increasing the proportionate share of
outstanding shares of
- 11 -
<PAGE>
any class of equity securities, or securities convertible into any equity
securities, of the Company, which is directly or indirectly owned by a
shareholder or group of shareholders owning at least twenty-five percent (.25)
of the Common Stock of the Company, or any affiliate of such shareholder or
group of shareholders.
The Board of Directors of the Company may, from time to time, by the
affirmative vote of not less than a majority of the entire membership of said
Board of Directors, at a meeting of said Board of Directors called and held for
the purpose, modify the phrase "twenty-five percent (.25)" in one or more of the
foregoing Sections (7)(a), (7)(b), (7)(c), (7)(d) and/or (7)(e) to a lesser
percentage, but not less than twenty percent (.20).
(8) ADDITIONAL CONSEQUENCES OF A CHANGE IN CONTROL
(a) In the event that a Change in Control has been approved by all
necessary shareholder, creditor and regulatory actions: (i) all of the
Executive's unvested phantom stock options will become vested and exercisable on
the day prior to the date of the Change in Control; provided, however, that if
the date of the Change in Control is on or prior to February 22, 1999, only
20,000 of such unvested phantom stock options, plus such number of the remaining
60,000 unvested phantom stock options as the Company's Board of directors may
determine in its sole discretion, will become so vested and exercisable on the
day prior to the date of the Change in Control; and (ii) the earning of
Performance Shares by the Executive under the Company's 1996 Long-Term Incentive
Program will be accelerated to the day prior to the date of the Change in
Control, and the Executive will be deemed to have earned all of the Contingent
Performance Shares outstanding with respect to him, payable to him on said day
prior to the date of the Change in Control, at his option, either (A) in
authorized but unissued shares of the Company's Common Stock, or (B) in cash,
based upon the market value of the Company's Common Stock at the end of the
business day next preceding said day prior to the date of the Change in Control.
(b) In the event that a Change in Control has been approved by all
necessary shareholder, creditor and regulatory actions, the Company will, not
later than the day prior to the date of the Change in Control, pay to the
Trustee of The United Illuminating Company Supplemental Retirement Benefit Trust
established pursuant to the Agreement, made as of the 1st day of June, 1995
between the Company and State Street Bank and Trust
- 12 -
<PAGE>
Company, as Trustee, cash in an amount equal to: (A) In the event that the
Executive's employment has been terminated or will be terminated prior to the
date of the Change in Control, a sum, calculated by the Company's independent
certified public accountants, reasonably sufficient to pay and discharge the
Company's future obligations, if any, to the Executive and/or his personal
representative and/or spouse, under Section (6)(a), Section (6)(b) or Section
(6)(d) hereof; or (B) in the event that the Executive's employment has not been
terminated and will not be terminated prior to the date of the Change in
Control, a sum, calculated by the Company's independent certified public
accountants, reasonably sufficient to pay and discharge the Company's
obligations to the Executive under Section (6)(d) hereof assuming, for purposes
of such calculation, that the Executive's employment is terminated under said
Section (6)(d) by a Notice of Termination delivered on the date of the Change in
Control and specifying an immediate Date of Termination.
(c) On and after the date of the Change in Control, the Executive's
Base Salary may not be reduced by the Board of Directors to an annual rate less
than the rate fixed by the Board of Directors of the Company as a result of its
most recent review of salary rates, pursuant to Section (4)(a) hereof, prior to
the date of the Change in Control.
(9) SUCCESSORS; BINDING AGREEMENT
(a) The Company shall pay to the Executive and/or his personal
representative and/or spouse all legal fees and expenses and court costs, if
any, incurred by the Executive and/or such representative and/or spouse in
successful litigation to enforce his rights under this Agreement.
(b) The Company will require any successor (whether direct or
indirect, by purchase, merger, consolidation or otherwise) to all or
substantially all of the business or assets of the Company, by agreement in form
and substance reasonably satisfactory to the Executive, to expressly assume and
agree to perform this Agreement in the same manner and to the same extent that
the Company would be required to perform it if no such succession had taken
place. Failure of the Company to obtain such agreement by the effectiveness of
any such succession shall be a breach of this Agreement and shall entitle the
Executive to compensation from the Company in the same amount and upon the same
terms as he would be entitled to hereunder if he terminated his employment upon
Breach by the Company, except that, for
- 13 -
<PAGE>
purposes of implementing the foregoing, the date on which any such succession
becomes effective shall be deemed the Date of Termination. As used in this
Agreement, the term "the Company" shall include The United Illuminating Company,
any parent and any successor to the business or assets of either as aforesaid
which executes and delivers the agreement provided for in this Section (9) or
which otherwise becomes bound by all the terms and provisions of this Agreement
by operation of law.
(c) This Agreement and all rights of the Executive hereunder shall
inure to the benefit of and be enforceable by the Executive's personal or legal
representatives, executors, administrators, successors, heirs, distributees,
devisees and legatees. If the Executive should die while any amounts would still
be payable to him hereunder if he had continued to live, all such amounts,
unless otherwise provided herein, shall be paid in accordance with the terms of
this Agreement to the Executive's devisee, legatee or other designee or, if
there be no such designee, to the Executive's estate.
(10) NOTICE
For the purpose of this Agreement, notices and all other communications to
either party hereunder provided for in the Agreement shall be in writing and
shall be deemed to have been duly given when delivered or mailed by United
States certified or registered mail, return receipt requested, postage prepaid,
addressed, in the case of the Company, to The United Illuminating Company, 157
Church Street, New Haven, Connecticut, Attention: Secretary, or, in the case of
the Executive, to him at 157 Church Street, New Haven, Connecticut, or to such
other address as either party shall designate by giving written notice of such
change to the other party.
(11) MISCELLANEOUS
(a) No provision of this Agreement may be modified, waived or
discharged unless such waiver, modification or discharge is approved by the
Board of Directors of the Company and agreed to in a writing signed by the
Executive and such officer as may be specifically authorized by the Board of
Directors of the Company. No waiver by either party hereto at any time of any
breach by the other party hereto of, or compliance with, any condition or
provision of this Agreement to be performed by such other party shall be deemed
a waiver of similar or dissimilar provisions or conditions at the same or at any
prior or subsequent time. No agreements or representations,
- 14 -
<PAGE>
oral or otherwise, express or implied, with respect to the subject matter hereof
have been made by either party which are not set forth expressly in this
Agreement. The validity, interpretation, construction and performance of this
Agreement shall be governed by the laws of the State of Connecticut.
(b) Exhibits A-1 and A-2 attached hereto, showing calculations of
supplemental retirement benefits under Section (4)(f), and Exhibit B attached
hereto, showing a calculation of a lump sum payment under Section (6)(d)(ii),
are incorporated herein by reference and set forth, by example, the parties'
intended interpretation and application of such Sections.
(12) VALIDITY
The validity or unenforceability of any provision or provisions of this
Agreement shall not affect the validity or enforceability of any other provision
of this Agreement, which shall remain in full force and effect.
(13) SURVIVAL
The provisions of this Agreement shall not survive the termination of this
Agreement or of employment hereunder, except that the provisions of Sections
(4), (6), (8), (9) and (10) hereof shall survive such termination and shall be
binding upon the Company's successors and assigns.
(14) COUNTERPARTS
This Agreement may be executed in one or more counterparts, each of which
shall be deemed to be an original but all of which together will constitute one
and the same instrument.
- 15 -
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Agreement on the
date and year first above written.
Attest: THE UNITED ILLUMINATING COMPANY
/s/ Kurt Mohlman By: /s/ Richard J. Grossi
- --------------------- ----------------------------------------
Secretary Chairman of the Board of
Directors and Chief Executive
Officer
/s/ Nathaniel D. Woodson
----------------------------------------
Nathaniel D. Woodson
- 16 -
EXHIBIT 10.29
THE UNITED ILLUMINATING COMPANY
PHANTOM STOCK OPTION AGREEMENT
THIS AGREEMENT, made as of February 23, 1998, by and between THE UNITED
ILLUMINATING COMPANY (the Company), a Connecticut corporation, and NATHANIEL D.
WOODSON (the Executive), an individual,
W I T N E S S E T H T H A T,
Whereas, the Company and the Executive have entered into an Employment
Agreement as of the date hereof (the Employment Agreement), whereby the Company
has employed the Executive, and the Executive has agreed to serve the Company,
as its President; and
Whereas, in Section (4)(b) of the Employment Agreement, the Company has
agreed to award the Executive eighty thousand (80,000) phantom stock options on
shares of the Company's Common Stock, under which the option price is $45.1563
(the Exercise Price), which was the average of the high and low per share sale
prices of said Common Stock on the New York Stock Exchange on February 20,
1998), vesting at the rate of sixteen thousand (16,000) options on each of the
first five anniversaries of February 23, 1998 occurring during the term of the
Employment Agreement, and exercisable by the Executive and/or his personal
representative only during a period ending on the earlier of (A) 2400 hours on
the first anniversary of the Date of Termination of the Employment Agreement (as
defined in Section (5)(e) of the Employment Agreement), or (B) 2400 hours on
February 23, 2008;
Whereas, the Company and the Executive desire to enter into this
Agreement evidencing the terms and provisions governing the aforesaid phantom
stock options,
NOW THEREFORE, the parties hereby agree as follows:
1. Options. This Agreement evidences the grant to the Executive of eighty
-------
thousand (80,000) Phantom Common Stock Options (the Options, and each an
Option).
2. Exercisability and Duration.
---------------------------
a. Generally. None of the Options shall be exercisable until February 23,
---------
1999. On that date, sixteen
<PAGE>
thousand (16,000) of the Options shall first become exercisable. Thereafter, an
additional sixteen thousand (16,000) Options shall first become exercisable on
each of February 23, 2000, February 23, 2001, February 23, 2002 and February 23,
2003. Once exercisable, each Option shall remain exercisable, unless sooner
terminated pursuant to the terms and provisions of this Agreement, until 2400
hours on February 23, 2008.
b. Upon A Change of Control. In the event of a Change in Control (as
-------------------------
defined in Section (7) of the Employment Agreement) of the Company, the Options
shall become exercisable pursuant to and in accordance with Section (8)(a) of
the Employment Agreement.
c. Upon Certain Other Events. Upon the Date of Termination of the
----------------------------
Employment Agreement (as defined in Section (5)(e) of the Employment Agreement),
all of the Options that are not then exercisable shall automatically expire, and
all of the Options that are then exercisable shall remain exercisable by the
Executive and/or his personal representative until the earlier of (A) 2400 hours
on the first anniversary of said Date of Termination or (B) 2400 hours on
February 23, 2008.
3. Payment Upon Exercise. On each date that the Executive or his personal
-----------------------
representative exercises one or more Options, the Company shall become obligated
to pay the Executive or his personal representative, in cash, an amount equal to
the excess of the fair market value of the Company's Common Stock on that date
over the Exercise Price, multiplied by the number of Options exercised. "Fair
market value" shall be the average of a high and low sale prices of shares of
the Company's Common Stock on the New York Stock Exchange composite tape on the
exercise date or, if there is no sale on such date, then such average price on
the last previous day on which at least one sale shall have been reported. The
Company shall discharge each payment obligation to the Executive or his personal
representative on or before the second business day following the exercise date.
4. Documentation of Exercise. In order to exercise an Option, the Executive or
-------------------------
his personal representative shall deliver to the Secretary of the Company a
signed notice of exercise; and the Option shall be deemed exercised on the date
when such notice is received by the Secretary of the Company. During the life of
the Executive, the Options may be exercised only by the Executive or his
guardian or legal representative.
- 2 -
<PAGE>
5. Transferability. The Options may not be assigned or transferred by the
---------------
Executive, except by will or the laws of descent and distribution. Any other
purported transfer or assignment of an Option shall automatically terminate it.
6. Adjustments. In the event of a recapitalization, reclassification, stock
-----------
split, stock dividend, combination of shares, or any other similar change in the
Company's capital structure, an appropriate adjustment shall be made in the
number and/or kind of shares of the Company's stock covered by the Options
and/or in the Exercise Price of the Options. In the event of any merger,
consolidation or other reorganization in which the Company is not the surviving
or continuing corporation, all Options shall be assumed by the surviving or
continuing corporation.
7. Funding; Right to Assets. Except as provided in Section (6) of the Employment
------------------------
Agreement, the Company's obligations under this Agreement shall be unfunded; and
the Company is not, under any circumstances except those referred to in said
Section (6), required to fund its obligations hereunder. The Company may, in its
sole discretion, set aside or invest funds to meet its obligations under this
Agreement, in whole or in part, in circumstances other than those referred to in
said Section (6); but if the Company determines to take such action, the method
and manner thereof and the continuance or discontinuance thereof shall be within
the sole discretion of the Company. This Agreement confers on the Executive no
right, title or interest whatsoever in or to any shares of the Company's stock
or any specific funds or assets of the Company. If any funds or assets are
acquired by the Company in connection with its obligations under this Agreement,
they shall be and remain subject to the claims of all of the creditors of the
Company.
8. Non-expansion of Rights. Nothing contained in this Agreement shall afford the
-----------------------
Executive any right to be employed by the Company.
9. Binding Effect. The provisions of this Agreement shall be binding upon and
---------------
inure to the benefit of the Company, its successors and assigns, and the
Executive and his guardians, legal representatives and personal representatives.
- 3 -
<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement
as of the date first above written.
THE UNITED ILLUMINATING COMPANY
By /s/ Richard J. Grossi
---------------------------------------
Its Chairman of the Board of
Directors and Chief Executive Officer
/s/ Nathaniel D. Woodson
---------------------------------------
Nathaniel D. Woodson
- 4 -
<TABLE>
EXHIBIT 12
PAGE 1 of 2
THE UNITED ILLUMINATING COMPANY
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(In Thousands)
<CAPTION>
TWELVE
MONTHS
ENDED
YEAR ENDED DECEMBER 31, MAR. 31,
------------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $40,481 $46,795 $50,393 $39,096 $45,791 $47,043
Federal income taxes 22,342 34,551 41,951 35,252 30,186 31,342
State income taxes 4,645 6,216 12,976 8,506 8,651 9,001
Fixed charges 97,928 88,093 83,994 80,097 78,016 75,187
----------- ----------- ----------- ----------- ----------- ------------
Earnings available for fixed charges $165,396 $175,655 $189,314 $162,951 $162,644 $162,573
=========== =========== =========== =========== =========== ============
FIXED CHARGES
Interest on long-term debt $80,030 $73,772 $63,431 $66,305 $63,063 $60,214
Other interest 12,260 10,301 16,723 9,534 10,881 10,931
Interest on nuclear fuel burned 928 - - - - -
One third of rental charges 4,710 4,020 3,840 4,258 4,072 4,042
----------- ----------- ----------- ----------- ----------- ------------
$97,928 $88,093 $83,994 $80,097 $78,016 $75,187
=========== =========== =========== =========== =========== ============
RATIO OF EARNINGS TO FIXED
CHARGES 1.69 1.99 2.25 2.03 2.08 2.16
=========== =========== =========== =========== =========== ============
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12
PAGE 2 of 2
THE UNITED ILLUMINATING COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS
(In Thousands)
<CAPTION>
TWELVE
MONTHS
ENDED
YEAR ENDED DECEMBER 31, MAR. 31,
---------------------------------------------------------------------
1993 1994 1995 1996 1997 1998
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $40,481 $46,795 $50,393 $39,096 $45,791 $47,043
Federal income taxes 22,342 34,551 41,951 35,252 30,186 31,342
State income taxes 4,645 6,216 12,976 8,506 8,651 9,001
Fixed charges 97,928 88,093 83,994 80,097 78,016 75,187
----------- ----------- ---------- ----------- ----------- -----------
Earnings available for combined fixed
charges and preferred stock
dividend requirements $165,396 $175,655 $189,314 $162,951 $162,644 $162,573
=========== =========== ========== =========== =========== ===========
FIXED CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS
Interest on long-term debt $ 80,030 $ 73,772 $ 63,431 $ 66,305 $ 63,063 $60,214
Other interest 12,260 10,301 16,723 9,534 10,881 10,931
Interest on nuclear fuel burned 928 - - - - -
One third of rental charges 4,710 4,020 3,840 4,258 4,072 4,042
Preferred stock dividend requirements (1) 7,197 6,223 2,778 699 379 381
----------- ----------- ---------- ----------- ----------- -----------
$105,125 $94,316 $86,772 $80,796 $78,395 $75,568
=========== =========== ========== =========== =========== ===========
RATIO OF EARNINGS TO FIXED
CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS 1.57 1.86 2.18 2.02 2.07 2.15
=========== =========== ========== =========== =========== ===========
</TABLE>
(1) Preferred Stock Dividends increased to reflect the pre-tax earnings required
to cover such dividend requirements.
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