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, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
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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, 1999, was 14,334,922.
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<PAGE>
INDEX
PART I. FINANCIAL INFORMATION
PAGE
NUMBER
------
Item 1. Financial Statements. 3
Consolidated Statement of Income for the three months
ended March 31, 1999 and 1998. 3
Consolidated Balance Sheet as of March 31, 1999
and December 31, 1998. 4
Consolidated Statement of Cash Flows for the three months
ended March 31, 1999 and 1998. 6
Notes to Consolidated Financial Statements. 7
- Statement of Accounting Policies 7
- Capitalization 7
- Rate-Related Regulatory Proceedings 8
- Short-term Credit Arrangements 11
- Income Taxes 13
- Supplementary Information 14
- Fuel Financing Obligations and Other Lease Obligations 15
- Commitments and Contingencies 15
- Capital Expenditure Program 15
- Nuclear Insurance Contingencies 15
- Other Commitments and Contingencies 16
- Connecticut Yankee 16
- Hydro-Quebec 16
- Environmental Concerns 17
- Site Decontamination, Demolition and Remediation Costs 17
- Nuclear Fuel Disposal and Nuclear Plant Decommissioning 17
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 19
- Major Influences on Financial Condition 19
- Capital Expenditure Program 20
- Liquidity and Capital Resources 21
- Subsidiary Operations 22
- Results of Operations 22
- Looking Forward 24
PART II. OTHER INFORMATION
Item 1. Legal Proceedings. 29
Item 6. Exhibits and Reports on Form 8-K. 29
SIGNATURES 30
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<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,
1999 1998
---- ----
<S> <C> <C>
OPERATING REVENUES (NOTE G) $168,667 $162,474
------------- -------------
OPERATING EXPENSES
Operation
Fuel and energy 33,899 40,541
Capacity purchased 9,062 6,222
Other 38,754 33,309
Maintenance 9,446 11,033
Depreciation (Note G) 17,739 20,806
Amortization of cancelled nuclear project,
deferred return and regulatory tax asset 7,026 3,440
Income taxes (Note F) 15,525 11,487
Other taxes (Note G) 14,009 12,959
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Total 145,460 139,797
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OPERATING INCOME 23,207 22,677
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OTHER INCOME AND (DEDUCTIONS)
Allowance for equity funds used during construction 13 30
Other-net (Note G) (469) 445
Non-operating income taxes 891 83
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Total 435 558
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INCOME BEFORE INTEREST CHARGES 23,642 23,235
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INTEREST CHARGES
Interest on long-term debt 12,227 13,523
Interest on Seabrook obligation bonds owned by the company (1,711) (1,818)
Other interest (Note G) 1,856 844
Allowance for borrowed funds used during construction (448) (129)
------------- -------------
11,924 12,420
Amortization of debt expense and redemption premiums 614 650
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Net Interest Charges 12,538 13,070
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MINORITY INTEREST IN PREFERRED SECURITIES 1,203 1,203
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NET INCOME 9,901 8,962
Dividends on preferred stock 51 51
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INCOME APPLICABLE TO COMMON STOCK $9,850 $8,911
============= =============
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC 14,042 13,987
AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - DILUTED 14,044 13,997
EARNINGS PER SHARE OF COMMON STOCK - BASIC AND DILUTED $0.70 $0.64
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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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
ASSETS
(Thousands of Dollars)
<CAPTION>
March 31, December 31,
1999 1998*
---- ----
(Unaudited)
<S> <C> <C>
Utility Plant at Original Cost
In service $1,888,526 $1,886,930
Less, accumulated provision for depreciation 729,772 714,375
---------------- ----------------
1,158,754 1,172,555
Construction work in progress 29,622 33,695
Nuclear fuel 24,944 20,174
---------------- ----------------
Net Utility Plant 1,213,320 1,226,424
---------------- ----------------
Other Property and Investments 38,507 37,873
---------------- ----------------
Current Assets
Cash and temporary cash investments 19,042 101,445
Accounts receivable
Customers, less allowance for doubtful
accounts of $1,800 and $1,800 55,469 54,178
Other 29,685 37,472
Accrued utility revenues 21,450 21,079
Fuel, materials and supplies, at average cost 34,040 33,613
Prepayments 12,468 7,424
Other 1,503 154
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Total 173,657 255,365
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Deferred Charges
Unamortized debt issuance expenses 9,105 9,421
Other 2,477 1,664
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Total 11,582 11,085
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Regulatory Assets (future amounts due from customers
through the ratemaking process)
Income taxes due principally to book-tax differences 259,452 264,811
Connecticut Yankee 40,861 42,633
Deferred return - Seabrook Unit 1 9,439 12,586
Unamortized redemption costs 23,175 23,468
Unamortized cancelled nuclear projects 10,659 10,952
Uranium enrichment decommissioning cost 1,143 1,177
Other 4,613 4,962
---------------- ----------------
Total 349,342 360,589
---------------- ----------------
$1,786,408 $1,891,336
================ ================
</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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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED BALANCE SHEET
CAPITALIZATION AND LIABILITIES
(Thousands of Dollars)
<CAPTION>
March 31, December 31,
1999 1998*
---- ----
(Unaudited)
<S> <C> <C>
Capitalization (Note B)
Common stock equity
Common stock $292,006 $292,006
Paid-in capital 2,108 2,046
Capital stock expense (2,182) (2,182)
Unearned employee stock ownership plan equity (9,972) (10,210)
Retained earnings 163,587 163,847
------------------- ------------------
445,547 445,507
Preferred stock - 4,299
Minority interest in preferred securities 50,000 50,000
Long-term debt
Long-term debt 730,586 757,370
Investment in Seabrook obligation bonds (87,413) (92,860)
------------------- ------------------
Net long-term debt 643,173 664,510
------------------- ------------------
Total 1,138,720 1,164,316
------------------- ------------------
Noncurrent Liabilities
Connecticut Yankee contract obligation 30,759 32,711
Pensions accrued 27,412 31,097
Nuclear decommissioning obligation 24,213 23,045
Obligations under capital leases 16,415 16,506
Other 6,358 6,622
------------------- ------------------
Total 105,157 109,981
------------------- ------------------
Current Liabilities
Current portion of preferred stock 4,299 -
Current portion of long-term debt 6,806 66,202
Notes payable 82,172 86,892
Accounts payable 25,377 53,440
Dividends payable 10,160 10,155
Taxes accrued 23,440 9,015
Interest accrued 14,108 10,203
Obligations under capital leases 354 348
Other accrued liabilities 36,585 39,845
------------------- ------------------
Total 203,301 276,100
------------------- ------------------
Customers' Advances for Construction 1,866 1,867
------------------- ------------------
Regulatory Liabilities (future amounts owed to customers
through the ratemaking process)
Accumulated deferred investment tax credits 15,433 15,623
Other 3,051 2,065
------------------- ------------------
Total 18,484 17,688
------------------- ------------------
Deferred Income Taxes (future tax liabilities owed
to taxing authorities) 318,880 321,384
Commitments and Contingencies (Note L)
------------------- ------------------
$1,786,408 $1,891,336
=================== ==================
</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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<TABLE>
THE UNITED ILLUMINATING COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<CAPTION>
Three Months Ended
March 31,
1999 1998
---- ----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $9,901 $8,962
------------ -----------
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 22,466 21,851
Deferred income taxes (732) (2,251)
Deferred investment tax credits - net (190) (190)
Amortization of nuclear fuel 3,191 1,265
Allowance for funds used during construction (461) (159)
Amortization of deferred return 3,147 3,147
Changes in:
Accounts receivable - net 6,496 6,339
Fuel, material and supplies (427) (3,768)
Prepayments (5,044) (2,968)
Accounts payable (28,063) (26,051)
Interest accrued 3,905 2,528
Taxes accrued 14,425 11,919
Other assets and liabilities (9,818) (2,792)
------------ -----------
Total Adjustments 8,895 8,870
------------ -----------
NET CASH PROVIDED BY OPERATING ACTIVITIES 18,796 17,832
------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock 300 4,015
Long-term debt - 99,780
Notes payable (4,720) 7,369
Securities redeemed and retired:
Long-term debt (86,202) (133,976)
Expense of issue - (800)
Lease obligations (85) (82)
Dividends
Preferred stock (51) (51)
Common stock (10,104) (10,000)
------------ -----------
NET CASH USED IN FINANCING ACTIVITIES (100,862) (33,745)
------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Plant expenditures, including nuclear fuel (5,784) (8,356)
Investment in debt securities 5,447 8,528
------------ -----------
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES (337) 172
------------ -----------
CASH AND TEMPORARY CASH INVESTMENTS:
NET CHANGE FOR THE PERIOD (82,403) (15,741)
BALANCE AT BEGINNING OF PERIOD 101,445 32,002
------------ -----------
BALANCE AT END OF PERIOD $19,042 $16,261
============ ===========
CASH PAID DURING THE PERIOD FOR:
Interest (net of amount capitalized) $6,306 $10,626
============ ===========
Income taxes $3,700 $2,900
============ ===========
</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, 1998. 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 1999
and 1998 was 7.0% and 8.0%, respectively, on a before-tax basis.
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 $666,000 and $645,000 in the first three
months of 1999 and 1998, respectively, into the decommissioning trust funds for
Seabrook Unit 1 and Millstone Unit 3. At March 31, 1999, the Company's shares of
the trust fund balances, which included accumulated earnings on the funds, were
$17.4 million and $6.9 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.
(B) CAPITALIZATION
(A) COMMON STOCK
The Company had 14,334,922 shares of its common stock, no par value,
outstanding at March 31, 1999, of which 293,374 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, 1999. No options were exercised during the
first quarter of 1999.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, 1999, 293,374 shares, with a fair market value of
$12.3 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
$105.4 million were free from such limitations at March 31, 1999.
(C) PREFERRED STOCK
On April 8, 1999, the Company called for redemption all 10,370 shares of
its outstanding $100 par value 4.35% Preferred Stock, Series A, all 17,158
shares of its outstanding $100 par value 4.72% Preferred Stock, Series B, all
12,745 shares of its outstanding $100 par value 4.64% Preferred Stock, Series C
and all 2,712 shares of its outstanding $100 par value 5 5/8% Preferred Stock,
Series D. The Company paid a redemption premium of $53,355 in effecting these
redemptions, which were completed on May 14, 1999.
(E) LONG-TERM DEBT
On February 1, 1999, the Company converted $7.5 million principal amount
Connecticut Development Authority Bonds from a weekly reset mode to a five-year
multiannual mode. The interest rate on the Bonds for the five-year period
beginning February 1, 1999 is 4.35% and interest will be paid semi-annually
beginning on August 1, 1999. In addition, on February 1, 1999, the Company
converted $98.5 million principal amount Business Finance Authority of the State
of New Hampshire Bonds from a weekly reset mode to a multiannual mode. The
interest rate on $27.5 million principal amount of the Bonds is 4.35% for a
three-year period beginning February 1, 1999. The interest rate on $71 million
principal amount of the Bonds is 4.55% for a five-year period. Interest on the
Bonds will be paid semi-annually beginning on August 1, 1999.
On March 8, 1999, the Company prepaid and terminated $20 million of the
remaining $70 million outstanding debt under its $150 million Term Loan
Agreement dated August 29, 1995. On April 16, 1999, the Company prepaid and
terminated the entire remaining $50 million outstanding debt under said $150
million Term Loan Agreement, and the entire $75 million outstanding debt under
its Term Loan Agreement dated October 25, 1996.
(C) RATE-REGULATED REGULATORY PROCEEDINGS
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. The business of generating and supplying
electricity directly to consumers will be price-deregulated and opened to
competition beginning in the year 2000. At that time, these business activities
will be separated from the business of delivering electricity to consumers, also
known as the transmission and distribution business. The business of delivering
electricity will remain with the incumbent franchised utility companies
(including the Company), which will continue to be regulated by the DPUC as
Distribution Companies. 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
licensed suppliers, for delivery over the wires system of the franchised
Distribution Company. Commencing no later than mid-1999, Distribution Companies
will be required to separate on consumers' bills the
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
charge for electricity generation services from the charge for delivering the
electricity and all other charges. On July 29, 1998, the DPUC issued the first
of what are expected to be several orders relative to this "unbundling"
requirement, and has now reopened its proceeding to consider the amount of the
generation services charge to be included on consumers' bills.
A major component of the Restructuring Act is the collection, by
Distribution Companies, of a "competitive transition assessment," a "systems
benefits charge," an "energy conservation and load management program charge"
and a "renewable energy investment charge". The competitive transition
assessment represents costs that have been reasonably incurred by, or will be
incurred by, Distribution Companies to meet their public service obligations as
electric companies, and that will likely 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 and
above-market investments in power plants (so-called stranded costs). The systems
benefits charge represents public policy costs, such as generation
decommissioning and displaced worker protection costs. Beginning in 2000, a
Distribution Company must collect the competitive transition assessment, the
systems benefits charge, the energy conservation and load management program
charge and the renewable energy investment charge from all Distribution Company
customers, except customers taking service under special contracts pre-dating
the Restructuring Act. The Distribution Company will also be required to offer a
"standard offer" rate that is, subject to certain adjustments, at least 10%
below its fully bundled prices for electricity at rates in effect on December
31, 1996, as discussed below. The standard offer is required, subject to certain
adjustments, to be the total rate charged under the standard offer, including
generation and transmission and distribution services, the competitive
transition assessment, the systems benefits charge, the energy conservation and
load management program charge and the renewable energy investment charge.
The Restructuring Act requires that, in order for a Distribution Company to
recover any stranded costs associated with its power plants, its fossil-fueled
plants must be sold prior to 2000, with any net excess proceeds used to mitigate
its recoverable stranded costs, and the Company must attempt to divest its
ownership interest in its nuclear-fueled power plants prior to 2004. By October
1, 1998, each Distribution Company was required to file, for the DPUC's
approval, an "unbundling plan" to separate, on or before October 1, 1999, all of
its power plants that will not have been sold prior to the DPUC's approval of
the unbundling plan or will not be sold prior to 2000.
In May of 1998, the Company announced that it would commence selling,
through a two-stage bidding process, all of its non-nuclear generation assets,
in compliance with the Restructuring Act. On October 2, 1998, the Company agreed
to sell both of its operating fossil-fueled generating stations, Bridgeport
Harbor Station and New Haven Harbor Station, to Wisvest-Connecticut, LLC, a
single-purpose subsidiary of Wisvest Corporation. Wisvest Corporation is a
non-utility subsidiary of Wisconsin Energy Corporation, Milwaukee, Wisconsin. On
February 24, 1999, the Federal Energy Regulatory Commission issued an order
authorizing the sale, on March 5, 1999, the DPUC issued a decision approving the
sale; and the sale was completed on April 16, 1999.
The Company has received approximately $277.9 million in cash from this
sale of its operating fossil-fueled generating stations, which amount is subject
to certain post-closing adjustments. The Company realized a small book gain from
the sale proceeds net of taxes and plant investment. However, under the
Restructuring Act, this gain will be offset by a writedown of above-market
generation costs eligible for collection by the Company under the Restructuring
Act's competitive transition assessment, such as regulated plant costs and
tax-related regulatory assets or other costs related to the restructuring
transition, such that there will be no net income effect of the sale. The
Company used the net cash proceeds from the sale to reduce debt.
On October 1, 1998, in its "unbundling plan" filing with the DPUC under
the Restructuring Act, the Company stated that it plans to divest its nuclear
generation ownership interests (17.5% of Seabrook Station in New Hampshire and
3.685% of Millstone Station Unit No. 3 in Connecticut) by the end of 2003, in
accordance with the Restructuring Act. The divestiture method has not yet been
determined. In anticipation of ultimate divestiture, the
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Company proposed to satisfy, on a functional basis, the Restructuring Act's
requirement that nuclear generating assets be separated from its transmission
and distribution assets. This would be accomplished by transferring the nuclear
generating assets into a separate new division of the Company, using divisional
financial statements and accounting to segregate all revenues, expenses, assets
and liabilities associated with nuclear ownership interests. In a draft decision
dated April 23, 1999, the DPUC tentatively approved the Company's proposal in
this regard.
The Company's unbundling plan also proposes to separate its ongoing
regulated transmission and distribution operations and functions, that is, the
Distribution Company assets and operations, from all of its unregulated
operations and activities. This would be achieved by undergoing a corporate
restructuring into a holding company structure. In the holding company structure
proposed, the Company will become a wholly-owned subsidiary of a holding
company, and each share of the common stock of the Company will be converted
into a share of common stock of the holding company. In connection with the
formation of the holding company structure, all of the Company's interests in
all of its operating unregulated subsidiaries will be transferred to the holding
company and, to the extent new businesses are subsequently acquired or
commenced, they will also be financed and owned by the holding company. An
application for the DPUC's approval of this corporate restructuring was filed on
November 13, 1998. DPUC hearings on the corporate unbundling plan and corporate
restructuring commenced on February 18, 1999. In a draft decision dated April
23, 1999, the DPUC tentatively approved the proposed corporate restructuring. A
final decision is expected in late May. The proposed corporate restructuring is
also subject to approval by the Company's common stock shareowners and by the
Federal Energy Regulatory Commission and the Nuclear Regulatory Commission.
Under the Restructuring Act, all Connecticut electricity customers will be
able to choose their power supply providers after June 30, 2000. The Company
will be required to offer fully-bundled service to customers under a regulated
"standard offer" rate and will also become the power supply provider to each
customer who does not choose an alternate power supply provider, even though the
Company will no longer be in the business of retail power generation. In order
to mitigate the financial risk that these regulated service mandates will pose
to the Company in an unregulated power generation environment, its unbundling
plan proposes that a purchased power adjustment clause be added to its regulated
rates, effective July 1, 2000, as permitted by the Restructuring Act. This
clause, similar to and based on the purchased gas adjustment clauses used by
Connecticut's natural gas local distribution companies, would work in tandem
with the Company's procurement of power supplies to assure that "standard offer"
customers pay competitive market rates for power supply services and that the
Company collects its costs of providing such services. The Distribution Company
is also required under the Restructuring Act to provide back-up power supply
service to customers whose electric supplier fails to provide power supply
services for reasons other than the customers' failure to pay for such services.
The Restructuring Act provides for the Distribution Company to recover its
reasonable costs of providing this back-up service.
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 at least 10% below
the average fully-bundled prices in effect on December 31, 1996. The Company has
already delivered about 4.8% of this decrease, in price reductions through 1998.
The DPUC's 1996 financial and operational review order (see below) 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 allow for the
additional standard offer price reduction requirement of 10%, at a minimum,
while providing for the added costs imposed by the restructuring legislation.
The legislation does prescribe certain bases for adjusting the price of standard
offer service if the 10% minimum price reduction cannot be accomplished.
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<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
FIVE-YEAR RATE PLAN
- -------------------
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 Rate Plan). The DPUC did not change the existing
base rates charged to retail customers, but did provide for retail customer
price reductions of about 5% compared to 1996 and phased-in over 1997-2001; 3%
in 1997 compared to 1996, an additional 1% in 2000 and another 1% in 2001
compared to 1996. The price reductions are accomplished primarily through
reductions of conservation adjustment mechanism revenues, through a surcredit in
each of the five plan years, and through acceptance of the Company's proposal to
modify the operation of the fossil fuel clause mechanism. The Rate Plan also
increased amortization of the Company's conservation and load management program
investments during 1997-1998, and accelerated the amortization recovery of
unspecified assets during 1999-2001 if the Company's return on utility common
stock equity exceeds 10.5%, on an annual basis, after recording the
amortization. The specified accelerated amortizations for 1999-2001, on an
after-tax basis, are $12.1 million, $29.7 million and $32.8 million,
respectively. The Company's authorized return on utility common stock equity
under the Rate Plan is 11.5%, on an annual basis. Earnings above 11.5% are to be
"shared" by utilizing one-third for retail customer price reductions, one-third
for increased amortization of regulatory assets, and one-third retained as
earnings.
The Rate Plan had significant impacts on the Company's 1998 financial
results. Retail customer prices actually decreased by approximately 4.8% in 1998
compared to 1996. Also in 1998, all of the increased amortization of the
Company's conservation and load management program investments prescribed by the
Rate Plan were recorded. No "shared" earnings were recorded in 1998 because
one-time items reduced the Company's return on utility common stock equity to
less than 11.5%, although earnings from operations, excluding one-time items,
would have been above 11.5% and "sharing" would have occurred based on earnings
from operations alone. See "Results of Operations" for a more complete
discussion of these results.
The Rate Plan was reopened in 1998, in accordance with its terms, to
determine the assets to be subjected to accelerated recovery in 1999, 2000 and
2001. The DPUC decided on February 10, 1999 that $12.1 million of the Company's
regulatory tax assets will be subjected to accelerated recovery in 1999. The
DPUC has not yet determined the assets to be subjected to recovery after 1999.
The Rate Plan also includes a provision that it may be reopened and modified
upon the enactment of electric utility restructuring legislation in Connecticut
and, as a consequence of the 1998 Restructuring Act described above, the Rate
Plan may be reopened and modified. However, aside from implementing an
additional price reduction in 2000 to achieve the minimum aggregate 10% price
reduction compared to 1996 required by the Restructuring Act and the probable
reductions in the accelerated amortizations scheduled in the Rate Plan, the
Company is unable to predict, at this time, in what other respects the Rate Plan
may be modified on account of this legislation.
(E) SHORT-TERM CREDIT ARRANGEMENTS
The Company has a revolving credit agreement with a group of banks, which
currently extends to December 8, 1999. 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, 1999, the Company had no short-term borrowings outstanding under this
facility.
On April 16, 1999, the Company repaid and terminated an $80 million
revolving credit agreement prior to its June 7, 1999 due date.
- 11 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In addition, as of March 31, 1999, 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.
- 12 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(F) INCOME TAXES
Three Months Ended
March 31,
1999 1998
---- ----
(000's)
Income tax expense consists of:
Income tax provisions:
Current
Federal $12,337 $10,719
State 3,219 3,126
------------- -------------
Total current 15,556 13,845
------------- -------------
Deferred
Federal (154) (1,551)
State (578) (700)
------------- -------------
Total deferred (732) (2,251)
------------- -------------
Investment tax credits (190) (190)
------------- -------------
Total income tax expense $14,634 $11,404
============= =============
Income tax components charged as follows:
Operating expenses $15,525 $11,487
Other income and deductions - net (891) (83)
------------- -------------
Total income tax expense $14,634 $11,404
============= =============
The following table details the components
of the deferred income taxes:
Seabrook sale/leaseback transaction ($2,082) ($2,181)
Pension benefits 1,525 600
Accelerated depreciation 1,250 1,534
Tax depreciation on unrecoverable plant
investment 1,188 1,212
Unit overhaul and replacement power costs (898) (398)
Conservation and load management (873) (2,007)
Postretirement benefits (433) (102)
Other - net (409) (909)
------------- -------------
Deferred income taxes - net ($732) ($2,251)
============= =============
- 13 -
<PAGE>
<TABLE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(G) SUPPLEMENTARY INFORMATION
<CAPTION>
Three Months Ended
March 31,
1999 1998
---- ----
(000's)
<S> <C> <C>
Operating Revenues
- ------------------
Retail $152,391 $146,545
Wholesale - capacity 1,854 3,426
- energy 11,739 11,389
Other 2,683 1,114
------------- -------------
Total Operating Revenues $168,667 $162,474
============= =============
Sales by Class(MWH's)
- ---------------------
Retail
Residential 533,768 488,329
Commercial 553,798 564,789
Industrial 269,060 265,628
Other 12,199 12,173
------------- -------------
1,368,825 1,330,919
Wholesale 652,746 508,317
------------- -------------
Total Sales by Class 2,021,571 1,839,236
============= =============
Depreciation
- ------------
Plant in Service $14,655 $14,330
Amortization Conservation and
Load Management Costs 2,418 5,657
Nuclear Decommissioning 666 819
------------- -------------
$17,739 $20,806
============= =============
Other Taxes
- -----------
Charged to:
Operating:
State gross earnings $5,854 $5,621
Local real estate and personal property 6,326 5,482
Payroll taxes 1,829 1,856
------------- -------------
14,009 12,959
Nonoperating and other accounts 134 148
------------- -------------
Total Other Taxes $14,143 $13,107
============= =============
Other Income and (Deductions) - net
- -----------------------------------
Interest income $667 $320
Equity earnings from Connecticut Yankee 181 307
Earnings (Loss) from subsidiary companies (1,206) 195
Miscellaneous other income and (deductions) - net (111) (377)
------------- -------------
Total Other Income and (Deductions) - net ($469) $445
============= =============
Other Interest Charges
- ----------------------
Notes Payable $1,284 $518
Other 572 326
------------- -------------
Total Other Interest Charges $1,856 $844
============= =============
</TABLE>
- 14 -
<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 the financing of 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 2000, when it will terminate. At March 31, 1999, no fossil fuel purchases
were being financed under this agreement. On April 16, 1999, the Company sold
all of its operating non-nuclear generation facilities to an unaffiliated
entity. See Note (C) "Rate-Related Regulatory Proceedings". As a result, the
Company will not finance any fuel purchases under this agreement prior to its
termination in May 2000.
(L) COMMITMENTS AND CONTINGENCIES
CAPITAL EXPENDITURE PROGRAM
The Company's continuing capital expenditure program is presently estimated
at $130.8 million, excluding AFUDC, for 1999 through 2003.
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 $83.9 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 $83.9 million, or $4.2
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 $17.8 million per incident. However, any assessment would be limited to
$2.1 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
$3.1 million.
- 15 -
<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.
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. In December of 1996,
Connecticut Yankee filed decommissioning cost estimates and amendments to the
power contracts with its owners with the Federal Energy Regulatory Commission
(FERC). Based on regulatory precedent, this filing seeks confirmation that
Connecticut Yankee 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. On August
31, 1998, a FERC Administrative Law Judge (ALJ) released an initial decision
regarding Connecticut Yankee's December 1996 filing. The initial decision
contains provisions that would allow Connecticut Yankee to recover, through the
power contracts with its owners, the balance of its net unamortized investment
in the Connecticut Yankee Unit, but would disallow recovery of a portion of the
return on Connecticut Yankee's investment in the unit. The ALJ's decision also
states that decommissioning cost collections by Connecticut Yankee, through the
power contracts, should continue to be based on a previously-approved estimate
until a new, more reliable estimate has been prepared and tested. During October
of 1998, Connecticut Yankee and its owners filed briefs setting forth exceptions
to the ALJ's initial decision. If this initial decision is upheld by the FERC,
Connecticut Yankee could be required to write off a portion of the regulatory
asset on its Balance Sheet associated with the retirement of the Connecticut
Yankee Unit. In this event, however, the Company would not be required to record
any write-off on account of its 9.5% ownership share in Connecticut Yankee,
because the Company has recorded its regulatory asset associated with the
retirement of the Connecticut Yankee Unit net of any return on investment. The
Company cannot predict, at this time, the outcome of the FERC proceeding.
However, the Company will continue to support Connecticut Yankee's efforts to
contest the ALJ's initial decision.
The Company's estimate of its remaining share of Connecticut Yankee costs,
including decommissioning, less return of investment (approximately $10.1
million) and return on investment (approximately $4.5 million) at March 31,
1999, is approximately $30.8 million. This estimate, which is subject to ongoing
review and revision, has been recorded by the Company as an obligation and a
regulatory asset 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 5.45% 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
Firm Energy Contract, which currently provides for the sale of 9 million
megawatt-hours per year by Hydro-Quebec to the New England participants in the
Phase II facility, is scheduled to expire in September of 2001, but is subject
to extension in order to remedy deficiencies in deliveries of energy by
Hydro-Quebec. 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, 1999, the Company's guarantee liability for this debt was
approximately $6.7 million.
- 16 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
ENVIRONMENTAL CONCERNS
In complying with existing environmental statutes and regulations and
further developments in areas of environmental concern, including legislation
and studies in the fields of water and air quality (particularly "air toxics"
and "global warming"), hazardous waste handling and disposal, toxic substances,
and electric and magnetic fields, the Company may incur substantial capital
expenditures for equipment modifications and additions, monitoring equipment and
recording devices, and it may incur additional operating expenses. Litigation
expenditures may also increase as a result of scientific investigations, and
speculation and debate, concerning the possibility of harmful health effects of
electric and magnetic fields. The total amount of these expenditures is not now
determinable.
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, 1999, 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 the deactivated English Station generation facilities.
Remediation costs, including the repair and/or replacement of approximately 560
linear feet of sheet piling, are currently estimated at $7.5 million. In
addition, the Company is planning to repair and/or replace the remaining
deteriorated sheet piling bordering the English Station property, at an
additional estimated cost of $10 million.
As described at Note (C) "Rate-Regulated Regulatory Proceedings" above, the
Company has sold its Bridgeport Harbor Station and New Haven Harbor Station
generating plants in compliance with Connecticut's electric utility industry
restructuring legislation. Environmental assessments performed in connection
with the marketing of these plants indicate that substantial remediation
expenditures will be required in order to bring the plant sites into compliance
with applicable Connecticut minimum standards following their sale. The
purchaser of the plants has agreed to undertake and pay for the major portion of
this remediation. However, the Company will be responsible for remediation of
the portions of the plant sites that will be retained by it.
(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 $497 million (in 1999 dollars) as the
decommissioning cost estimate for Seabrook Unit 1, of which the Company's share
would be approximately $87 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 1999 was $0.5 million. UI's share of the fund at
March 31, 1999 was approximately $17.4 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 $560 million (in 1999 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
- 17 -
<PAGE>
THE UNITED ILLUMINATING COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
decommissioning trust fund managed by Northeast Utilities (NU). UI's share of
the Millstone Unit 3 decommissioning payments made during the first quarter of
1999 was $0.1 million. UI's share of the fund at March 31, 1999 was
approximately $6.9 million. The current decommissioning cost estimate for the
Connecticut Yankee Unit, assuming the prompt removal and dismantling of the unit
commencing in 1997, is $476 million, of which UI's share would be $45 million.
Through March 31, 1999, $93.0 million has been expended for decommissioning. The
projected remaining decommissioning cost is $391 million, of which UI's share
would be $37 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 $0.6 million were funded by UI
during the first quarter of 1999, and UI's share of the fund at March 31, 1999
was $24.1 million.
- 18 -
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
MAJOR INFLUENCES ON FINANCIAL CONDITION
In April 1998, Connecticut enacted Public Act 98-28 (the Restructuring
Act), a massive and complex statute designed to restructure the State's
regulated electric utility industry. See Note (C), "Rate-Related Regulatory
Proceedings", for a discussion of the Restructuring Act and its impact on the
Company.
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. Total operation and maintenance expense, excluding
one-time items and cogeneration capacity purchases, declined by 1.1%, on
average, during the past 5 years. There will be significant changes to operation
and maintenance expense and other expenses in 1999, partly as a result of the
Generation Asset Divestiture described in "Looking Forward" below.
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.
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. The Company expects to continue to meet
these criteria in the foreseeable future. The Restructuring Act enacted in
Connecticut in 1998 provides for the Company to recover in future regulated
service rates previously deferred costs through ongoing assessments to be
included in such rates. 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 could 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.
- 19 -
<PAGE>
CAPITAL EXPENDITURE PROGRAM
The Company's 1999-2003 capital expenditure program, excluding allowance
for funds used during construction and its effect on certain capital-related
items, is presently budgeted as follows:
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003 TOTAL
---- ---- ---- ---- ---- -----
(000's)
<S> <C> <C> <C> <C> <C> <C>
Generation (1) $4,891 $4,229 $2,435 $1,851 $1,280 $14,686
Distribution and Transmission 16,954 15,761 11,470 11,509 12,816 68,510
Other 6,443 5,238 2,731 2,543 1,949 18,904
------ ------ ------ ------ ------ -------
Subtotal 28,288 25,228 16,636 15,903 16,045 102,100
Nuclear Fuel 2,413 9,298 6,774 2,953 7,302 28,740
------ ------ ------ ------ ------ -------
Total Expenditures $30,701 $34,526 $23,410 $18,856 $23,347 $130,840
======= ======= ======= ======= ======= ========
Rate Base and Other Selected Data:
- ---------------------------------
Depreciation
Book Plant (1) $50,200 $48,120 $48,636 $48,910 $49,531
Conservation Assets 5,048 0 0 0 0
Decommissioning 2,781 2,892 3,007 3,128 3,253
Additional Required Amortization
Regulatory Tax Assets (pre-tax
and after-tax) 12,096 0 0 0 0
Other Regulatory Assets (pre-tax)(2) 0 49,500 54,500 0 0
Amortization of Deferred
Return on Seabrook Unit 1
Phase-In (after-tax) 12,586 0 0 0 0
Estimated Rate Base
(end of period) 849,684
(average) 920,367
</TABLE>
(1) Reflects divestiture of operating fossil-fueled generation plant on April
16, 1999. See Note (C), "Rate-Related Regulatory Proceedings", for a
description of this divestiture. Remaining operating generation is
nuclear, excluding nuclear fuel.
(2) Additional amortization of unspecified regulatory assets, as ordered by
the Connecticut Department of Public Utility Control in its December 31,
1996 retail rate order, provided that, as expected, common equity return
on utility investment exceeds 10.5% after recording the additional
amortization. Substantially all of this accelerated amortization may have
to be eliminated in order to achieve the minimum 10% price reduction
(compared to the average fully bundled prices in effect on December 31,
1996), while providing for the added costs imposed by Public Act 98-28, a
statute enacted by Connecticut, designed to restructure the State's
regulated electric utility industry. See Note (C), "Rate-Related
Regulatory Proceedings", for a discussion of this statute.
- 20 -
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
At March 31, 1999, the Company had $19.0 million of cash and temporary cash
investments, a decrease of $82.4 million from the balance at December 31, 1998.
The components of this decrease, which are detailed in the Consolidated
Statement of Cash Flows, are summarized as follows:
(Millions)
Balance, December 31, 1998 $ 101.4
------
Net cash provided by operating activities 18.8
Net cash provided by (used in) financing activities:
- Financing activities, excluding dividend payments (90.7)
- Dividend payments (10.2)
Net cash provided by investing activities, excluding investment
in plant 5.5
Cash invested in plant, including nuclear fuel (5.8)
-----
Net Change in Cash (82.4)
Balance, March 31, 1999 $19.0
====
The Company's capital requirements are presently projected as follows:
<TABLE>
<CAPTION>
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
(millions)
<S> <C> <C> <C> <C> <C>
Cash on Hand - Beginning of Year $101.4 $34.5 $9.0 $42.7 $ -
Internally Generated Funds less Dividends 98.4 59.4 57.4 64.4 72.7
Net Proceeds from Sale of Fossil Generation Plants 160.0 - - - -
----- ---- ---- ----- ----
Subtotal 359.8 93.9 66.4 107.1 72.7
Less:
Capital Expenditures (excluding AFUDC) 30.7 34.5 23.4 18.9 23.3
----- ---- ---- ----- ----
Cash Available to pay Debt Maturities and Redemptions 329.1 59.4 43.0 88.2 49.4
Less:
Maturities and Mandatory Redemptions 69.6 0.4 0.3 100.3 100.5
Optional Redemptions 145.0 50.0 - - -
Repayment of Short-Term Borrowings 80.0 - - - -
----- ---- - ----- ----- -----
External Financing Requirements (Surplus) $(34.5) $(9.0) $(42.7) $12.1 $51.1
===== ==== ===== ==== ====
</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 December 31, 1996 price
levels by the year 2000. Connecticut's Restructuring Act, described at Note
(C), "Rate-Related Regulatory Proceedings", required the Company to divest
itself of its fossil-fueled generating plants and requires it to attempt to
divest itself of its ownership interests in nuclear-fueled generating units
prior to January 1, 2004. This forecast reflects the net after-tax proceeds
from the divestiture of fossil-fueled generation plants on April 16, 1999.
All of these estimates are
- 21 -
<PAGE>
subject to change due to future events and conditions that may be
substantially different from those used in developing the projections.
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. 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 8, 1999. 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, 1999, the Company had no 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 UI's regulated electric utility business and provide long-term
rewards to UI's shareowners.
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 UI and other utilities. It
manages agent networks in 36 states and processed approximately $7.5 billion in
customer payments during 1998, generating operating revenues of approximately
$33.7 million and operating income of approximately $1.7 million. Another
subsidiary of URI, Thermal Energies, Inc., owns and operates heating and cooling
energy centers in commercial and institutional buildings, and 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,
government buildings and industrial facilities. URI's fourth subsidiary, United
Bridgeport Energy, Inc., is a 33 1/3% owner of Bridgeport Energy, LLC, which is
completing construction of a 500-megawatt merchant wholesale electric generating
facility in Bridgeport, Connecticut.
RESULTS OF OPERATIONS
FIRST QUARTER OF 1999 VS. FIRST QUARTER OF 1998
- -----------------------------------------------
Earnings for the first quarter of 1999 were $9.9 million, or $.70 per share
(on both a basic and diluted basis), up $1.0 million, or $.06 per share, from
the first quarter of 1998. Excluding one-time items, earnings from operations
were $9.3 million, or $.66 per share, up $.02 per share from the first quarter
of 1998.
The one-time items recorded in the first quarter of 1999 were:
EPS
------------------------------------------------------------------------------
1999 Quarter 1 Purchased power expense refund $.12
"Sharing" of earnings due to refund $(.08)
------------------------------------------------------------------------------
- 22 -
<PAGE>
Retail revenues from operations increased by $6.8 million in the first
quarter of 1999 compared to the first quarter of 1998, as electric sales
increased for reasons detailed below. Retail revenues decreased by $1.0 million
because of "sharing" of earnings required under the current regulatory structure
as applied to the one-time gain recorded in the first quarter of 1999. Retail
fuel and energy expense decreased by $5.0 million, primarily from lower fossil
fuel prices, and there was an increase of $0.2 million in revenue-based taxes.
Overall, retail sales margin (revenue less fuel expense and revenue-based taxes)
from operations increased by $11.6 million or 10.3%. The principal components of
the retail sales margin change for the quarter, year over year, include:
$ millions
------------------------------------------------------------------ -----------
Revenue from:
------------------------------------------------------------------ -----------
Estimate of "real" retail sales growth, up 2.9% 4.3
------------------------------------------------------------------ -----------
Estimate of weather affect on retail sales, up 1.6% 2.4
------------------------------------------------------------------ -----------
Sales decrease from Yale University cogeneration, (1.7)% (2.5)
------------------------------------------------------------------ -----------
Price mix of sales and other 2.5
------------------------------------------------------------------ -----------
"Sharing" due to one-time gain (1.0)
------------------------------------------------------------------ -----------
Fuel and energy, margin effect:
------------------------------------------------------------------ -----------
Sales increase (0.7)
------------------------------------------------------------------ -----------
Nuclear fuel prices to account for previously spent fuel (0.8)
------------------------------------------------------------------ -----------
Fossil fuel price 6.6
------------------------------------------------------------------ -----------
Net wholesale margin (wholesale revenue less wholesale expense) decreased
by $2.2 million in the first quarter of 1999 compared to the first quarter of
1998 from lower wholesale capacity sales. Other operating revenues, which
include NEPOOL related transmission revenues, increased by $1.6 million. NEPOOL
transmission revenues are recoveries, for the most part, of NEPOOL transmission
expense and simply reflect new accounting requirements implemented by the
Federal Energy Regulatory Commission (FERC).
It should be noted that on April 16, 1999, the Company completed the sale
of its operating fossil-fueled generating plants and existing wholesale sales
contracts (known as the Generation Asset Divestiture or GAD) that was required
by Connecticut's electric utility industry restructuring legislation. As a
result of GAD, the "geography" of the Company's costs on the income statement,
and hence, the year-over-year variances, will change significantly beginning in
the second quarter. This particularly relates to wholesale revenue, fossil fuel
expense, operations and maintenance expense, depreciation and interest charges.
See "Looking Forward" below for more details.
Operating expenses for operations, maintenance and purchased capacity
charges increased by $6.7 million in the first quarter of 1999 compared to the
first quarter of 1998. The principal components of these expense changes
include:
$ millions
------------------------------------------------------------------ ---------
Capacity expense:
------------------------------------------------------------------ ---------
Connecticut Yankee (0.4)
------------------------------------------------------------------ ---------
Cogeneration and other purchases (see Note) 3.2
------------------------------------------------------------------ ---------
Other O&M expense:
------------------------------------------------------------------ ---------
Seabrook Unit (refueling outage and accruals) 1.9
------------------------------------------------------------------ ---------
Millstone Unit 3 (0.2)
------------------------------------------------------------------ ---------
Fossil generation unit overhaul and outage costs (1.6)
------------------------------------------------------------------ ---------
NEPOOL transmission expense 0.9
------------------------------------------------------------------ ---------
Other miscellaneous 2.9
------------------------------------------------------------------ ---------
Note: A cogeneration facility was out of service for about a month in the
first quarter of 1998 but has operated normally in 1999.
- 23 -
<PAGE>
Depreciation expense increased by $0.2 million in the first quarter of 1999
compared to the first quarter of 1998.
On December 31, 1996, the Connecticut Department of Public Utility Control
(DPUC) issued an order (the Order) that implemented a five-year Rate Plan to
reduce the Company's retail prices and accelerate the recovery of certain
"regulatory assets". According to the Rate Plan, under which the Company is
currently operating, "accelerated" amortization of past utility investments is
scheduled for every year that the Rate Plan is in effect, contingent upon the
Company earning a 10.5% return on utility common stock equity. All of the
accelerated amortization for 1998, amounting to $13.1 million (before-tax, $8.5
million after-tax), was recorded against earnings from operations in 1998. One
fourth of the total accelerated amortization for 1999, or $3.3 million
(before-tax, $2.1 million after-tax), was recorded in the first quarter. The
Company has begun amortizing regulatory income tax assets for the 1999 amount,
totaling $12.1 million (after-tax), one-fourth of it, or $3.0 million
(after-tax), in the first quarter.
The Company can also incur additional accelerated amortization expense as a
result of the "sharing" mechanism in the Rate Plan if the Company achieves a
return on utility common stock equity above 11.5%, on an annual basis. Such
"sharing" amortization was recorded in the first quarter of 1999, in the amount
of $0.6 million (after-tax), as a result of the one-time gain recorded in the
first quarter. There was no "sharing" recorded against earnings from operations
in the first quarter of 1998, or in 1999.
Other net income decreased by about $0.9 million in the first quarter of
1999 compared to first quarter of 1998. The Company's largest unregulated
subsidiary, American Payment Systems (APS), earned about $246,000 (before-tax)
in the first quarter of 1999, slightly less than the $284,000 (before-tax)
earned in the first quarter of 1998. Income for Precision Power, Inc. decreased
$0.7 million (before-tax), reflecting increased infrastructure costs as it
prepares to expand its service offerings. The first quarter loss was in line
with expectations outlined in the "Looking Forward" section of Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations in the Company's annual report on Form 10-K for the year ended
December 31, 1998. Income from other unregulated subsidiary activities at United
Resources, Inc. decreased by $0.6 million (before-tax) from start-up costs.
Interest charges continued on their downward trend, decreasing by $0.2
million in the first quarter of 1999 compared to the first quarter of 1998. Most
of the reduction in interest charges anticipated for 1999 compared to 1998 will
come after the GAD, which was completed on April 16, 1999. On April 16, 1999,
the Company used proceeds received from the sale of plant to repay $205 million
of debt. See "Looking Forward" below for more details.
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
INCOME AND EARNINGS NUMBERS AS ONLY THE "MOST LIKELY" TO OCCUR WITHIN A RANGE OF
POSSIBLE VALUES.)
Five-year Rate Plan
- -------------------
The reader is referred to Note (C), "Rate-Related Regulatory Proceedings"
above, for a description of the Company's five-year Rate Plan and Connecticut's
electric utility industry restructuring legislation.
1999 Earnings
- -------------
1999 will be a year of transition to the January 1, 2000 effective date of
electric utility restructuring legislation passed by the Connecticut legislature
in 1998. The Company has taken one major step toward restructuring by
- 24 -
<PAGE>
effecting the sale of its operating fossil fuel generation plants and existing
wholesale sales contracts (known as the Generation Asset Divestiture program, or
GAD). That sale was completed on April 16, 1999. All of the changes resulting
from GAD, described below, will occur beginning April 16.
One result of the GAD will be a reduction in the electric utility rate
base, the basis for measuring return on utility common stock equity. Rate base
is expected to decline from an average of $1,128 million in 1998 to about $920
million in 1999. Offsetting the effect of the decline in total rate base is the
Company's long-standing policy of debt paydown that increases the portion of
rate base financed by equity. The portion of rate base that is financed by
equity is expected to decline from an average of about $431 million in 1998 to
about $410-$420 million in 1999. During 1998, a return of 11.5% on utility
common stock equity would have produced earnings of about $3.43 per share.
Absent the one-time items that reduced earnings in 1998, utility earnings from
operations above $3.43 per share would have given rise to an imputed "sharing"
benefit of an additional $.12 per share. Because of the equity funded rate base
reduction expected in 1999, the allowed 11.5% return would be expected to
produce utility earnings in the $3.35-$3.40 per share range. Currently, the
Company expects to be in a "sharing" position in 1999, to a somewhat greater
extent than was the case for earnings from operations in 1998.
The Company's earnings from its utility business are affected principally
by: retail sales that fluctuate with weather conditions and economic activity,
nuclear generating unit availability and operating costs, and interest rates.
These are all items over which the Company has little control.
The Company's revenues are principally dependent on the level of retail
electricity sales. The two primary factors that affect the volume of these
retail sales are economic conditions and weather. The Company's retail sales for
1998 of 5,452 gigawatt-hours set an all-time record for the Company and were up
1.4% from the 1997 level.
The Company estimates that mild 1998 weather reduced retail kilowatt-hour
sales by about 0.5%, retail revenues by about $3.4 million, and retail sales
margin by about $2.7 million. Weather corrected retail sales for 1998 were
probably in the 5,470-5,500 gigawatt-hour range. On this weather-adjusted basis,
the Company experienced about 1.0-1.5% of "real" sales growth in 1998 over
weather-adjusted 1997 sales, with most of the growth appearing to occur in the
first three quarters of the year.
Aside from "real" economic growth, reductions in retail electricity sales
will occur in 1999 compared to 1998 as a result of a cogeneration unit at Yale
University that produces approximately one half of Yale's annual electricity
requirements (about 1.5% of the Company's total 1998 retail sales). This unit
commenced operations in mid-1998, and has reduced total Company retail
kilowatt-hour sales by about 0.9% in 1998 compared to 1997. The remaining impact
will be reflected in the first half of 1999. Thus, it would require "real"
growth of 0.5% in 1999 compared to 1998 just to maintain the 1998 level of
"real" sales. "Real" growth in kilowatt-hour sales for the first quarter of 1999
compared to the first quarter of 1998 was estimated to be 2.9%, only partially
offset by a 1.7% decrease in sales to Yale University. Retail kilowatt-hour
sales growth of 1.0%, on an annual basis, produces a retail sales margin
improvement of about $5.0 million, before any "sharing" effect considerations.
Prices in individual customer rate classes will not change in 1999 relative
to 1998, exclusive of any "sharing". However, sales growth is occurring in rate
classes with higher than average prices, and the Company expects to have an
increase in retail revenue of about $3.0 million in 1999 compared to 1998 from
this price mix improvement.
Other operating revenues are expected to increase by about $4.0 million in
1999 relative to 1998, due to increased transmission revenues resulting from
NEPOOL restructuring changes; but this should have no net income effect, as the
higher revenues are due to higher transmission operating expense. Other than the
NEPOOL impact, these revenues are expected to decrease by about $2.0 million to
a more normal level. The Company does not anticipate, at this time, any other
significant revenue reductions in 1999 compared to 1998, unless the Company is
achieving a "sharing" level of earnings.
- 25 -
<PAGE>
As a result of the GAD, wholesale capacity revenues will decrease by about
$7.7 million in 1999 compared to 1998, because existing wholesale sales
contracts were part of the GAD. Also as a result of the GAD, the Company's
purchased energy charges will increase in 1999 compared to 1998 by about $40
million, to replace the power previously provided by the Company's fossil-fueled
generation plants. A power supply purchase agreement was part of the GAD and it
will help to ensure that the Company has adequate resources to meet customer
energy demands until July 2000 (the price under this short-term, fixed-price
agreement declines somewhat in 2000 compared to 1999) when all customers will
have a choice of generation suppliers. The Company expects that its projected
1999 energy requirements that are not met by the GAD power supply purchase
agreement will be met at lower prices than those experienced in 1998, primarily
because of lower projected fossil fuel prices and energy prices in general. This
is expected to result in energy cost savings of about $5 million.
Purchased capacity costs should decrease by about $2 million in 1999, due
primarily to the retirement of the Connecticut Yankee nuclear generation plant.
Several other expense categories are expected to be reduced substantially
in 1999 because of the GAD and the Company's other cost reduction efforts,
offsetting the impact of the increase in purchased energy charges. Operation and
maintenance expense is expected to decrease by a net $22 million, reflecting a
decrease of $32 million due to the GAD and other general changes, partly offset
by increases of about $5 million for nuclear unit refueling outages and $1
million for Y2K costs and $4 million due to NEPOOL transmission operating
expense charges The latter would have no net income effect, as the higher
transmission expense should be offset by higher transmission revenues. Total Y2K
costs for 1999 are currently projected at about $3.6 million. Other operation
and maintenance expenses in 1999 should be fairly stable compared to 1998,
unless an event occurs that cannot be predicted at this time.
Consolidated interest costs are now expected to decline by about $12
million in 1999 compared to 1998, to about $40 million, a level that was last
experienced in 1982. This anticipated interest cost reduction will result
largely from utility debt paydown through use of the after-tax cash proceeds
from the GAD sale, partly offset by the impact of the Company's passive
financial investment increase in Bridgeport Energy LLC. The Bridgeport Energy
investment was announced in a news release dated March 30, 1999, and represents
a 33 1/3% stake in an operational combined cycle gas turbine operated on a
merchant basis by Duke Energy in Bridgeport, Connecticut. The Company also
expects to generate substantial cash flow from operations after dividend and
capital spending, which will also be used to reduce debt.
Depreciation, excluding accelerated amortization, should decrease by about
$13 million in 1999 compared to 1998, due mostly to the GAD but also from the
near completion in 1998 of the depreciation of previously capitalized
conservation program expenditures. A significant portion of the decrease in
depreciation related to the GAD will not affect taxable income and will not
increase income taxes, and will therefore supplement the $13 million decrease
with an additional tax benefit, comparing 1999 to 1998, of about $2.5 million,
or $.18 per share.
Accelerated amortization, under the Rate Plan, will increase by about $4
million (on an equivalent after-tax basis) in 1999 compared to 1998, exclusive
of any "sharing" amortization. Property taxes should decrease by about $2
million, due mostly to the GAD. Other operating expenses can be expected to have
some increases and some decreases that should, more or less, offset one another.
In summary, the Company expects substantial net expense reductions as a
result of the GAD and ongoing cost control measures that should more than
compensate for increased charges for purchased power and increased accelerated
amortization costs in 1999. This should allow utility earnings to increase above
an 11.5% return on utility common stock equity into the "sharing" range of the
Rate Plan. The 11.5% return level would allow for utility earnings from
operations of about $3.35-$3.40 per share, while the "shared" earnings from
operations above that level are currently anticipated to increase per share
earnings by about $.20 per share, although the size of this increase will
fluctuate with every event that affects utility operations during the year. The
Company expects that 1999 quarterly earnings from operations will follow a
pattern similar to that of 1998 on a weather-normalized basis.
- 26 -
<PAGE>
Unregulated subsidiaries are expected to occasion a loss of up to $.10 per
share to earnings in 1999. American Payment Systems, Inc. is expected to build
on 1998's contribution to earnings from operations of $.07 per share. However,
this will depend on its ability to expand sales to its utility customers.
Precision Power, Inc. (PPI) increased its organizational infrastructure in 1998,
also in an effort to increase its presence in its principal markets of
distributed power systems and services. At its current level of expense, PPI
would occasion a loss of $.10 to $.15 per share in 1999, if no substantial new
contracts are obtained. PPI may also engage in acquisition activities in 1999
that may have short-term dilutive effects on earnings beyond those indicated
above. For 2000 and beyond, the Company's passive financial investment in
Bridgeport Energy is expected to increase annual earnings from operations by
$.10 to $.15 per share.
As a result of the earnings contributions anticipated from all of its
different business activities described above, the Company expects net earnings
per share from operations to be in the range of $3.45 to $3.65 in 1999. These
estimates are subject to all of the contingencies and uncertainties detailed in
the preceding discussion and the reader is cautioned to read this "Looking
Forward" section in its entirety.
Year 2000 Issue
- ---------------
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. This comprehensive program includes all
information technology systems and encompasses systems critical to the
generation, transmission and distribution of electric energy as well as
traditional business systems. Critical systems have been defined as those
business processes, including embedded technology, which if not remediated may
have a significant impact on safety, customers, revenue or regulatory
compliance. The Company has also identified 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 have been completed, and
recommended solutions to all identified risks and exposures have been generated.
A testing, remediation, renovation, replacement and retirement program has been
in progress since early 1998. Both external and internal resources are being
utilized to accomplish the testing, remediation and renovation efforts. A total
of 383 affected business processes have been identified and 307 of them have
been verified as Year 2000 compliant through testing, remediation, replacement
or retirement. The remediation methodology utilized has been Fixed Windowing,
and totally independent platforms have been installed for testing all of the
applications. Necessary upgrades to mainframe hardware and software are expected
to be completed and tested by June 30, 1999. A parallel program for desktop
hardware and application software on all platforms is currently projected to be
completed and tested, for all critical systems, by June 1, 1999, except in a
minority of cases where a business specific need dictates a later date - but not
later than December 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 included its operating
non-nuclear generation facilities in the Year 2000 program up to the date of
their divestiture on April 16, 1999. At that point, all related documentation
was transferred and delivered to Wisvest-Connecticut, LLC, the purchaser of
these generation facilities. See Note (C), "Rate-Related Regulatory Proceedings"
above, for a description of this transaction.
While failure to achieve Year 2000 compliance by any one of a number of
critical suppliers and data sharers could have some adverse effect on the
success of the Company's implementation program, the Company believes that the
entities that might impact the program most significantly in this regard are its
telecommunications providers, the other participants in the New England Power
Pool (NEPOOL), and the Independent System Operator (ISO) that operates the
NEPOOL bulk power supply system. Year 2000 compliance failures by any of these
entities
- 27 -
<PAGE>
could have a material effect on electricity delivery and telemetering. In its
efforts to mitigate these risks the Company has taken several actions. UI has
communicated its concerns to its principal telecommunications provider and a
joint effort to design and plan appropriate testing to insure that all critical
telecommunications functions will be operational has commenced. The Year 2000
Issue is also being addressed at the regional level by NEPOOL and the ISO.
Coordination efforts with NEPOOL to establish utility testing and readiness are
in progress. The Company is a participant in all of the subcommittees working
within NEPOOL/ISO on efforts to assure operational reliability. The Company is
also actively involved with NEPOOL/ISO in the planning effort for integrated
contingency planning, as directed by the North American Electric Reliability
Council (NERC) . The first NERC directed test was completed on April 9, 1999.
Aside from telecommunications and NEPOOL/ISO concerns, the availability of
vendor patches, releases and/or replacement equipment or software poses the most
significant risk to the success of the Company's Year 2000 compliance
implementation program. In order to minimize these risks, the Company has
commenced its contingency planning. While the Company's knowledge and experience
in electric system recovery planning and execution has been demonstrated in the
past, the Company recognizes the need for, and importance of, Year 2000-specific
contingency planning, because the complex interaction of today's computing and
communications systems precludes certainty that all critical system remediation
will be successful. High level contingency planning for essential business
processes has been completed. These plans will be continually reviewed, revised
and modified throughout the remainder of the year as appropriate. As a part of
the contingency planning process, consideration will be given to potential
frequency and duration of interruptions in the generating, financial and
communications infrastructures. Since contingency planning is, by nature, a
speculative process, there can be no assurance that this planning will
completely eliminate the risk of material impacts to the Company's business due
to Year 2000 problems. However, the Company recognizes the importance to its
customers of a reliable supply of electricity, and it intends to devote whatever
resources are necessary to assure that both the program and its implementation
are successful.
The Company believes that the successful implementation of this program
will cost approximately $6 million for existing information systems and embedded
technology. A total of $4.6 million had been expended as of March 31, 1999. As
systems testing progresses and more embedded technology vendor product
information is forthcoming, business decisions made and testing results
verified, the need for increased expenditures, if necessary, will be determined.
The Company believes these actions will preclude any adverse impact of the Year
2000 Issue on its operations or financial condition.
- 28 -
<PAGE>
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
On March 5, 1999, the Connecticut Superior Court approved the settlement
agreement between the Company and the City of New Haven relative to all of the
Company's contested personal property tax assessments and tax bills for the
years 1991-1992 through 1997-1998 and the Company's personal property tax
assessments for the tax year 1998-1999 and subsequent years. The Company has
paid the City $14.025 million pursuant to this settlement agreement.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits.
<TABLE>
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
---------- ------- -----------
<S> <C> <C>
(3) 3.2c Copy of Bylaws of The United Illuminating Company.
(10) 10.6h Copy of Restated New England Power Pool Agreement, amending and
restating Exhibit 10.5*.
(10) 10.28 Copy of Power Supply Agreement between The United Illuminating
Company and Wisvest-Connecticut, LLC, dated April 16, 1999.
(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, 1999 and Twelve Months Ended December 31, 1998, 1997, 1996,
1995 and 1994).
(27) 27 Financial Data Schedule.
</TABLE>
- ------------------------
*Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1998.
(b) Reports on Form 8-K.
None
- 29 -
<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 05/14/99 Signature /s/ Robert L. Fiscus
---------------- ---------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
and Chief Financial Officer
- 30 -
<PAGE>
<TABLE>
EXHIBIT INDEX
<CAPTION>
Exhibit
Table Item Exhibit
Number Number Description
---------- -------- -----------
<S> <C> <C>
(3) 3.2c Copy of Bylaws of The United Illuminating Company.
(10) 10.6h Copy of Restated New England Power Pool Agreement, amending and
restating Exhibit 10.5*.
(10) 10.28 Copy of Power Supply Agreement between The United Illuminating
Company and Wisvest-Connecticut, LLC, dated April 16, 1999.
(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, 1999 and Twelve Months Ended December 31, 1998, 1997, 1996,
1995 and 1994).
(27) 27 Financial Data Schedule.
</TABLE>
*Filed with Quarterly Report (Form 10-Q) for fiscal quarter ended March 31,
1998.
EXHIBIT 3.2c
===============================
BYLAWS
OF
THE UNITED ILLUMINATING COMPANY
(a Connecticut corporation)
ADOPTED NOVEMBER 20, 1939
As Amended to March 22, 1999
===============================
<PAGE>
BYLAWS
OF
THE UNITED ILLUMINATING COMPANY
(A CONNECTICUT CORPORATION)
ADOPTED NOVEMBER 20, 1939
AS AMENDED TO MARCH 22, 1999
-----
ARTICLE I.
OFFICES.
SECTION 1. PRINCIPAL OFFICE. The location of the principal office of the
Corporation shall be in the Town of New Haven County of New Haven in the State
of Connecticut.
SECTION 2. OTHER OFFICES. The Corporation may also have an office in the Town of
Bridgeport, County of Fairfield in the State of Connecticut, and other offices
at such other places within or without the State of Connecticut as the Board of
Directors or the President may from time to time determine or as the business of
the Corporation may require.
ARTICLE II.
MEETINGS OF SHAREHOLDERS.
SECTION 1. ANNUAL MEETING. The annual meeting of the shareholders shall be held
at the principal office of the Corporation in the State of Connecticut, or at
such other place in said State as the Board of Directors or the President may
determine, on the first Wednesday of April in each year, unless another date
shall be designated by the Board of Directors, in which case such meeting shall
be held on the date so designated, for the purpose of electing a Board of
Directors and for the transaction of any other business which may legally come
before the meeting.
SECTION 2. SPECIAL MEETINGS. Special meetings of the shareholders may be called
at any time by the President, or in his absence or disability by a Vice
President, and shall be called on the request in writing or by a vote of a
majority of the Board of Directors or upon the written request of the holders of
not less than 35 percent of the voting power of all shares entitled to vote at
the meeting. Special meetings of the shareholders may be held at such place
within the State of Connecticut as is specified in the notice or call of such
meeting.
<PAGE>
SECTION 3. NOTICE OF MEETINGS. A written or printed notice of each meeting of
shareholders, stating the place, day and hour of the meeting and the general
purpose or purposes for which it is called, shall be mailed, postage prepaid, by
or at the direction of the Secretary, to each shareholder of record entitled to
vote at such meeting, addressed to the shareholder at the shareholder's last
known post office address as last shown on the stock records of the Corporation,
not less than ten days nor more than sixty days before the date of the meeting.
SECTION 4. QUORUM. At any meeting of the shareholders, the holders of a majority
of the voting power of the shares entitled to vote, present in person or by
proxy, shall constitute a quorum for such meeting, except as otherwise expressly
provided by statute, the Certificate of Incorporation of the Corporation or
these Bylaws. In the absence of a quorum, the holders of a majority of the
voting power of the shares entitled to vote, present in person or by proxy, may
adjourn the meeting from time to time, not exceeding thirty days at any one
time, without further notice, until a quorum shall attend, and thereupon any
business may be transacted which might have been transacted at the meeting as
originally called.
Except where otherwise expressly provided by statute, the Certificate of
Incorporation of the Corporation or these Bylaws, when a quorum is present at
any duly held meeting, directors shall be elected by a plurality of the votes
cast by the holders of the voting power of shares entitled to vote in the
election of directors, and any other action to be voted on shall be approved if
the votes favoring the action cast by the holders of the voting power of the
shares entitled to vote on the matter exceed the votes opposing the action cast
by such shareholders.
SECTION 5. VOTING. Each holder of a share which may be voted on a particular
subject matter at any meeting of shareholders shall be entitled to one vote, in
person or by proxy, for each such share standing in his name on the books of the
Corporation on the record date for such meeting. All voting at meetings of
shareholders shall be by voice vote, except that the vote for the election of
directors shall be by ballot and except where a vote by ballot is required by
law or is determined to be appropriate by the officer presiding at such meeting.
SECTION 6. INSPECTORS OF PROXIES AND TELLERS. The Board of Directors or, in the
absence of action by the Board of Directors, the President or, in the absence or
disability of the President, the chairman of the meeting may appoint two persons
(who may be officers or employees of the Corporation) to serve as Inspectors of
Proxies and the same persons or two other persons (who may be officers or
employees of the Corporation) to serve as Tellers at any meeting of
shareholders. The determination by such persons of the validity of proxies and
the count of shares voted shall be final and binding on all shareholders.
2
<PAGE>
ARTICLE III.
DIRECTORS.
SECTION 1. GENERAL POWERS. The property, affairs and business of the Corporation
shall be managed by its Board of Directors, which may exercise all the powers of
the Corporation except such as are by law or by the Certificate of Incorporation
of the Corporation or by these Bylaws expressly conferred upon or reserved to
the shareholders.
SECTION 2. NUMBER AND TERM OF OFFICE. The number of directorships shall be
thirteen. Directors shall be elected to hold office until the next annual
meeting of the shareholders and until their successors shall have been elected
and qualified.
SECTION 3. VACANCIES. Subject to the provisions of the second paragraph of this
Section, in case of any vacancy among the directors through death, resignation,
disqualification, failure of the shareholders to elect as many directors as the
number of directorships fixed by Section 2 of this Article III, or any other
cause except the removal of a director, the directors in office, although less
than a quorum, by the affirmative vote of the majority of such other directors,
or the sole director in office if there be only one, may fill such vacancy;
provided that the shareholders entitled to vote may fill any such vacancy not so
filled.
If any such vacancy occurs in respect of a director elected by a particular
class of shares voting as a class, and if such class is still entitled to fill
such directorship, the remaining directors elected by such class, by the
affirmative vote of a majority of such remaining directors, or the sole
remaining director so elected if there be only one, may fill such vacancy;
provided the shareholders of such class may fill any such vacancy not so filled.
The resignation of a director shall be effective at the time specified therein
and, unless otherwise specified therein, the acceptance of a resignation shall
not be necessary to make it effective.
SECTION 4. REMOVAL OF DIRECTORS. Any director may be removed from office either
with or without cause at any time, and another person may be elected in his
stead to serve for the remainder of his term at any special meeting of the
shareholders called for the purpose, by vote of a majority of all the shares
outstanding and entitled to vote.
SECTION 5. PLACE OF MEETING. The directors may hold their meetings and have one
or more officers and keep the books of the Corporation (except as otherwise at
any time may be provided by
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law) at such place or places within or without the State of Connecticut as the
Board of Directors may from time to time determine.
SECTION 6. ORGANIZATION MEETINGS OF THE BOARD. The newly elected Board of
Directors may meet for the purpose of organization, for the election of
officers, and for the transaction of other business immediately following the
adjournment of the annual meeting of the shareholders or at such other time and
place as shall be fixed by the shareholders at the annual meeting, and if a
quorum be then present no prior notice of such meeting shall be required to be
given to the directors. The time and place of such organization meeting may also
be fixed by written consent of the newly elected directors, or such organization
meeting may be called by the President upon reasonable notice.
SECTION 7. REGULAR MEETINGS. Regular meetings of the Board of Directors shall be
held at such times and places within or without the State of Connecticut as the
Board of Directors shall from time to time designate.
SECTION 8. SPECIAL MEETINGS. Special meetings of the Board of Directors may be
called at any time by the Chairman of the Board of Directors (if one there be)
or by the President or, in the absence or disability of the President, by a Vice
President, and shall be called upon the written request of two directors, or may
be called by a majority of the directors. Special meetings of the Board shall be
held at such place, either within or without the State of Connecticut, as shall
be specified in the call of the meeting.
SECTION 9. NOTICE OF MEETINGS. The Secretary of the Corporation shall give
reasonable notice to each director of each regular or special meeting, either by
mail, telegraph, telephone or personally, which notice shall state the time and
place of the meeting.
SECTION 10. QUORUM. A majority of the number of directorships shall constitute a
quorum for the transaction of business, except where otherwise provided by
statute or by these Bylaws, but a majority of those present at any regular or
special meeting, if there be less than a quorum, may adjourn the same from time
to time without notice until a quorum be had. The act of a majority of the
directors present at any meeting at which there is a quorum shall be the act of
the Board of Directors, except as otherwise may be provided by statute or by
these Bylaws.
SECTION 11. COMPENSATION OF DIRECTORS. The Board of Directors shall have
authority to fix the compensation of directors and of members of committees of
the directors, including reasonable allowances for expenses incurred in
connection with their duties.
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SECTION 12. ACTION WITHOUT MEETING. If all of the directors severally or
collectively consent in writing to any action taken or to be taken by the
Corporation, and the number of such directors constitutes a quorum for such
action, such action shall be as valid corporate action as though it had been
authorized at a meeting of the Board of Directors. The Secretary shall file such
consent or consents with the minutes of the meetings of the Board of Directors.
ARTICLE IV.
EXECUTIVE COMMITTEE AND OTHER COMMITTEES.
SECTION 1. APPOINTMENT. The Board of Directors, by resolution adopted by the
affirmative vote of directors holding a majority of the directorships, may
appoint an Executive Committee, consisting of four or more directors, one of
whom shall be the Chairman of the Board of Directors (if one there be) to serve
during the pleasure of the Board, and may fill vacancies in such committee. The
Executive Committee shall have and may exercise all such authority of the Board
of Directors as shall be provided in such resolution.
SECTION 2. MINUTES. The Executive Committee shall keep regular minutes of its
proceedings and report the same to the Board of Directors.
SECTION 3. OTHER COMMITTEES. The Board of Directors, by resolution adopted by
the affirmative vote of directors holding a majority of the directorships, may
appoint any other committee or committees consisting of two or more directors to
serve during the pleasure of the Board, which committees shall have and may
exercise such authority of the Board of Directors as shall be provided in such
resolution.
ARTICLE V.
OFFICERS, AGENTS AND ATTORNEYS.
SECTION 1. EXECUTIVE OFFICERS. The executive officers of the Corporation shall
be a Chairman of the Board of Directors, if the Board of Directors so determine,
and a President, one or more Vice Presidents, a Secretary and a Treasurer, all
of whom shall be elected by the Board of Directors. The Board of Directors may
also appoint such additional officers, including, but not limited to, one or
more Assistant Secretaries and Assistant Treasurers, as in their judgment may be
necessary, who shall have authority to perform such duties as may from time to
time be designated by the Board of Directors or by the President. Any two of
said offices may be held by the same person, except that the same
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person shall not be President and Vice President, or President and Secretary.
SECTION 2. POWERS AND DUTIES OF THE CHAIRMAN OF THE BOARD OF DIRECTORS. The
Chairman of the Board of Directors (if one there be) when present shall preside
at all meetings of the Board of Directors, of the Executive Committee, and of
the shareholders. He shall have such powers and shall perform such duties as may
from time to time be assigned to him by the Board of Directors.
If so designated by the Board of Directors, the Chairman of the Board of
Directors shall be the chief executive officer of the Corporation and as such,
he, and not the President, shall have and possess all of the powers and
discharge all of the duties assigned to the President in these Bylaws, except
that (1) in the absence, disability or death of the Chairman of the Board of
Directors, the President shall have and possess all of such powers and discharge
all of such duties, (2) the Board of Directors may delegate one or more of such
powers and duties to the President, (3) the Chairman of the Board of Directors
shall not have the power or duty, of signing certificates for the shares of the
Corporation and (4) both the Chairman of the Board of Directors and the
President shall be included among those officers who may act with respect to
shares of other corporations held by the Corporation and who may sign or
countersign checks, drafts and notes of the Corporation under the provisions of
Sections 5 and 6, respectively, of Article VII of these Bylaws.
SECTION 3. POWERS AND DUTIES OF THE PRESIDENT. The President shall be the chief
executive officer of the Corporation unless the Board of Directors designates
the Chairman of the Board of Directors as the chief executive officer of the
Corporation; he may sign, with the Secretary or an Assistant Secretary or the
Treasurer or an Assistant Treasurer, certificates for the shares of the
Corporation, and he shall sign and execute, in the name of the Corporation, all
deeds, mortgages, bonds, contracts or other instruments authorized by the Board
of Directors, except in cases where the signing and execution thereof shall be
delegated by the Board of Directors or by these Bylaws to some other officer or
agent of the Corporation; and, in general, shall perform all the duties incident
to the office of the President; provided, however, that any or all of the powers
and duties of the President above set forth may be delegated by the Board of
Directors by vote or by a contract of the Corporation approved by the Board, to
some other officer, agent or employee of the Corporation. In the absence of the
Chairman of the Board of Directors, or if there shall be no Chairman of the
Board of Directors, the President shall preside at all meetings of the Board of
Directors, of the Executive Committee, and of the shareholders.
SECTION 4. POWERS AND DUTIES OF THE VICE PRESIDENTS. In the absence, disability
or death of the President, a Vice President shall have and possess all the
powers and discharge all the
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duties of the President, and the Board of Directors may designate the particular
Vice President, if more than one, thus to possess the powers and discharge the
duties of the President. Any Vice President may also sign, with the Secretary or
an Assistant Secretary or the Treasurer or an Assistant Treasurer, certificates
for the shares of the Corporation, and shall perform such other duties as from
time to time may be assigned to him by the Board of Directors or by the
President.
SECTION 5. POWERS AND DUTIES OF THE SECRETARY. It shall be the duty of the
Secretary to act as Secretary of all meetings of the Board of Directors and of
the shareholders of the Corporation and keep the minutes thereof in a proper
book or books to be provided for that purpose; he shall see that all notices
required to be given by the Corporation are duly given or served; he may sign,
with the President or a Vice President, certificates for the shares of the
Corporation; he shall have the custody of the seal of the Corporation and, on
behalf of the Corporation, he may attest and affix the corporate seal to such
instruments as may require the same; and he shall in general perform all of the
duties incident to the office of Secretary, and such other duties as may from
time to time be assigned to him by the Board of Directors or by the President.
SECTION 6. POWERS AND DUTIES OF THE TREASURER. The Treasurer shall have the care
and custody of all the funds and securities of the Corporation which may come
into his hands and shall deposit all such funds to the credit of the Corporation
in such banks, trust companies or other depositaries as shall be designated by
the Board of Directors or pursuant to its authorization; he shall enter, or
cause to be entered, regularly, in books to be kept by him for that purpose,
full and adequate account of all moneys received and paid by him on account of
the Corporation, and shall render a detailed statement of his accounts and
records to the Board of Directors as often as they shall require the same; he
may endorse for deposit or collection all negotiable instruments requiring
endorsement for or on behalf of the Corporation; he may sign all receipts and
vouchers for payments made to the Corporation; he may sign, with the President
or a Vice President, certificates for the shares of the Corporation; and he
shall in general perform all the duties incident to the office of Treasurer, and
such other duties as may from time to time be assigned to him by the Board of
Directors or by the President.
SECTION 7. POWERS AND DUTIES OF ASSISTANT SECRETARY AND ASSISTANT TREASURER. In
the absence, disability or death of the Secretary or whenever the convenience of
the Corporation shall make it advisable, an Assistant Secretary shall have and
possess all the powers and discharge all the duties of the Secretary; and in the
absence, disability or death of the Treasurer or whenever the convenience of the
Corporation shall make it advisable, an Assistant Treasurer shall have and
possess all the powers and discharge all the duties of the Treasurer.
7
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SECTION 8. AGENTS AND ATTORNEYS. The Board of Directors may appoint such agents,
attorneys and representatives of the Corporation with such powers and to perform
such acts and duties on behalf of the Corporation as the Board of Directors may
determine, so far as the same shall not be inconsistent with the laws of the
State of Connecticut, the Certificate of Incorporation of the Corporation, or
these Bylaws.
SECTION 9. SALARIES. The salaries of the officers, including the Chairman of the
Board of Directors (if one there be) and the President, may be fixed from time
to time by the Board of Directors, and no officer shall be prevented from
receiving a salary by reason of the fact that he is also a director of the
Corporation.
SECTION 10. CERTAIN OFFICERS TO GIVE BONDS. Every officer, agent or employee of
the Corporation, who may receive, handle or disburse money for its account or
who may have any of the Corporation's property in his custody or be responsible
for its safety or preservation, may be required, in the discretion of the Board
of Directors or the Executive Committee to give bond, in such sum and with such
sureties and in such form as shall be satisfactory to the Board of Directors or
the Executive Committee, for the faithful performance of the duties of his
office and for the restoration to the Corporation, in the event of his death,
resignation or removal from office, of all books, papers, vouchers, moneys and
other property of whatsoever kind in his custody belonging to the Corporation.
SECTION 11. REMOVAL OF OFFICERS. Any officer elected or appointed by the
directors may be removed at any time with or without cause by the affirmative
vote of a majority of all of the directors, but nothing in this Section shall
operate to invalidate, impair or otherwise affect any employment contract
entered into by the Corporation which contract has been authorized or ratified
by the affirmative vote of a majority of all the directors. The election or
appointment of an officer for a given term shall not of itself create contract
rights.
SECTION 12. VACANCIES. All vacancies among the officers from whatsoever cause
may be filled by the Board of Directors.
ARTICLE VI.
SHARES AND CERTIFICATES FOR SHARES.
SECTION 1. CERTIFICATES OF SHARES. Every shareholder of the Corporation shall be
entitled to a certificate or certificates, signed by, or, if the certificates
are signed by a transfer agent acting on behalf of the Corporation, bearing the
facsimile signatures of, the President or a Vice President and the Treasurer or
an Assistant Treasurer or the Secretary or an Assistant Secretary, and under the
seal of the Corporation or
8
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with a facsimile of such seal affixed, certifying the number and class of shares
of the Corporation owned by him. All certificates shall be consecutively
numbered, and the names and addresses of all persons owning shares of the
Corporation, with the number of shares owned by each and the date or dates of
issue of the shares held by each, shall be entered in books kept for that
purpose by the proper officers or agents of the Corporation.
The Corporation shall be entitled to treat the holder of record of any share or
shares as the holder in fact thereof and, accordingly, shall not be bound to
recognize any equitable or other claim to or interest in such share or shares on
the part of any other person, whether or not it has actual or other notice
thereof, save as expressly provided by the laws of the State of Connecticut.
SECTION 2. LOST CERTIFICATES. If a share certificate be lost or destroyed,
another may be issued in its stead upon satisfactory proof of such loss or
destruction and upon the giving of a bond of indemnity satisfactory to the
Corporation, unless this requirement be dispensed with by the President, a Vice
President, the Treasurer, or the Board of Directors, and upon compliance with
such other conditions as the Board of Directors may require.
SECTION 3. TRANSFERS. Shares shall be transferable on the records of the
Corporation by the holder of record thereof, or by his attorney thereunto duly
authorized, upon the surrender and cancellation of a certificate or certificates
for a like number of shares of the same class and of the same series where there
are more than one series in a class, with such proof of the authenticity of the
signature of such holder or of such attorney and such proof of the authority of
such attorney as the Corporation may require.
SECTION 4. REGULATIONS. The Board of Directors may make such regulations as it
may deem expedient concerning the issue, transfer and registration of shares.
SECTION 5. TRANSFER AGENT AND REGISTRAR. The Board of Directors may appoint one
or more transfer agents and registrars, or a transfer agent only, and may
require all share certificates to bear the signature of such a transfer agent,
and, if a registrar shall also have been appointed, the signature of such a
registrar.
SECTION 6. RECORD DATE. The Board of Directors by resolution may fix a date as
the record date for the purpose of determining the shareholders entitled to
notice of and to vote at any meeting of shareholders or any adjournment thereof,
or entitled to receive payment of any dividend or other distribution, or for any
other purpose, such date in any case to be not earlier than the date such action
is taken by the Board of Directors and not more than seventy days, and, in case
of a meeting of shareholders, not less than ten full days, immediately preceding
the date on which
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the particular event requiring such determination of shareholders is to occur.
If no record date is so fixed, the date on which notice of a meeting is mailed
shall be the record date for the determination of shareholders entitled to
notice of and to vote at such meeting and the date on which the resolution of
the Board of Directors declaring such dividend or other distribution is adopted
shall be the record date for the determination of shareholders entitled to
receive payment of such dividend or other distribution. Shareholders actually of
record at a record date shall be the only shareholders entitled to receive
notice of or to vote at the meeting, or receive the dividend or other
distribution, or otherwise participate in respect of the event or transaction,
to which such date relates, except as otherwise provided by statute.
ARTICLE VII.
Miscellaneous.
SECTION 1. SEAL. The seal of the Corporation shall be circular in form and shall
bear the name of the Corporation around the circumference and the figures "1899"
in the center.
SECTION 2. FISCAL YEAR. The fiscal year of the Corporation shall end December
31st in each year, or otherwise, as the Board of Directors may determine.
SECTION 3. INSPECTION OF BOOKS. The Board of Directors shall determine from time
to time whether and, if allowed, when and under what conditions and regulations
the accounts and books of the Corporation (except such as may by statute be
specifically required to be open to inspection), or any of them, shall be open
to the inspection of the shareholders, and the shareholders' rights in this
respect are and shall be restricted and limited accordingly.
SECTION 4. WAIVER OF NOTICE. Whenever any notice of time, place, purpose or any
other matter, including any special notice or form of notice, is required or
permitted to be given to any person by law, the Certificate of Incorporation,
these Bylaws or a resolution of shareholders or directors, a written waiver of
notice signed by the person or persons entitled to such notice, whether before
or after the time stated therein, shall be equivalent to the giving of such
notice. The Secretary shall cause any such waiver to be filed with or entered
upon the records of the Corporation or, in the case of a waiver of notice of a
meeting, the records of the meeting. The attendance of any person at a meeting
without protesting, prior to or at the commencement of the meeting, the lack of
proper notice shall be deemed to be a waiver by him of notice of such meeting.
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SECTION 5. VOTING SHARES OF OTHER CORPORATIONS. Unless otherwise ordered by the
Board of Directors or by the Executive Committee, the President, the Secretary
or the Treasurer shall have full power and authority on behalf of the
Corporation to attend and to act and vote at any meetings of shareholders of any
corporation in which the Corporation may hold shares, and at any such meeting
shall possess and exercise any and all the rights and powers incident to the
ownership of such shares and which as the owner thereof the Corporation might
have possessed and exercised if present; or the President may in his discretion
give a proxy or proxies in the name of the Corporation to any other person or
persons, who may vote said shares and exercise any and all other rights in
regard to it as here accorded to the officers. The Board of Directors by
resolution from time to time may limit or curtail such power.
SECTION 6. CHECKS, DRAFTS AND NOTES. All checks upon any bank account and all
drafts and notes of the Corporation shall be signed in its behalf pursuant to
authorization of the Board of Directors. In any event, such checks, drafts and
notes may be signed by the President, or a Vice President or the Treasurer, and
countersigned by another of said officers, without such authorization, provided
that the same shall be signed and countersigned by separate persons.
SECTION 7. AUDITS. The Board of Directors of the Corporation shall cause an
audit of the books and affairs of the Corporation to be made annually during the
period between the close of each fiscal year and the next annual meeting, such
audit to be made by such firm or individuals, not associated or connected with
the Corporation, as the directors may determine.
ARTICLE VIII.
Amendments.
These Bylaws may be altered, amended, added to or repealed (a) by the
affirmative vote of the holders of a majority of the voting power of shares
entitled to vote thereon or (b) by the affirmative vote of directors holding a
majority of the directorships. Any notice of a meeting of the shareholders or of
the Board of Directors at which these Bylaws are to be altered, amended, added
to or repealed shall include notice of such proposed action.
11
ATTACHMENT 2
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 Fortieth
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...............................................2
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 Annual Transmission Revenue Requirements....................4
1.8 Automatic Generation Control or AGC.........................4
1.9 Bid Price...................................................5
1.10 Commission..................................................5
1.11 Control Area................................................5
1.12 Curtailment.................................................6
1.13 Direct Assignment Facilities................................7
1.14 Dispatch Price..............................................7
1.15 EHV PTF.....................................................8
1.16 Electrical Load.............................................8
1.17 Eligible Customer...........................................9
1.18 Energy.....................................................10
1.19 Energy Entitlement.........................................10
1.20 Entitlement................................................11
1.21 Entity.....................................................11
1.22 Excepted Transaction.......................................12
1.23 Executive Committee........................................12
1.24 Facilities Study...........................................13
1.25 Firm Contract..............................................13
1.26 First Effective Date.......................................13
1.27 Good Utility Practice......................................13
1.28 HQ Contracts...............................................14
1.29 HQ Energy Banking Agreement................................14
1.30 HQ Interconnection.........................................14
1.31 HQ Interconnection Agreement...............................15
1.32 HQ Interconnection Capability Credit.......................15
1.33 HQ Interconnection Transfer Capability.....................16
1.34 HQ Net Interconnection Capability Credit...................17
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1.35 HQ Phase I Energy Contract.................................17
1.36 HQ Phase I Percentage......................................17
1.37 HQ Phase I Transfer Credit.................................18
1.38 HQ Phase II Firm Energy Contract...........................18
1.39 HQ Phase II Gross Transfer Responsibility..................18
1.40 HQ Phase II Net Transfer Responsibility....................19
1.41 HQ Phase II Percentage.....................................19
1.42 HQ Phase II Transfer Credit................................19
1.43 HQ Use Agreement...........................................19
1.44 Installed Capability.......................................20
1.45 Installed Capability Entitlement...........................20
1.46 Installed Capability Responsibility........................21
1.47 Installed System Capability................................21
1.48 Interchange Transactions...................................21
1.49 Internal Point-to-Point Service............................21
1.50 Interruption...............................................21
1.51 ISO........................................................22
1.52 Kilowatt...................................................22
1.53 Load.......................................................22
1.54 Local Network..............................................24
1.56 Lower Voltage PTF..........................................24
1.57 Management Committee.......................................25
1.58 Market Reliability Planning Committee......................25
1.59 Monthly Peak...............................................25
1.60 NEPOOL.....................................................25
1.61 NEPOOL Control Area........................................25
1.62 NEPOOL Installed Capability................................26
1.63 NEPOOL Installed Capability Responsibility.................27
1.64 NEPOOL Objective Capability................................27
1.65 New Unit...................................................27
1.66 Non-Participant............................................27
1.67 Operable Capability........................................28
1.68 Operable Capability Entitlement............................28
1.69 Operable Capability Requirement ...........................29
1.70 Operable System Capability.................................29
1.71 Operating Reserve..........................................29
1.72 Operating Reserve Entitlement..............................29
1.73 Other HQ Energy............................................30
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1.74 Participant................................................30
1.75 Pool-Planned Facility......................................31
1.76 Pool-Planned Unit..........................................31
1.77 Power Year.................................................31
1.78 Prior NEPOOL Agreement.....................................31
1.79 Proxy Unit.................................................31
1.80 PTF........................................................32
1.81 Regional Market Operations Committee.......................32
1.82 Regional Network Service...................................32
1.83 Regional Transmission Operations Committee.................32
1.84 Regional Transmission Planning Committee...................32
1.85 Related Person.............................................33
1.86 Scheduled Dispatch Period..................................33
1.87 Second Effective Date......................................33
1.88 Service Agreement..........................................34
1.89 Summer Capability..........................................34
1.90 Summer Period..............................................34
1.91 System Contract............................................34
1.92 System Impact Study........................................35
1.93 System Operator............................................35
1.94 Target Availability Rate...................................36
1.95 Tariff.....................................................36
1.96 Third Effective Date.......................................36
1.97 Through or Out Service.....................................36
1.99 Transmission Customer......................................37
1.100 Transmission Provider......................................37
1.101 Unit Contract..............................................37
1.102 Voting Share...............................................38
1.103 Winter Capability..........................................38
1.104 Winter Period..............................................38
1.105 10-Minute Spinning Reserve.................................38
1.106 10-Minute Non-Spinning Reserve.............................39
1.107 30-Minute Operating Reserve................................40
1.108 33rd Amendment.............................................41
1.109 Modification of Certain Definitions When a Participant
Purchases a Portion of Its Requirements from Another
Participant Pursuant to Firm Contract......................42
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SECTION 2 - PURPOSE; EFFECTIVE DATES.........................................45
2.1 Purpose....................................................45
2.2 Effective Dates; Transitional Provisions...................45
SECTION 3 - MEMBERSHIP.......................................................46
3.1 Membership.................................................46
3.2 Operations Outside the Control Area........................48
3.3 Lack of Place of Business in New England...................48
3.4 Obligation for Deferred Expenses...........................49
3.5 Financial Security.........................................49
SECTION 4 - STATUS OF PARTICIPANTS...........................................50
4.1 Treatment of Certain Entities as Single Participant........50
4.2 Participants to Retain Separate Identities.................51
SECTION 5 - NEPOOL OBJECTIVES AND COOPERATION BY
PARTICIPANTS...............................................52
5.1 NEPOOL Objectives..........................................52
5.2 Cooperation by Participants................................53
PART TWO - GOVERNANCE........................................................54
SECTION 6 - MANAGEMENT COMMITTEE.............................................54
6.1 Membership.................................................54
6.2 Term of Members............................................55
6.3 Votes......................................................55
6.4 Number of Votes Necessary for Action.......................64
6.5 Proxies....................................................65
6.6 Alternates.................................................65
6.7 Officers...................................................65
6.8 Meetings...................................................66
6.9 Notice of Meetings.........................................66
6.10 Adoption of Budgets........................................66
6.11 Adoption of Bylaws.........................................67
6.12 Establishing Reliability Standards.........................67
6.13 Appointment and Compensation of NEPOOL Personnel...........68
6.14 Duties and Authority.......................................68
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6.15 Attendance of Members of Management Committee at Other
Committee Meetings.........................................74
SECTION 7 - EXECUTIVE COMMITTEE..............................................74
7.1 Organization...............................................74
7.2 Membership.................................................75
7.3 Term of Members............................................77
7.4 Alternates.................................................78
7.5 Votes......................................................78
7.6 Number of Votes Necessary for Action.......................79
7.7 Officers...................................................79
7.8 Meetings...................................................80
7.9 Notice of Meetings.........................................80
7.10 Notice to Members of Management Committee of Actions by
Executive Committee........................................81
7.11 Appeal of Actions to Management Committee..................81
SECTION 8 - MARKET RELIABILITY PLANNING COMMITTEE............................82
8.1 Organization...............................................82
8.2 Membership.................................................82
8.3 Term of Members............................................84
8.4 Voting.....................................................85
8.5 Alternates.................................................86
8.6 Officers...................................................87
8.7 Meetings...................................................87
8.8 Notice of Meetings.........................................87
8.9 Notice to Members of Management Committee..................88
8.10 Appeal of Actions to Management Committee..................88
8.11 Responsibilities...........................................89
8.12 Functional Planning Committees.............................91
8.13 Appointment of Task Forces.................................92
8.14 Consultants, Computer Time and Expenses....................93
8.15 Further Powers and Duties..................................93
8.16 Reports to Management Committee............................93
8.17 Joint Meetings With Regional Transmission Planning
Committee..................................................94
SECTION 9 - REGIONAL TRANSMISSION PLANNING COMMITTEE.........................94
9.1 Organization...............................................94
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9.2 Membership.................................................95
9.3 Term of Members............................................97
9.4 Voting.....................................................97
9.5 Alternates.................................................99
9.6 Officers...................................................99
9.7 Meetings...................................................99
9.8 Notice of Meetings........................................100
9.9 Notice to Members of Management Committee.................100
9.10 Appeal of Actions to Management Committee.................101
9.11 Responsibilities..........................................101
9.12 Functional Planning Committees............................103
9.13 Appointment of Task Forces................................105
9.14 Consultants, Computer Time and Expenses...................105
9.15 Further Powers and Duties.................................105
9.16 Reports to Management Committee...........................106
9.17 Joint Meetings With Market Reliability Planning Committee.106
SECTION 10 - REGIONAL MARKET OPERATIONS COMMITTEE...........................106
10.1 Organization..............................................106
10.2 Membership................................................107
10.3 Terms of Members..........................................109
10.4 Voting....................................................109
10.5 Alternates................................................111
10.6 Officers..................................................111
10.7 Meetings..................................................111
10.8 Notice of Meetings........................................112
10.9 Notice to Members of Management Committee.................112
10.10 Appeal of Actions to Management Committee.................113
10.11 Appointment of Task Forces................................113
10.12 Consultants, Computer Time and Expenses...................114
10.13 Responsibilities..........................................114
10.14 Further Powers and Duties.................................117
10.15 Development of Rules Relating to Non-Participant Supply
and Demand-side Resources.................................117
10.16 Joint Meetings with Regional Transmission Operations
Committee.................................................118
SECTION 11 - REGIONAL TRANSMISSION OPERATIONS COMMITTEE.....................118
11.1 Organization..............................................118
vi
<PAGE>
PAGE
----
11.2 Membership................................................118
11.3 Terms of Members..........................................121
11.4 Voting....................................................121
11.5 Alternates................................................123
11.6 Officers..................................................123
11.7 Meetings..................................................123
11.8 Notice of Meetings........................................124
11.9 Notice to Members of Management Committee.................124
11.10 Appeal of Actions to Management Committee.................125
11.11 Appointment of Task Forces................................125
11.12 Consultants, Computer Time and Expenses...................126
11.13 Responsibilities..........................................126
11.14 Further Powers and Duties.................................127
11.15 Joint Meetings with Regional Market Operations Committee..128
PART THREE - MARKET PROVISIONS..............................................128
SECTION 12 - INSTALLED CAPABILITY AND OPERABLE CAPABILITY
OBLIGATIONS AND PAYMENTS.................................128
12.1 Obligations to Provide Installed Capability and Operable
Capability................................................128
12.2 Computation of Installed Capability Responsibilities......129
12.3 Computation of Operable Capability Requirements...........147
12.4 Bids to Furnish Installed Capability or Operable
Capability................................................148
12.5 Consequences of Deficiencies in Installed Capability
Responsibility............................................148
12.6 Consequences of Deficiencies in Operable Capability
Requirements..............................................151
12.7 Payments to Participants Furnishing Installed Capability
and Operable Capability...................................153
SECTION 13 - OPERATION, GENERATION, OTHER RESOURCES,
AND INTERRUPTIBLE CONTRACTS..............................155
13.1 Maintenance and Operation in Accordance with Good Utility
Practice..................................................155
13.2 Central Dispatch..........................................155
13.3 Maintenance and Repair....................................156
13.4 Objectives of Day-to-Day System Operation.................157
13.5 Satellite Membership......................................158
vii
<PAGE>
PAGE
----
SECTION 14 - INTERCHANGE TRANSACTIONS.......................................158
14.1 Obligation for Energy, Operating Reserve and Automatic
Generation Control........................................158
14.2 Obligation to Bid or Schedule, and Right to Receive
Energy, Operating Reserve and Automatic Generation
Control...................................................162
14.3 Amount of Energy, Operating Reserve and Automatic
Generation Control Received or Furnished..................168
14.4 Payments by Participants Receiving Energy Service,
Operating Reserve and Automatic Generation Control........171
14.5 Payments to Participants Furnishing Energy Service,
Operating Reserve, and Automatic Generation Control.......173
14.6 Energy Transactions with Non-Participants.................176
14.7 Participant Purchases Pursuant to Firm Contracts and
System Contracts..........................................178
14.8 Determination of Energy Clearing Price....................180
14.9 Determination of Operating Reserve Selling Price and
Clearing Price............................................181
14.10 Determination of AGC Clearing Price.......................185
14.11 Funds to or from which Payments are to be Made............186
14.12 Development of Rules Relating to Nuclear and Hydroelectric
Generating Facilities, Limited-Fuel Generating Facilities,
and Interruptible Loads...................................196
14.13 Dispatch and Billing Rules During Energy Shortages........197
14.14 Congestion Uplift.........................................197
14.15 Additional Uplift Charges. ..............................202
PART FOUR - TRANSMISSION PROVISIONS.........................................203
SECTION 15 - OPERATION OF TRANSMISSION FACILITIES...........................203
15.1 Definition of PTF.........................................203
15.2 Maintenance and Operation in Accordance with Good Utility
Practice..................................................207
15.3 Central Dispatch..........................................207
15.4 Maintenance and Repair....................................207
15.5 Additions to or Upgrades of PTF...........................208
SECTION 16 - SERVICE UNDER TARIFF...........................................211
16.1 Effect of Tariff..........................................211
viii
<PAGE>
PAGE
----
16.2 Obligation to Provide Regional Service....................211
16.3 Obligation to Provide Local Network Service...............212
16.4 Transmission Service Availability.........................215
16.5 Transmission Information..................................215
16.6 Distribution of Transmission Revenues.....................216
16.7 Changes to Tariff.........................................219
SECTION 17 - POOL-PLANNED UNIT SERVICE......................................220
17.1 Effective Period..........................................220
17.2 Obligation to Provide Service.............................220
17.3 Rules for Determination of Facilities Covered by Particular
Transactions..............................................221
17.4 Payments for Uses of EHV PTF During the Transition Period.223
17.5 Payments for Uses of Lower Voltage PTF....................228
17.6 Use of Other Transmission Facilities by Participants......228
17.7 Limits on Individual Transmission Charges.................229
PART FIVE - GENERAL.........................................................230
SECTION 18 - GENERATION AND TRANSMISSION FACILITIES.........................230
18.1 Designation of Pool-Planned Facilities....................230
18.2 Construction of Facilities................................231
18.3 Protective Devices for Transmission Facilities and Automatic
Generation Control Equipment..............................231
18.4 Review of Participant's Proposed Plans....................232
18.5 Participant to Avoid Adverse Effect.......................233
SECTION 19 - EXPENSES.......................................................235
19.1 Annual Fee................................................235
19.2 NEPOOL Expenses...........................................235
SECTION 20 - INDEPENDENT SYSTEM OPERATOR....................................236
SECTION 21 - MISCELLANEOUS PROVISIONS.......................................242
21.1 Alternative Dispute Resolution............................242
21.2 Payment of Pool Charges; Termination of Status as
Participant...............................................255
21.3 Assignment................................................259
21.4 Force Majeure.............................................260
ix
<PAGE>
PAGE
----
21.5 Waiver of Defaults........................................261
21.6 Other Contracts...........................................261
21.7 Liability and Insurance...................................262
21.8 Records and Information...................................263
21.9 Consistency with NPCC and NERC Standards..................264
21.10 Construction..............................................264
21.11 Amendment.................................................264
21.12 Termination...............................................267
21.13 Notices to Participants...................................267
21.14 Severability and Renegotiation............................269
21.15 No Third-Party Beneficiaries..............................270
21.16 Counterparts..............................................270
x
<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
July 20, 1998.
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 1.109):
<PAGE>
-2-
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 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
<PAGE>
-3-
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.
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
<PAGE>
-4-
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.
1.6 Agreement is this restated contract and attachments, including the
---------
Tariff, as amended and restated from time to time.
1.7 Annual Transmission Revenue Requirements of a Participant's PTF or of
------------------------------------------
all Participants' PTF for purposes of this Agreement are the amounts
determined in accordance with Attachment F to the Tariff.
1.8 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.
<PAGE>
-5-
1.9 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 Capability, Energy,
Operating Reserve and/or AGC pursuant to a Firm Contract or System
Contract in accordance with Section 14.7.
1.10 Commission is the Federal Energy Regulatory Commission.
----------
1.11 Control Area is an electric power system or combination of electric
-------------
power systems to which a common automatic generation control scheme is
applied in order to:
<PAGE>
-6-
(l) match, at all times, the power output of the
generators within the electric power system(s) and
capacity and energy purchased from entities outside
the electric power system(s), with the load within
the electric power system(s);
(2) maintain scheduled interchange with other Control
Areas, within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power
system(s) within reasonable limits in accordance with
Good Utility Practice and the criteria of the
applicable regional reliability council or the North
American Electric Reliability Council; and
(4) provide sufficient generating capacity to maintain
operating reserves in accordance with Good Utility
Practice.
1.12 Curtailment is a reduction in firm or non-firm transmission service in
-----------
response to a transmission capacity shortage as a result of system
reliability conditions.
<PAGE>
-7-
1.13 Direct Assignment Facilities are facilities or portions of facilities
------------------------------
that are Non- PTF and are constructed for the sole use/benefit of a
particular Transmission Customer requesting service under the Tariff or
Generator Owner requesting an interconnection. Direct Assignment
Facilities shall be specified in a separate agreement with the
Transmission Provider whose transmission system is to be modified to
include and/or interconnect with said Facilities, shall be subject to
applicable Commission requirements and shall be paid for by the
Transmission Customer or a Generator Owner in accordance with the
separate agreement and not under the Tariff.
1.14 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.
<PAGE>
-8-
1.15 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.
1.16 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, or (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
----
<PAGE>
-9-
(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.
The Electrical Load of a Participant may be calculated in any
reasonable manner which substantially complies with this definition.
1.17 Eligible Customer is the following: (i) Any Participant that is
------------------
engaged, or proposes to engage, in the wholesale or retail electric
power business is an Eligible Customer under the Tariff. (ii) Any
electric utility (including any power marketer), Federal power
marketing agency, or any other entity generating electric energy for
sale or for resale is an Eligible Customer under the Tariff. Electric
energy sold or produced by such entity may be electric energy produced
in the United States, Canada or Mexico. However, with respect to
transmission service that the Commission is prohibited from ordering by
Section 212(h) of the Federal Power Act, such entity is eligible only
if the service is provided pursuant to a state requirement that the
Transmission Provider with which that entity is
<PAGE>
-10-
directly interconnected offer the unbundled transmission service, or
pursuant to a voluntary offer of such service by the Transmission
Provider with which that entity is directly interconnected. (iii) Any
end user taking or eligible to take unbundled transmission service
pursuant to a state requirement that the Transmission Provider with
which that end user is directly interconnected offer the transmission
service, or pursuant to a voluntary offer of such service by the
Transmission Provider with which that end user is directly
interconnected, is an Eligible Customer under the Tariff.
1.18 Energy is power produced in the form of electricity, measured in
------
kilowatthours or megawatthours.
1.19 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
<PAGE>
-11-
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.
1.20 Entitlement is an Installed Capability Entitlement, Operable Capability
-----------
Entitlement, Energy Entitlement, Operating Reserve Entitlement, or AGC
Entitlement. When used in the plural form, it may be any or all such
Entitlements or combinations thereof, as the context requires.
1.21 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
<PAGE>
-12-
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 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.
1.22 Excepted Transaction is a transaction specified in Section 25 of the
--------------------
Tariff for the applicable period specified in that Section.
1.23 Executive Committee is the committee established pursuant to Section 7.
-------------------
<PAGE>
-13-
1.24 Facilities Study is an engineering study conducted pursuant to this
-----------------
Agreement or the Tariff by the System Operator and/or one or more
affected Participants to determine the required modifications to the
NEPOOL Transmission System, including the cost and scheduled completion
date for such modifications, that will be required to provide a
requested transmission service or interconnection.
1.25 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.
1.26 First Effective Date is March 1, 1997.
--------------------
1.27 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
<PAGE>
-14-
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.
1.28 HQ Contracts are the HQ Interconnection Agreement, the HQ Phase I
-------------
Energy Contract, and the HQ Phase II Firm Energy Contract.
1.29 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.
1.30 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
<PAGE>
-15-
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.
1.31 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.
1.32 HQ Interconnection Capability Credit of a Participant for a month
---------------------------------------
during the Base Term (as defined in Section 1.38) 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 HQ Phase II
<PAGE>
-16-
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.
1.33 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 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
<PAGE>
-17-
followed by it in its determination of the Winter Capability and Summer
Capability of generating units.
1.34 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.
1.35 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.
1.36 HQ Phase I Percentage is the percentage of the total HQ Interconnection
---------------------
Transfer Capability represented by the HQ Phase I Transfer Capability.
<PAGE>
-18-
1.37 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.
1.38 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.
1.39 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 1.38) 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>
-19-
1.40 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.
1.41 HQ Phase II Percentage is the percentage of the total HQ
--------------------------
Interconnection Transfer Capability represented by the HQ Phase II
Transfer Capability.
1.42 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.
1.43 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>
-20-
1.44 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.
1.45 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.
<PAGE>
-21-
1.46 Installed Capability Responsibility * of a Participant for any month is
-----------------------------------
the number of Kilowatts determined in accordance with Section 12.2.
1.47 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.
----
1.48 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.
1.49 Internal Point-to-Point Service is the transmission service by that
---------------------------------
name provided pursuant to Section 19 of the Tariff.
1.50 Interruption is a reduction in non-firm transmission service due to
------------
economic reasons pursuant to Section 28.7 of the Tariff, other than a
reduction which results from a failure to dispatch a generating
resource, including a contract, used
<PAGE>
-22-
in a transaction requiring In Service or Through or Out Service which
is out of merit order.
1.51 ISO is the Independent System Operator which is responsible 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.
1.52 Kilowatt is a kilowatthour per hour.
--------
1.53 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
(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
----
<PAGE>
-23-
(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.
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
<PAGE>
-24-
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.
1.54 Local Network is the transmission facilities constituting a local
--------------
network identified on Attachment E to the Tariff, and any other local
network or change in the designation of a Local Network as a Local
Network which the Management Committee may designate or approve from
time to time. The Management Committee may not unreasonably withhold
approval of a request by a Participant that it effect such a change or
designation.
1.55 Local Network Service is the service provided, under a separate tariff
---------------------
or contract, by a Participant that is a Transmission Provider to
another Participant, or other entity connected to the Transmission
Provider's Local Network to permit the other Participant or entity to
efficiently and economically utilize its resources to serve its load.
1.56 Lower Voltage PTF are all PTF facilities other than EHV PTF.
-----------------
<PAGE>
-25-
1.57 Management Committee is the committee established pursuant to Section
--------------------
6.
1.58 Market Reliability Planning Committee is the committee established
----------------------------------------
pursuant to Section 8.
1.59 Monthly Peak of a Participant for a month is the maximum Adjusted Load
------------
of the Participant during any hour in the month.
1.60 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.
1.61 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:
<PAGE>
-26-
(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;
(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.
1.62 NEPOOL Installed Capability at any particular time is the sum of the
-----------------------------
Installed System Capabilities of all Participants at such time.
<PAGE>
-27-
1.63 NEPOOL Installed Capability Responsibility for any month is the sum of
-------------------------------------------
the Installed Capability Responsibilities of all Participants during
that month.
1.64 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.
1.65 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.
1.66 Non-Participant is any entity which is not a Participant.
---------------
<PAGE>
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1.67 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.
1.68 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
<PAGE>
-29-
generating unit or units, and may be transferred separately from the
related Installed Capability Entitlement, Energy Entitlement, Operating
Reserve Entitlements, or AGC Entitlement.
1.69 Operable Capability Requirement of a Participant for any hour is the
---------------------------------
number of Kilowatts determined in accordance with Section 12.3.
1.70 Operable System Capability of a Participant in any hour is the sum of
----------------------------
such Participant's Operable Capability Entitlements.
1.71 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.
1.72 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
-------
<PAGE>
-30-
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.
1.73 Other HQ Energy is Energy purchased under the HQ Phase I Energy
-----------------
Contract which is classified as "Other Energy" under that contract.
1.74 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.
<PAGE>
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1.75 Pool-Planned Facility is a generation or transmission facility
-----------------------
designated as "pool-planned" pursuant to Section 18.1.
1.76 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).
1.77 Power Year is (i) the period of twelve (12) months commencing on
-----------
November 1, in each year to and including 1997; (ii) the period of
seven (7) months commencing on November 1, 1998; and (iii) the period
of twelve (12) months commencing on June 1, 1999 and each June 1
thereafter.
1.78 Prior NEPOOL Agreement is the NEPOOL Agreement as in effect on December
----------------------
1, 1996.
1.79 Proxy Unit is a hypothetical electric generating unit which possesses a
----------
Winter Capability, equivalent forced outage rate, annual maintenance
outage
<PAGE>
-32-
requirement, and seasonal derating determined in accordance with
Section 12.2(a)(2).
1.80 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.
1.81 Regional Market Operations Committee is the committee established
---------------------------------------
pursuant to Section 10.
1.82 Regional Network Service is the transmission service by that name
--------------------------
provided pursuant to Section 14 of the Tariff.
1.83 Regional Transmission Operations Committee is the committee established
------------------------------------------
pursuant to Section 11.
<PAGE>
-33-
1.84 Regional Transmission Planning Committee is the committee established
------------------------------------------
pursuant to Section 9.
1.85 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.
1.86 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>
-34-
1.87 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 such date
as the Commission may fix on its own or pursuant to a request of the
Management Committee.
1.88 Service Agreement is the initial agreement and any amendments or
------------------
supplements thereto entered into by the Transmission Customer and the
System Operator for service under the Tariff.
1.89 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).
1.90 Summer Period in each Power Year is the four-month period from June
--------------
through September.
<PAGE>
-35-
1.91 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.
1.92 System Impact Study is an assessment pursuant to Part V, VI or VII of
-------------------
the Tariff of (i) the adequacy of the NEPOOL Transmission System to
accommodate a request for the interconnection of a new or materially
changed generating unit or a new or materially changed interconnection
to another Control Area or new Regional Network Service, Internal
Point-to-Point Service or Through or Out Service, and (ii) whether any
additional costs may be required to be incurred in order to provide the
interconnection or transmission service.
1.93 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 is the ISO.
<PAGE>
-36-
1.94 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.
1.95 Tariff is the NEPOOL Open Access Transmission Tariff set out in
------
Attachment B to the Agreement, as modified and amended from time to
time.
1.96 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 the
Commission may fix on its own or pursuant to a request by the
Management Committee.
1.97 Through or Out Service is the transmission service by that name
------------------------
provided pursuant to Section 18 of the Tariff.
1.98 Transition Period is the five-year period commencing on March 1, 1997.
-----------------
<PAGE>
-37-
1.99 Transmission Customer is any Eligible Customer that (i) is a
-----------------------
Participant which is not required to sign a Service Agreement with
respect to a service to be furnished to it in accordance with Section
48 of the Tariff or (ii) executes, on its own behalf or through its
Designated Agent, a Service Agreement, or (iii) requests in writing, on
its own behalf or through its Designated Agent, that NEPOOL file with
the Commission a proposed unexecuted Service Agreement in order that
the Eligible Customer may receive transmission service under the
Tariff.
1.100 Transmission Provider is the Participants, collectively, which own PTF
---------------------
and are in the business of providing transmission service or provide
service under a local open access transmission tariff, or in the case
of a state or municipal or cooperatively-owned Participant, would be
required to do so if requested pursuant to the reciprocity requirements
specified in the Tariff, or an individual such Participant, whichever
is appropriate.
1.101 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)
<PAGE>
-38-
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.
1.102 Voting Share has the meaning specified in Section 6.3.
------------
1.103 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).
1.104 Winter Period in each Power Year is (i) the seven-month period from
--------------
November through May and the month of October for the Power Year
commencing on November 1 in 1997 or a prior Power Year; (ii) the
seven-month period from November through May for the Power Year
commencing on November 1, 1998; and (iii) the eight-month period from
October through May for the Power Year commencing on June 1, 1999 and
each June 1 thereafter.
<PAGE>
-39-
1.105 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>
-40-
1.106 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>
-41-
1.107 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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1.108 33rd Amendment is the Thirty-Third Agreement Amending New England Power
--------------
Pool Agreement dated as of December 1, 1996.
1.109 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>
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(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>
-44-
(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
---
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 that are not defined above, or in the
sections in which such terms are used, shall have the meanings
customarily attributed to such terms in the electric power industry in
New England.
<PAGE>
-45-
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 became effective on
the First Effective Date and replaced 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 provisions of Sections 12.1(a),
12.2, 12.4 (as to Installed Capability only), 12.5 and 12.7(a) of this
Agreement became effective
<PAGE>
-46-
on April 1, 1998 and replaced 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.
SECTION 3
MEMBERSHIP
----------
3.1 Membership. Those Entities which are Participants in NEPOOL on the
----------
First Effective Date shall continue to be Participants.
<PAGE>
-47-
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
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.
<PAGE>
-48-
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.
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
<PAGE>
-49-
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 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
<PAGE>
-50-
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 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.
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.
<PAGE>
-51-
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 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.
<PAGE>
-52-
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;
(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;
<PAGE>
-53-
(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
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
<PAGE>
-54-
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.
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:
V = .15833 (P (E (C (X (M (R
-- + .15833 -- + .15833 -- + .15833 -- + .15833 -- + .15833 -- +
P1) E1) C1) X1) M1) R1)
.05 (Y
--
Y1)
<PAGE>
-56-
in which
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>
-57-
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
--
<PAGE>
-58-
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 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
<PAGE>
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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;
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 the
month;
<PAGE>
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provided, however, that a Participant and its Related Persons may not have
- -------- -------
aggregate Voting Shares exceeding 18% 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 18% 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 on a per capita
basis to those Participants which have a current Voting Share of less than 18%
and which receive a credit in the computation of their Voting Shares under at
least one of the P, E, C, X, M or R components of the Voting Shares formula as
specified above.
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
<PAGE>
-61-
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.
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:
<PAGE>
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(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 Vermont Yankee Nuclear Power Corporation or a
similar corporation, or as a general or limited partner in
Ocean State Power or a similar 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
<PAGE>
-63-
(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.
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;
<PAGE>
-64-
(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
(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 six 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
<PAGE>
-65-
defeat any proposed action. In determining whether the negative vote
total specified above has been reached, the 18% limitation specified in
Section 6.3 on the aggregate Voting Shares of any Participant and its
Related Persons shall be applicable.
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
<PAGE>
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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 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.
<PAGE>
-67-
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. The Management Committee may
modify any NEPOOL budget from time to time after its adoption.
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 Committee 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
<PAGE>
-68-
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.
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
<PAGE>
-69-
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
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
<PAGE>
-70-
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.
(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
<PAGE>
-71-
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 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
<PAGE>
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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 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
<PAGE>
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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
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.
<PAGE>
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(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 powers and
perform the duties of the Management Committee. The Executive Committee
shall not have any of the powers or
<PAGE>
-75-
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:
----------
the ISO shall have the right to appoint a non-voting member of the
Committee; each Participant whose Voting Share equals or exceeds 1% 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 1% 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 utilities;
<PAGE>
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(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>
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(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 Participants which appointed
them or until such Participant or Participants shall lose their status
as Participants or otherwise lose
<PAGE>
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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 divide the member's
<PAGE>
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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
<PAGE>
-80-
need not be a 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
<PAGE>
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of the meeting. The notice shall specify the principal subject matte
expected to be acted upon at the meeting.
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>
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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: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting Share
equals or exceeds 1% 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 1% 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>
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(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>
-84-
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, 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
<PAGE>
-85-
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 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
<PAGE>
-86-
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.
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.
<PAGE>
-87-
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.
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.
<PAGE>
-88-
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 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
<PAGE>
-89-
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:
(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;
<PAGE>
-90-
(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;
(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
<PAGE>
-91-
(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
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.
<PAGE>
-92-
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
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.
<PAGE>
-93-
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.
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 conside
appropriate. Market Reliability
<PAGE>
-94-
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.
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.
<PAGE>
-95-
9.2 Membership. The Regional Transmission Planning Committee shall be
----------
constituted as follows:
(a) the ISO shall have the right to appoint a non-voting
member of the Committee;
(b) Transmission Service Provider Members: each
Participant which provides transmission service
through NEPOOL under the Tariff as a Transmissio
Provider (a "Service Provider") and whose Voting
Share equals or exceeds 1% of the aggregate Voting
Shares of all Participants shall have the right to
appoint a voting member of the Committee (a
"Transmission Service Provider Member") and the
remaining Service Providers aggregated together shall
have the right to appoint one voting Transmission
Service Provider Member.
(c) Non-Transmission Service Provider Members: each
Participant which is not a Service Provider and whose
Voting Shares equals or exceeds 1% of the aggregate
Voting Shares of all Participants shall
<PAGE>
-96-
have the right to appoint a voting member of the
Committee (a "Non-Transmission Service Provider
Member") and the remaining Participants which are not
Service Providers whose Voting Shares are less than
1% of the aggregate Voting Shares of all Participants
shall be divided into the following four groups, with
each having the right to appoint one voting
Non-Transmission Service Provider Member of the
Committee:
(i) One group consisting of the remaining
Participants which are municipally-owned and
cooperatively-owned utilities;
(ii) 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;
<PAGE>
-97-
(iii) 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; and
(iv) 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 three groups.
Notwithstanding the foregoing, any such Participant may elect
to join a different group under (c) 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
<PAGE>
-98-
Participant which is its Related Person and shall not be
assigned to any of the four 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 shal
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 or group of Participants by giving written notice of such
appointment or replacement to the Secretary of theRegional Transmission
Planning Committee.
9.4 Voting. Each Transmission Service Provider Member (as defined in
------
Section 9.2) of the Regional Transmission Planning Committee shall have
the number of votes determined by the following formula:
X = 50 in which:
--
Y
<PAGE>
-99-
X is the number of votes to which the
member is entitled, and
Y is the number of Transmission
Service Provider Members at the
time.
Each Non-Transmission Service Provider Member (as
defined in Section 9.2) shall have the number of
votes determined by the following formula:
A = 50 in which:
--
B
A is the number of votes to which the
\
member is entitled, and
B is the number of Non-Transmission
Service Provider Members at the
time.
<PAGE>
-100-
A member's vote 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.
The voting member appointed by a group may divide the
member's votes 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 different positions of the members of the
group.
The adoption of actions by the Regional Transmission
Planning Committee shall require affirmative votes by
voting members having in the aggregate 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. Voting members having a
majority of
<PAGE>
-101-
the votes to which all members are entitled at any
time shall constitute a quorum.
When the number of votes on any action is greater
than or equal to 50% but less than 60% of the total
votes, then the non-voting member of the Committee
that is appointed by the ISO shall have the right to
cast a vote and a positive vote by the ISO shall
cause an action to pass.
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
<PAGE>
-102-
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.
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
<PAGE>
-103-
meeting whenever the meeting is not held in accordance with the
schedule adopted by the Committee.
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
<PAGE>
-104-
Committee, the delivery of a notice of appeal as aforesaid shall
suspend the action appealed from.
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;
<PAGE>
-105-
(d) following appropriate studies, recommending to the
Management Committee proposed reliability standards
for the bulk power system of NEPOOL;
(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
<PAGE>
-106-
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 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
<PAGE>
-107-
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.
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.
<PAGE>
-108-
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.
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.
<PAGE>
-109-
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.
10.2 Membership. The Regional Market Operations Committee shall be
----------
constituted as follows: the ISO shall have the right to appoint a
non-voting member of the Committee; each Participant whose Voting Share
equals or exceeds 1% 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 1% 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 Regional Market Operations Committee:
(a) One group consisting of the remaining Participants
which are municipally-owned and cooperatively-owned
traditional utilities;
<PAGE>
-110-
(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>
-111-
(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 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.
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
<PAGE>
-112-
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 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 of the Regional Market
Operations Committee both participates in the wholesale bulk power
market and owns PTF, the member appointed by the Participant shall 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.
<PAGE>
-113-
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 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.
<PAGE>
-114-
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 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.
<PAGE>
-115-
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 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
<PAGE>
-116-
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.
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.
<PAGE>
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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) 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;
(b) 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, and (ii) adopting and implementing
uniform rules or procedures, until the Second
Effective Date, fordetermining 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
<PAGE>
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Outage Service shall be the unit's Reserve Capability
or its Temporary Reserve Capability;
(c) 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;
(d) 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;
(e) determining as appropriate from time to time the
current Annual Peak, Adjusted Annual Peak, Monthly
Peak, Adjusted Monthly Peak, Installed Capability
Responsibility, Operable Capability
<PAGE>
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Requirements, and obligations for Energy, Operating
Reserve and AGC of each Participant;
(f) 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;
(g) 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
(h) calculating and equitably apportioning losses
incurred in connection with Interchange Transactions.
<PAGE>
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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 and
---------
Non- Participants with 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
<PAGE>
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meetings, and to conduct studies and exercise its responsibilities,
jointly with the Regional Transmission Operations Committee to the
extent appropriate.
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:
(a) the ISO shall have the right to appoint a
non-voting member of the Committee;
(b) Transmission Service Provider Members: each
Participant which is a Service Provider (as
defined in Section 9.2) and whose Voting
Share equals or exceeds 1% of the aggregate
<PAGE>
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Voting Shares of all Participants shall have
the right to appoint a voting member of the
Committee (a "Transmission Service Provider
Member") and the remaining Service Providers
aggregated together shall have the right to
appoint one voting Transmission Service
Provider Member.
(c) Non-Transmission Service Provider Members:
each Participant which is not a Service
Provider and whose Voting Shares equals or
exceeds 1% of the aggregate Voting Shares of
all Participants shall have the right to
appoint a voting member of the Committee (a
"Non-Transmission Service Provider Member")
and the remaining Participants which are not
Service Providers which own PTF whose Voting
Shares are less than 1% of the aggregate
Voting Shares of all Participants shall be
divided into the following four groups, with
each having the right to appoint one voting
Non-Transmission Service Provider Member of
the Committee:
<PAGE>
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(i) One group consisting of the
remaining Participants which are
municipally-owned and cooperatively-
owned utilities;
(ii) 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;
(iii) 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; and
<PAGE>
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(iv) 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 three groups.
Notwithstanding the foregoing, any such Participant
may elect to join a different group under (c) 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 four 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
<PAGE>
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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.
11.4 Voting. Each Transmission Service Provider Member (as defined in
------
Section 11.2) of the Regional Transmission Operations Committee shall
have the number of votes determined by the following formula:
X = 50 in which:
--
Y
X is the number of votes to which the
member is entitled, and
Y is the number of Transmission
Service Provider Members at the
time.
<PAGE>
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Each Non-Transmission Service Provider Member (as
defined in Section 11.2) shall have the number of
votes determined by the following formula:
A = 50 in which:
--
B
A is the number of votes to which th
member is entitled, and
B is the number of Non-Transmission
Service Provider Members at the
time.
A member's vote 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.
<PAGE>
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The voting member appointed by a group may divide the
member's votes 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 different positions of the members of the
group.
The adoption of actions by the Regional Transmission
Operations Committee shall require affirmative votes
by voting members having in the aggregate 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. Voting members having a
majority of the votes to which all members are
entitled at any time shall constitute a quorum.
When the number of votes on any action is greater
than or equal to 50% but less than 60% of the total
votes, then the non-voting member of the Committee
that is appointed by the ISO shall have the right to
cast a vote and a positive vote by the ISO shall
cause an action to pass.
<PAGE>
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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.
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
<PAGE>
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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 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
<PAGE>
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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.
11.11 Appointment of Task Forces. The Regional Transmission Operations
--------------------------
Committee shall have the authority, within its budget or with the
approval of the
<PAGE>
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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) 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;
<PAGE>
-132-
(b) coordinating studies of, and providing information to
Participants on, maintenance schedules for the supply
and demand-side resources and transmission facilities
of the Participants;
(c) 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; and
(d) establishing or approving appropriate billing
procedures for transmission service pursuant to this
Agreement and 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.
<PAGE>
-133-
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.
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.
<PAGE>
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(b) Each Participant shall have Operable System Capability in each
hour at least sufficient to satisfy its Operable Capability
Requirement for such hour.
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)
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.
<PAGE>
-135-
P is the value of the Participant's fraction
for the month as determined in accordance
with the following formula:
P = Fp/F, wherein:
Fp is the Participant's Adjusted
Monthly Peak for the month less any
Kilowatts received by such
Participant pursuant to a contract
of a type that traditionally has
been treated by NEPOOL as a firm
contract for the purposes of this
Section prior to January 1, 1999,
but which does not constitute a Firm
Contract as defined in this
Agreement.
F is the aggregate for the month of
the Adjusted Monthly Peaks for all
Participants less any Kilowatts
received by any Participant pursuant
to a contract of a type that
traditionally has been treated by
NEPOOL as a firm contract for the
purposes of this Section prior to
January 1, 1999, but which
<PAGE>
-136-
does not constitute a Firm Contract
as defined in this Agreement.
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 New
Unit
<PAGE>
-137-
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).
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
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
<PAGE>
-138-
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; provided, however, that
for the purpose of determining the Four Year
Target Availability Rate (i) for months
included within the Power Year which
commences June 1, 1999, the determination
shall be made for the months of June through
October on the basis of the calendar years
1995 through 1998, and shall be made for the
months of November through May on the basis
of the calendar years 1996 through 1999, and
(ii) for months
<PAGE>
-139-
included within the Power Year which
commences June 1, 2000, the determination
shall be made on the basis of the calendar
years 1996 through 1999. 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).
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
<PAGE>
-140-
months which comprise the period of four
consecutive calendar years ending within the
Power Year which includes such month;
provided, however, that for the purpose of
determining the Four Year Actual
Availability Rate (i) for months included
within the Power Year which commences June
1, 1999, the determination shall be made for
the months of June through October on the
basis of the calendar years 1995 through
1998, and shall be made for the months of
November through May on the basis of the
calendar years 1996 through 1999, and (ii)
for months included within the Power Year
which commences June 1, 2000, the
determination shall be made on the basis of
the calendar years 1996 through 1999. 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
<PAGE>
-141-
for an Installed 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>
\ -142-
(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>
-143-
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 t
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 12 month period
beginning November 1, 1998.
R=0.25 for the 12 month period
beginning November 1, 1999.
<PAGE>
-144-
R=0 for the 12 month period
beginning November 1, 2000
and all subsequent 12 month
periods.
(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 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.
<PAGE>
-145-
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 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.
<PAGE>
-146-
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.
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).
<PAGE>
-147-
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.
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
<PAGE>
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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.
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
<PAGE>
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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>
-150-
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>
-151-
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.
(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
<PAGE>
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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.
(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
<PAGE>
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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 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.
-----------------------------------------------
<PAGE>
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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 Requirement
for the hour.
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).
<PAGE>
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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.
-------------------------------------------------------------------
(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
<PAGE>
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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:
(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.
<PAGE>
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(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 accordance with
Section 12.5(b)(iii) to have been furnished to
another Participant for the month.
<PAGE>
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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
<PAGE>
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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
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
<PAGE>
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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 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,
<PAGE>
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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
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 and
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.
<PAGE>
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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:
(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.
<PAGE>
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13.5 Satellite Membership. Each Participant which is responsible for the
--------------------
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 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 to other Participants in the hour pursuant
to Firm Contracts or System Contracts, together with any
associated electrical losses.
<PAGE>
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(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.
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.
<PAGE>
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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.
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.
<PAGE>
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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.
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).
<PAGE>
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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,
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 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 each such Entitlement for which the
Participant is permitted
<PAGE>
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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).
(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
<PAGE>
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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 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
<PAGE>
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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 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
<PAGE>
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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.
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
<PAGE>
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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
-------------
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
<PAGE>
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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 Net Interchange is positive, the Participant shall be
deemed to be furnishing Energy in the hour.
<PAGE>
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(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 a Participant is deemed to
have received or furnished in any hour is the difference
<PAGE>
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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 th
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 and 14.15 of this Agreement and Section
24 of the Tariff 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
<PAGE>
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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 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.
<PAGE>
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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 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.
<PAGE>
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(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 Clearing Price as defined and
determined in accordance with Section 14.9 or the Bid Price to
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
----
<PAGE>
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(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
----
(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
<PAGE>
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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 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
<PAGE>
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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)
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 of this Agreement and/or
<PAGE>
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Section 24 of the Tariff 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 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
<PAGE>
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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.
14.8 Determination of Energy Clearing Price.
--------------------------------------
For each hour, the System Operator shall determine the Energy Clearing
Price as follows:
<PAGE>
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(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 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
<PAGE>
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Regional Market Operations Committee) of that
category of Operating Reserve that are designated by
the System Operator for use in the hour.
(iii) For 10-Minute Spinning Reserve the System Operator
shall rank in order of lowest to highest the
10-Minute Spinning Reserve Lost Opportunity Prices
(as defined in Section 14.9(b)) of the resources
designated by the System Operator for the hour. 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 10-Minute Spinning Reserve
Lost Opportunity Prices for the hour of the
Entitlements that were designated by the System
Operator for use in the hour.
(b) The System Operator shall determine a 10-Minute Spinning
Reserve Lost Opportunity Price for each hour for use in
determining the Operating Reserve Clearing Price for 10-Minute
Spinning Reserve. For the purposes of Section 14.9, the
10-Minute Spinning Reserve Lost
<PAGE>
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Opportunity Price for a Participant's resource shall be the
amount by which the Energy Clearing Price for the hour exceeds
the resource's Dispatch price (not less than zero), plus the
----
Bid Price in the hour for each resource to provide 10-Minute
Spinning Reserve.
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 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
<PAGE>
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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 of this Agreement and
Section 24 of the Tariff, 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:
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).
<PAGE>
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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.
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
<PAGE>
-193-
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 for the
month and shall be used and disbursed after each
month in the following order:
<PAGE>
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(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 I
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
(iii) amounts owed to Participants for the month
pursuant to Section 14.5 shall then be paid.
<PAGE>
-195-
(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 deficient shares
shall be billed and pay into their shares of
the Fund the amounts required for payments
to Hydro-Quebec.
<PAGE>
-196-
(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 Participant under the HQ
Energy Banking Agreement during the
month to
<PAGE>
-197-
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>
-198-
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.
<PAGE>
-199-
(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 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
<PAGE>
-200-
deemed to be furnished to the Participant under th
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 Agreemen
to be held and disbursed by it through the 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
<PAGE>
-201-
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.
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.
<PAGE>
-202-
14.14 Congestion Uplift.
-----------------
(a) 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 of this
Agreement and with retail access, and to determine
whether subsection (b) of this Section, together with
an 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 (b),
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 Management 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
<PAGE>
-203-
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.
(b) Commencing on January 1, 2000, but subject to the
adoption of an amendment specifying the rights of
Participants and Non-Participants across constrained
interfaces within the NEPOOL Control Area and making
other necessary or appropriate changes in the
language of this subsection (b), 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 (a) 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
<PAGE>
-204-
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 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
<PAGE>
-205-
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.
(iii) The System Operator shall identify for each
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
<PAGE>
-206-
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, Internal Point-to-Point
Service or Through or Out Service charge,
whichever is applicable.
(c) 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 of
out-of-merit generation produced by the resource for
the hour.
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 of this Agreement
and Section 24 of the
<PAGE>
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Tariff. 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.
<PAGE>
-208-
PART FOUR
TRANSMISSION PROVISIONS
SECTION 15
OPERATION OF TRANSMISSION FACILITIES
------------------------------------
15.1 Definition of PTF. PTF or pool transmission facilities are the
-------------------
transmission facilities owned by Participants rated 69 kV or above
required to allow energy from significant power sources to move freely
on the New England transmission network, and include:
1. All transmission lines and associated facilities
owned by Participants rated 69 kV and above, except
for lines and associated facilities that contribute
little or no parallel capability to the NEPOOL
Transmission System (as defined in the Tariff). The
following do not constitute PTF:
(a) Those lines and associated facilities which
are required to serve local load only.
<PAGE>
-209-
(b) Generator leads, which are defined as radial
transmission from a generation bus to the
nearest point on the NEPOOL Transmission
System.
(c) Lines that are normally operated open.
2. Parallel linkages in network stations owned by
Participants (including substation facilities such as
transformers, circuit breakers and associated
equipment) interconnecting 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 will constitute PTF if both of the
following requirements are met for this connection:
<PAGE>
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(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.
4. Rights of way and land owned by Participants required
for the installation of facilities which constitute
PTF under (1), (2) or (3) above.
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 or catalogue
of PTF facilities.
The following examples indicate the intent of the above
definitions:
(i) Radial tap lines to local load are excluded.
<PAGE>
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(ii) Lines which loop, from two geographically
separate points on the NEPOOL Transmission
System, the supply to a load bus from the
NEPOOL Transmission System are included.
(iii) Lines which loop, from two geographically
separate points on the NEPOOL Transmission
System, the connections between a generator
bus and the NEPOOL Transmission System are
included.
(iv) Radial connections or connections from a
generating station to a single substation or
switching station on the NEPOOL Transmission
System 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
<PAGE>
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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 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
<PAGE>
-213-
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 the System Operator in accordance
with rules approved by the Regional Transmission Operations Committee.
15.5 Additions to or Upgrades of PTF. The possible need for an addition to
-------------------------------
or upgrade of PTF may be identified in connection with an application
or request for service under the Tariff, or in connection with a
request for the installation of or material change to a generation or
transmission facility, or may be separately identified by a NEPOOL
committee, a Participant or the System
<PAGE>
-214-
Operator. In such cases, a study, if necessary, to assess available
transmission capacity and, if necessary, a System Impact Study and a
Facility Study shall be performed by the affected Participant(s) in
whose Local Network(s) the addition or upgrade would or might be
effected or their designee(s), or the Regional Transmission Planning
Committee and/or the System Operator, in the case of a System Impact
Study, or the Committee's or the System Operator's designee(s) 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, as
appropriate, in accordance with the affected Participant's Local
Network Service Tariff, or in accordance with the applicable
methodology specified in Attachments C and D to the Tariff, and the
provisions of the Local Network Service Tariff or the applicable
provisions of Attachments I and J to the Tariff shall apply, as
appropriate, with respect to the payment of the costs of the study and
the other matters covered thereby.
If any of the studies referred to above indicates that new PTF
facilities or a facility modification or other PTF upgrades are
necessary to provide the requested service, or in connection with a new
or modified generation or
<PAGE>
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transmission facility, or otherwise in order 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, upon approval of the studies by the Regional
Transmission Planning Committee, subject to review by the System
Operator, one or more Transmission Providers shall be designated by the
Regional Transmission Planning Committee, subject to review by the
System Operator, to design and effect the construction or modification.
Upon the designation of a Transmission Provider to design and effect a
PTF addition or upgrade and the fixing of the cost responsibilities of
the Participants and Non-Participants and agreement as to the security
and other provisions of said arrangement, the Transmission Provider
designated to perform the construction shall, in accordance with the
terms of such arrangement and subject to Sections 18.4 and 18.5, use
its best efforts to obtain any necessary public approvals or permits,
to acquire any required rights of way or other property, and to effect
the proposed construction or modification.
<PAGE>
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Responsibility for the costs of new PTF or any modification or other
upgrade of PTF shall be determined, to the extent applicable, in
accordance with Parts V and VI and Schedule 11 of the Tariff, including
without limitation the provisions relating to responsibility for the
costs of new PTF or modifications or other upgrades to PTF exceeding
regional system, regulatory or other public requirements set forth in
paragraph (ii) of Schedule 11 to the Tariff.
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.
16.2 Obligation to Provide Regional Service. The Participants which own PTF
--------------------------------------
shall collectively provide through NEPOOL regional transmission service
over their
<PAGE>
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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 service under its Local Network Service Tariff or
otherwise (i) 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 and (ii) to permit the delivery to an Eligible Customer taking
Internal Point-to-Point Service under the Tariff of the Energy and/or
capacity covered by its Completed Application for that Internal
Point-to-Point Service.
<PAGE>
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A Local Network Service Tariff shall provide:
(i) for a pro rata allocation of monthly revenue requirements not
otherwise paid for through charges to Eligible Customers for
Local Point-to-Point Service among the Transmission Provider's
Network 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 from
Eligible Customers taking Regional Network Service and
Internal Point-to-Point Service 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 or Internal Point-to-Point Service pursuant to Section
16.6;
<PAGE>
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(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 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 receives a distribution
pursuant to Section 16.6 from NEPOOL out of revenues paid for
Through or Out
<PAGE>
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Service or for In Service (as defined in the Tariff), the
amounts received shall reduce its Local Network Service
revenue requirements; and
(v) that if the Transmission Provider receives transmission
revenues from an Eligible Customer taking Local Network
Service from that Transmission Provider with respect to an
Excepted Transaction, the amounts received shall reduce the
amount due from such Eligible Customer connected to the
Transmission Provider's transmission system for Local Network
Service provided thereto by the Transmission Provider rather
than reducing the Transmission Provider's total cost of
service.
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.
<PAGE>
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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 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
<PAGE>
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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:
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
<PAGE>
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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 delivered, 100% of the
megawatt mile flows with respect to the transaction shall be
deemed to occur on such Participant's system.
C. Internal Point-to-Point Service Revenues. The revenues
---------------------------------------------
received by NEPOOL each month for providing Internal
Point-to-Point Service and the revenues, if any, received by
NEPOOL each month for providing In Service (as defined in the
Tariff) shall be distributed among the Participants owning or
supporting PTF in proportion to their respective Annual
Transmission Revenue Requirements for PTF under Attachment F
to the Tariff.
D. 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
<PAGE>
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Operator (if the System Operator does not receive revenues for
that service under a separate tariff) 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 Prior
NEPOOL Agreement and the rules adopted thereunder, and shall
be distributed on or after the Second Effective Date in
accordance with Section 14.
E. Congestion Payments. Any congestion uplift charge received as
-------------------
a payment for transmission service pursuant to Section 24 of
the Tariff 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 six or more
-------- -------
members representing Participants
<PAGE>
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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 change. In determining whether the negative vote
total specified above has been reached, the 18% limitation specified in
Section 6.3 on the aggregate Voting Shares of any Participant and its
Related Persons shall be applicable. 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
<PAGE>
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approved prior to November 1, 1996 by the Management
Committee.
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
<PAGE>
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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.
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
<PAGE>
-229-
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 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
<PAGE>
-230-
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 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.
<PAGE>
-231-
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 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
<PAGE>
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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 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
<PAGE>
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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 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.
<PAGE>
-234-
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 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.
<PAGE>
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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 Responsibilities with a mix of
generation and other resources reasonably comparable as to economics
and types to that being developed for New England.
<PAGE>
-236-
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 Automatic Generation Control equipment as the
Management Committee may determine to be required in
<PAGE>
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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
<PAGE>
-238-
plan 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 by 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
<PAGE>
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not proceed to implement such plan unless the Participant or the
Non-Participant on whose behalf the Participant has submitted its plan
takes such action or constructs at its expense 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.
<PAGE>
-240-
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.
19.2 NEPOOL Expenses. Commencing on January 1, 1999, or such other date as
----------------
the Commission may determine, most expenses of the System Operator are
to be recovered by it directly from Participants and Non-Participants
under the ISO's Tariff for Transmission Dispatch and Power
Administration (the "ISO Tariff") and shall cease to be NEPOOL
expenses. At such time, whether or not the Second Effective Date has
occurred, the payment of a portion of NEPEX expenses from the Savings
Fund in accordance with the Prior NEPOOL Agreement shall terminate.
Further, commencing as of such time, the balance of NEPOOL expenses
remaining to be paid after the application of (i) the annual fee to be
paid pursuant
<PAGE>
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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, except as otherwise provided in Sections 19.3
and 19.4, be allocated among and paid monthly by the Participants in
accordance with their respective Voting Shares.
19.3 Reallocation of Certain ISO Charges. Schedule 3 of the ISO Tariff (as
------------------------------------
defined in Section 19.2) provides for the allocation of a portion of
the ISO's expenses (the "Schedule 3 Expenses") to Participants in
accordance with their Voting Shares, as determined under the formula in
Section 6.3, as in effect prior to December 31, 1998. However,
effective commencing with the month for which the revised Voting Shares
formula provided for in Section 1.1 of the Fortieth Agreement first
becomes effective, the Schedule 3 Expenses for the remaining months of
1999 shall be reallocated in the monthly billings to Participants which
combine charges for ISO and NEPOOL expenses as follows. Schedule 3
Expenses shall be allocated among Participants based on the Voting
Share formula in Section 6.3 of this Agreement as in effect prior to
December 31, 1998, but with a maximum allocation of 22% of Schedule 3
Expenses to any one Participant and its Related Persons. If the
aggregate Schedule 3 Expenses of a Participant and its Related
<PAGE>
-242-
Persons would be in excess of 22% if it were not for this limitation,
the remaining Schedule 3 Expenses for which such Participant and its
Related Persons would otherwise be liable shall be allocated each month
on a per capita basis to those Participants which receive a credit in
the computation of their Voting Shares for the month under at least one
of the P, E, C, X, M or R components of the Voting Share formula
specified in Section 6.3. It is expected that commencing in 2000 all of
the Schedule 3 Expenses may be recovered by the ISO under the ISO
Tariff on a transaction basis.
19.4 Restructuring Costs. The expense of restructuring NEPOOL
----------------------
("Restructuring Expense"), including but not limited to (i) software
development, hardware and system software costs for implementation of
the Tariff and the new market system, (ii) the costs of the formation
of the Independent System Operator and related separation costs, and
(iii) legal and consultant costs related to the amendment of the NEPOOL
Agreement (including the Tariff) and the proceeding with respect
thereto at the Federal Energy Regulatory Commission, has been funded
during the restructuring period by those Entities which have been the
Participants during such period. Commencing as the Second Effective
Date, the Restructuring Expense shall be amortized in equal monthly
amounts and repaid
<PAGE>
-243-
over the next 60 months with interest thereon at the rate of 8% per
annum from the date of payment. Each month during the first twelve
months of such period each Participant shall pay its percentage "X", as
determined below, of 1/60th of the Restructuring Expense, plus
accumulated interest, and each Participant or other Entity which
previously paid an unreimbursed portion of the aggregate Restructuring
Expense shall be entitled to receive each month its percentage "Y", as
determined below, of the aggregate amount to be paid for the month,
including accumulated interest. "X" and "Y" shall be determined in
accordance with the following formulas:
A
X = --- in which
A1
X is the percentage to be paid pursuant to
this Section for a month by a Participant of
the aggregate amount payable by all
Participants for the month.
<PAGE>
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A is the amount payable by the Participant for
the month under Schedule 2 of the ISO Tariff
(as defined in Section 19.2).
A1 is the aggregate amount payable by all
Participants for the month under Schedule 2
of the ISO Tariff.
B
Y = --- in which
B1
Y is the percentage to be received for a month
by a Participant or other Entity of the
aggregate amount to be received pursuant to
this Section by all Participants or other
Entities for the month.
B is the amount of Restructuring Expense paid
by the Participant or other Entity with
respect to the restructuring period which
has not previously been reimbursed.
<PAGE>
-245-
B1 is the aggregate amount of Restructuring
Expense paid by all Participants and other
Entities with respect to the restructuring
period which has not previously been
reimbursed.
The Participants agree to amend the Agreement within
twelve months after the Second Effective Date to
specify how the balance of the Restructuring Expense
is to be paid.
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 (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
<PAGE>
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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 those recovered
under the ISO Tariff, as defined in Section 19.2, and 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 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
<PAGE>
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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
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
<PAGE>
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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 o
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.
(f) The ISO shall have the right to appoint a non-voting member
and an alternate to each NEPOOL committee other than the
Management
<PAGE>
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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 the action of
<PAGE>
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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
<PAGE>
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other state authorities shall be provided an appropriate
opportunity to appear at meetings of the NEPOOL committees and
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
<PAGE>
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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 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
<PAGE>
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(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
(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.
<PAGE>
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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 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
<PAGE>
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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 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.
<PAGE>
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(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, 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.
<PAGE>
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(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.
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
<PAGE>
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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.
(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
<PAGE>
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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
<PAGE>
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brief statement explaining why the
Management Committee believes its decision
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
<PAGE>
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legal proceeding as to the facts determined
by the arbitrator but will not be conclusive
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.
<PAGE>
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(6) Other Disputes: In the event a dispute
---------------
arises with a Non- Participant which
receives or is eligible to receive service
under 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>
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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
<PAGE>
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of creditors, the Management Committee may terminate such
Participant's status as a Participant as of any time
thereafter.
(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
<PAGE>
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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 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
<PAGE>
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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 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
<PAGE>
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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 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, any Curtailment, 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
<PAGE>
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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 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.
<PAGE>
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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 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
<PAGE>
-272-
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).
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.
<PAGE>
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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.
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
<PAGE>
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Shares of all Participants; provided that an amendment shall not become
effective if six 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 18% limitation specified in Section 6.3
on the aggregate Voting Shares of any Participant and its Related
Persons shall be applicable.
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 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
<PAGE>
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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.
21.12 Termination. This Agreement shall continue in effect until terminated,
-----------
in accordance with the Commission's regulations, by Participants
represented by
<PAGE>
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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 Management
<PAGE>
-277-
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>
-278-
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
<PAGE>
-279-
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 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").
<PAGE>
-2-
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.
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.
<PAGE>
-3-
3. Transformers
All transformers connecting PTF transmission lines
shall be included in the analysis.
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
<PAGE>
-4-
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 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
<PAGE>
-5-
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 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.
<PAGE>
-6-
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 ownership of jointly-owned facilities or the
percentage of its support for facilities for which it
provides support.
EXHIBIT 10.28
POWER SUPPLY AGREEMENT
BETWEEN
THE UNITED ILLUMINATING COMPANY
AND
WISVEST-CONNECTICUT, LLC
DATED APRIL 16, 1999
<PAGE>
TABLE OF CONTENTS
Page
ARTICLE 1. Definitions 5
ARTICLE 2. Term 10
ARTICLE 3. Required Approvals and Conditions Precedent 11
ARTICLE 4. Obligations and Responsibilities 11
ARTICLE 5. Price 13
ARTICLE 6. Delivery of Electricity 13
ARTICLE 7. Billing and Payments 16
ARTICLE 8. Security Guaranty 18
ARTICLE 9. Termination 18
ARTICLE 10. Force Majeure 19
ARTICLE 11. Assignment 20
ARTICLE 12. Successors and Assigns 21
ARTICLE 13. Default and Termination 21
ARTICLE 14. Indemnification, Limitation of Damages and Liability 24
ARTICLE 15. Resolution of Disputes 28
ARTICLE 16. Interpretation 31
ARTICLE 17. Severability 32
ARTICLE 18. Auditing of Accounts and Records 32
ARTICLE 19. Regulation 32
ARTICLE 20. Notices 33
ARTICLE 21. Miscellaneous 34
<PAGE>
POWER SUPPLY AGREEMENT
This POWER SUPPLY AGREEMENT (the "Agreement") is made and entered into
as of the 16th day of April, 1999, by and between The United Illuminating
Company ("UI" or the "Company"), a Connecticut Corporation, and
Wisvest-Connecticut, LLC, a Connecticut limited liability company ("Supplier"),
(hereinafter sometimes referred to individually as a "Party" and collectively as
"Parties").
WHEREAS, the Company owns electric facilities and is engaged in the
generation, purchase, transmission, distribution and sale of electric energy in
the State of Connecticut; and
WHEREAS, the State of Connecticut enacted an electric industry
restructuring statute entitled "An Act Concerning Electric Restructuring" on
April 29, 1998 (the "Act"), which Act provides that after December 31, 1999, up
to thirty-five percent (35%) of the Company's retail customers residing within
UI's service territory in a "distressed municipality" as defined by the Act may
choose to purchase electricity from other suppliers, and that after June 30,
2000, all of the Company's retail customers may choose to purchase electricity
from other suppliers, or such customers may, instead, purchase Standard Offer
Service from the Company after December 31, 1999; and
WHEREAS, the Company is required by the Act to provide firm
all-requirements electric service to all retail customers in its service
territory through December 31, 1999, and thereafter until December 31, 2003, to
any retail customer that is eligible for and is taking electric service under
UI's Standard Offer Service Tariff filed with and approved by the CDPUC or such
other similar Company tariff approved by the CDPUC for those Customers that have
not chosen an alternate supplier of electricity; and
- 3 -
<PAGE>
WHEREAS, the Act encourages Connecticut electric companies to sell or
otherwise divest their electric generating assets to other entities; and
WHEREAS, the Company and Supplier have entered into a Purchase and Sale
Agreement dated October 2, 1998, pursuant to which Supplier has acquired certain
generation assets (the "Assets") from the Company, as further defined and
described in Section 2.1 of the Purchase and Sale Agreement; and
WHEREAS, the Company and Supplier desire that Supplier shall supply
electric capacity, energy and other generation-related products required by the
Restated NEPOOL Agreement, the NEPOOL Tariff and the ISO to the Company to
enable the Company to fulfill its obligation to provide Retail Service to retail
customers in its service territory through December 31, 1999; and
WHEREAS, the Company and Supplier desire that Supplier shall supply
electric capacity, energy and other generation-related products required by the
Restated NEPOOL Agreement, the NEPOOL Tariff and the ISO to the Company to
enable the Company to fulfill its obligation to provide Standard Offer Service
to retail customers in its service territory for the period January 1 through
June 30, 2000; and
WHEREAS, by entering into this Agreement, Supplier agrees to deliver
and sell and the Company agrees to receive and pay for electric capacity, energy
and other generation-related products required by the Restated NEPOOL Agreement,
the NEPOOL Tariff and by the ISO provided in accordance with the terms and
conditions of this Agreement and the Appendices.
NOW, THEREFORE, in consideration of the foregoing and the mutual
promises, covenants and agreements contained herein, and other good and valuable
consideration, the
- 4 -
<PAGE>
receipt and sufficiency of which are hereby acknowledged by the Parties, the
Company and Supplier agree as follows:
ARTICLE 1. Definitions
-----------
Whenever used in this Agreement, the following words and terms with
initial letters capitalized shall have the following meanings:
"Act" means the Connecticut electric industry restructuring statute
---
entitled "An Act Concerning Electric Restructuring," enacted April 29, 1998, as
amended from time to time.
"Agreement" means this Power Supply Agreement, including its
---------
Appendices, as amended from time to time.
"Assets" has the meaning set forth in Section 2.1 of the Purchase and Sale
------
Agreement.
"Business Day" means a day other than Saturday, Sunday or a day on which:
------------
(i) banks are legally closed for business in the State of New York; or (ii) UI
is closed for business.
"Closing" has the meaning set forth in Section 2.4 of the Purchase and Sale
-------
Agreement.
"Closing Date" has the meaning set forth in Section 2.4 of the Purchase and
------------
Sale Agreement.
"Company's Transmission System" means the electrical transmission system of
-----------------------------
UI, but not including UI's PTF.
"CDPUC" means the Connecticut Department of Public Utility Control, or its
-----
successor.
- 5 -
<PAGE>
"Delivered Energy" means the kilowatt-hours delivered to the meters of
----------------
those retail customers for whom the Company is responsible for providing Retail
Service or Standard Offer Service through Company's purchase of Wholesale
Transition Service from Supplier.
"Delivery Point" means the point or points of interconnection between
--------------
the Company's Transmission System and the transmission system owned by Northeast
Utilities as of the effective date of this Agreement.
"Estimation Process" means the process described in Appendix A of this
-------------------
Agreement for estimating the portion of Retail Service or Standard Offer Service
provided by Supplier.
"FERC" means the Federal Energy Regulatory Commission or its successor.
----
"Force Majeure" means any cause, event, condition or circumstance
--------------
beyond a Party's reasonable control, including, without limitation, storm,
flood, lightning, drought, earthquake, fire, explosion, civil disturbance, labor
dispute, act of God or the public enemy, or action of a court or public
authority; provided, that a cause, event, condition or circumstance shall be
deemed to constitute a Force Majeure only to the extent that the cause, event,
condition or circumstance (i) directly adversely affects the availability of the
transmission or distribution facility of NEPOOL or the Company such that said
facilities are not available for delivery by the Supplier of some or all
Wholesale Transition Service or Retail Assets Requirements to the Company or
(ii) directly adversely affects the delivery of Retail Service or Standard Offer
Service by the Company to some or all of the Company's customers. A cause,
event, condition or circumstance
- 6 -
<PAGE>
affecting the availability of, or cost of generating electricity at, any
particular electric generating facility shall not be considered to be a Force
Majeure for purposes of this Agreement. A cause, event, condition or
circumstance that merely causes an economic hardship to either Party shall not
be deemed a Force Majeure.
"Good Utility Practices" means any of the practices, methods and acts
-----------------------
engaged in or approved by a significant portion of the electric utility industry
in the geographic region covered by the North American Electric Reliability
Council (or any successor entity) during the relevant time period, or any of the
practices, methods or acts that, in the exercise of reasonable judgment 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 Practices
is not intended to be limited to the optimum practice, method or act to the
exclusion of all others, but rather to be acceptable practices, methods or acts
generally accepted in the region.
"ISO" means ISO New England, Inc., the independent system operator
---
established in accordance with the Restated NEPOOL Agreement, or its designees
or successor.
"ISO Tariff" means the tariff filed by the ISO with FERC pertaining to
----------
recovery of administrative, operating and maintenance, and other costs, as
amended from time to time, on file at FERC and in effect at the time the action
in question is taken.
"NEPOOL" means the New England Power Pool, or its successor.
------
"NEPOOL Tariff" means the NEPOOL Open Access Transmission Tariff, as
-------------
amended from time to time, on file at the FERC and in effect at the time the
action in question is taken.
- 7 -
<PAGE>
"NEPOOL Transmission System" means the PTF, i.e., Pool Transmission
----------------------------
Facilities.
"Parties" means the Company and Supplier collectively, and their respective
-------
successors and assigns.
"Party" means either the Company or Supplier as the context requires,
-----
and their respective successors and assigns.
"Price" means the amount per kilowatt-hour to be paid for Delivered
-----
Energy set forth in Article 5.
"PTF" means the facilities categorized as Pool Transmission Facilities
---
as defined in the Restated NEPOOL Agreement.
"Purchase and Sale Agreement" means the Purchase and Sale Agreement
-----------------------------
dated October 2, 1998, between UI and Supplier governing the sale and transfer
of the Assets from UI to Supplier.
"Restated NEPOOL Agreement" means the New England Power Pool Agreement
--------------------------
dated December 31, 1996, as amended from time to time, on file at FERC and in
effect at the time the action in question is taken.
"Retail Service" means firm, all-requirements electric service to the
--------------
Company's retail customers currently taking service under UI's retail service
tariffs, as presently in effect and as amended from time to time. Under the Act,
the Company currently is obligated to provide Retail Service until January 1,
2000.
- 8 -
<PAGE>
"Retained Assets" shall mean the Company's ownership interests in
----------------
Seabrook Station, Seabrook, New Hampshire, Millstone Station Unit No. 3,
Waterford, Connecticut, and its purchased power agreements with the Bridgeport
RESCO, Shelton Landfill and Derby Hydroelectric independent power producers and
with Hydro-Quebec.
"Retained Assets Requirements" means the provision of the installed
------------------------------
capability, operable capability, 10-minute spinning reserve, 10-minute
non-spinning reserve, 30-minute operating reserve, automatic generation control
and any other generation-related requirements and products defined in the
Restated NEPOOL Agreement or NEPOOL Tariff or otherwise necessary to fulfill
NEPOOL or ISO obligations, now or in the future, and any costs or losses
relating thereto, associated with the amount of Retail Service or Standard Offer
Service that the Company will provide using its Retained Assets, to the extent
that such requirements and products are not provided by the Retained Assets.
Retained Assets Requirements shall not include any energy associated with the
operable capability of the Retained Assets.
"Standard Offer Service" means firm, all-requirements electric service
----------------------
to the Company's retail customers taking service under UI's Standard Offer
Service Tariff. Under the Act, the Company currently will be obligated to
provide Standard Offer Service beginning on January 1, 2000.
"Standard Offer Service Tariff" refers to the "standard offer" to be
-------------------------------
determined by the CDPUC pursuant to Section 20 of the Act under which UI will
offer service to its retail customers beginning January 1, 2000, and terminating
on January 1, 2004.
"UI Tariff" means UI's Open Access Transmission Tariff, as amended from
---------
time to time, on file at the FERC and in effect at the time the action in
question is taken.
- 9 -
<PAGE>
"Wholesale Transition Service" means wholesale firm, all-requirements
-----------------------------
electric service (i.e., capacity, energy and ancillary services including,
---
without limitation: installed capability, operable capability, energy, 10-minute
spinning reserve, 10-minute non-spinning reserve, 30-minute operating reserve,
automatic generation control and associated losses necessary to fulfill all
NEPOOL and ISO obligations) required by the Company to meet the needs of its
retail customers taking Retail Service prior to January 1, 2000, and taking
Standard Offer Service from January 1, through June 30, 2000, in excess of the
amount of Retail Service and Standard Offer Service to be supplied by the
Company from its Retained Assets or by other means. Supplier, as a supplier of
Wholesale Transition Service, shall, subject to the provisions of the Restated
NEPOOL Agreement, NEPOOL Tariff and related ISO requirements, be responsible for
all ongoing requirements and associated costs for all the generation-related
requirements and products defined in the Restated NEPOOL Agreement, NEPOOL
Tariff and related ISO requirements and for such future additional
generation-related requirements and products associated with the Wholesale
Transition Service, and associated costs resulting from changes in the Restated
NEPOOL Agreement, the NEPOOL Tariff and related ISO requirements, from time to
time. To the extent that any NEPOOL, ISO or any successor entity's expenses or
costs are allocated to wholesale or retail suppliers, the portion of such costs
associated with Supplier's supply of Wholesale Transition Service will also be
the responsibility of Supplier.
ARTICLE 2. Term
----
The term of this Agreement shall commence at 12:01 a.m. on April 16,
1999, or such other date or time as is mutually agreed upon by the Parties, and
shall continue thereafter until the hour ending 2400 Eastern Prevailing Time on
June 30, 2000. Applicable provisions of this Agreement shall continue in effect
after termination of the Agreement to the extent necessary to provide for final
billings, billing adjustments, confidentiality of records and payments
pertaining to
- 10 -
<PAGE>
liability and indemnification obligations arising from acts or events that
occurred while this Agreement was in effect.
ARTICLE 3. Required Approvals and Conditions Precedent
-------------------------------------------
The commencement of the Parties' obligations under this Agreement are
subject to the receipt of all federal, state or local regulatory approvals or
permits necessary for the sale and purchase of the Wholesale Transition Service
to enable the Company to provide the Retail Service or Standard Offer Service
and to enable Supplier to provide Wholesale Transition Service contemplated
under this Agreement, including, without limitation, the approval of this
Agreement by the FERC and the CDPUC, all such approvals to be final and no
longer subject to rehearing, reconsideration or appeal; provided, however, that
Supplier's continuing obligations hereunder shall not be subject to the receipt
of any regulatory approvals or permits necessary for the operation of any
electric generating facility. Each Party shall use reasonable, good faith
efforts to acquire all regulatory approvals or permits and to assist the other
Party in acquiring such approvals or permits, including, without limitation,
FERC approval of this Agreement, prior to the Closing Date and to maintain
thereafter such regulatory approvals or permits.
ARTICLE 4. Obligations and Responsibilities.
--------------------------------
4.1 Purchase and Sale.
-----------------
Supplier shall sell and deliver Wholesale Transition Service and the
Company shall purchase and receive that service at the Delivery Point(s).
- 11 -
<PAGE>
4.2 Supplier's Obligation Unconditional.
-----------------------------------
Supplier's obligation hereunder to sell and deliver Wholesale
Transition Service to the Company shall be unconditional except for reasons of
Force Majeure and shall not be conditioned upon the availability of any
particular electric generating facilities, whether owned by the Supplier or
third parties, and the Supplier's obligations hereunder shall not be excused by
the unavailability of any such particular generating facilities for any reason.
Supplier is responsible for deliveries of Wholesale Transition Service to
accommodate changes in customer demand for Retail Service and Standard Offer
Service for any reason, including, but not limited to, seasonal factors, daily
load fluctuations, increased or decreased usage, demand-side management
activities, extreme weather and other similar events.
4.3 Retained Assets Requirements.
----------------------------
During the Term of this Agreement, Supplier shall have the obligation
to provide the Company's Retained Assets Requirements at no cost to the Company.
4.4 Supplier Responsibilities
-------------------------
Supplier shall be a member in good standing of NEPOOL and maintain an
own-load dispatch or settlement account established in accordance with the rules
and criteria established by the ISO throughout the term of this Agreement. In
addition, Supplier must satisfy any applicable registration and licensing
requirements, as the case may be, required by Connecticut law or CDPUC
regulations.
- 12 -
<PAGE>
4.5 Company's Responsibilities.
--------------------------
Company's obligation hereunder to purchase and receive Wholesale
transition Service from Seller shall be unconditional except for reasons of
Force Majeure.
The Company shall operate its respective transmission and distribution
systems in accordance with Good Utility Practices and in a manner which does not
discriminate against Supplier's deliveries of Wholesale Transition Service in
favor of any party or entity.
ARTICLE 5. Price
-----
For each kilowatt hour of Delivered Energy in each month during
calendar year 1999, as determined in accordance with Article 6, the Company
shall pay the Supplier 4.2 cents. For each kilowatt hour of Delivered Energy in
each month during calendar year 2000, as determined in accordance with Article
6, the Company shall pay the Supplier 3.4 cents. For the quantity of Delivered
Energy in each month, as determined in accordance with Article 6, the Company
shall make an additional payment to the Supplier equal to said quantity
multiplied by 0.054 multiplied by 3.0 cents.
ARTICLE 6. Delivery of Electricity
-----------------------
6.1 Delivery
--------
All electric energy associated with Wholesale Transition Service shall be
delivered to the Company in the form of three-phase, sixty-hertz alternating
current at the Delivery Point(s). Title to the electric energy and any other
associated services provided under Wholesale Transition Service shall pass to
the Company at the Delivery Point(s), and Supplier shall incur no expense or
risk beyond the Delivery Point(s) other than as provided for in this Article 6.
If the NEPOOL control area experiences congestion, Supplier will be responsible
for
- 13 -
<PAGE>
any congestion costs incurred by the Company in delivering Wholesale Transition
Service across the NEPOOL Transmission System to the extent such costs are
imposed by NEPOOL or the ISO on the Company. The Company may deduct congestion
costs from amounts the Company owes Supplier pursuant to Article 5 and this
Article 6. Supplier shall be responsible for all transmission and distribution
costs associated with the use of transmission systems outside of NEPOOL and for
any charges for local transmission service and for distribution service outside
of the Company's service territory needed to deliver Wholesale Transition
Service to the Delivery Points.
6.2 Losses.
------
Supplier shall be responsible for all transmission and distribution
losses incurred in delivering electric energy to the meters of the Company's
customers receiving Retail Service or Standard Offer Service. Supplier shall
provide any additional amounts of Wholesale Transition Service to the Company at
the Delivery Point(s) necessary to compensate for such losses at no additional
cost to the Company. The quantities required for this purpose in each hour of a
billing period shall be determined in accordance with NEPOOL's and the Company's
established and customary procedures for loss determination.
6.3 Determination and Reporting of Hourly Loads.
--------------------------------------------
(a) To meet NEPOOL obligations, the Retail Service or Standard Offer
Service loads for which Supplier is providing Wholesale Transition Service
pursuant to this Agreement, including losses, must be reported to NEPOOL or the
ISO. To accomplish this, the Company will estimate its total hourly Retail
Service or Standard Offer Service load based upon average load profiles
developed for each customer class, actual metered data as available and the
Company's actual total hourly load. Appendix A, attached hereto and incorporated
herein by reference, provides a general description of the estimation process
that the Company will initially employ
- 14 -
<PAGE>
(the "Estimation Process"). The Company reserves the right to modify the
Estimation Process in the future, provided that any such modification shall be
designed to improve the accuracy of its results. The Company will report to
NEPOOL or the ISO, on behalf of Supplier, the portion of Retail Service or
Standard Offer Service provided by Supplier.
(b) The Company will report to NEPOOL or the ISO the portion of the
hourly adjusted Retail Service or Standard Offer Service provided by Supplier by
12:00 noon of the second following Business Day, or at such other time as may be
required by the ISO or NEPOOL.
(c) Within ten business days after the end of each month, the Company
shall aggregate the portion of the hourly Retail Service or Standard Offer
Service provided by Supplier for the previous month as determined by the
Estimation Process. For purposes of Article 5, above, the result of the
Estimation Process will be deemed to be the quantity of Delivered Energy
associated with Wholesale Transition Service delivered by Supplier to the in the
applicable month.
(d) To refine the estimates of the portion of the monthly Retail
Service or Standard Offer Service provided by Supplier developed by the Company
using the Estimation Process, a monthly calculation will be performed by the
company to reconcile the original estimate of Supplier's Retail Service or
Standard Offer Service with actual customer usage based on meter readings. The
Company will apply any resulting billing adjustment (debit or credit) to
Supplier's account no later than the last day of the third month following the
billing month.
- 15 -
<PAGE>
ARTICLE 7. Billing and Payments
--------------------
Until reconciled with actual metered data, computations by the Company
of the charges for the purposes of billings hereunder shall be based on
estimates of Supplier's Delivered Energy in accordance with Article 6 and the
Price in accordance with Article 5. The Company shall calculate the amount
payable by the Company to the Supplier for a given month and provide the
calculation in the form of a statement to supplier on or before the twentieth
(20th) day of the following month. The calculation shall show the total amount
due and payable for the previous month. Each statement shall be subject to
adjustment for any errors in arithmetic computation, estimating, reconciliation
or otherwise only to the extent allowed by the terms of this Article 7.
On or before the last day of each month ("Due Date"), the Company shall
pay Supplier any amounts due and payable for Delivered Energy provided by
Supplier in the previous month by wire transfer in immediately available funds.
Any amount remaining unpaid after the Due Date shall bear interest at the Prime
Rate then in effect at the main office of
or such other lending institution as
agreed to by the Company and Supplier, from the Due Date to the date of payment
by the Company.
If Supplier disputes the amount set forth in any statement or payment,
Supplier shall provide written notice itemizing the basis for its dispute to the
Company within fifteen (15) days after the Due Date. Billing and payment
disputes shall be handled in accordance with the provisions of Article 15 of
this Agreement. Upon final resolution of the dispute, payment of any amount due
to a Party under the terms of the resolution shall be made within thirty (30)
days of the date of the final resolution, together with interest from and after
the original Due Date at the rate specified in this Article.
- 16 -
<PAGE>
The Company shall make retroactive adjustments to any statement for a
period of up to twelve (12) months from the date of the original statement in
order to reflect differences in charges resulting from the receipt of more
accurate data. Supplier may dispute such adjustment in writing within thirty
(30) days of receipt of the proposed adjustment and any such dispute shall be
handled in accordance with the provisions of Article 15 of this Agreement.
The Price set forth in Article 5 shall include full reimbursement to
Supplier, and Supplier shall be liable for and shall pay, or cause to be paid,
all taxes, fees and levies in effect on the Closing Date or thereafter which may
be assessed by any governmental entity upon the Wholesale Transition Service and
upon the Retained Assets Requirements prior to delivery to the Company at the
Delivery Point(s). If the Company is required to remit such tax, the amount of
such tax may be deducted from sums otherwise due to Supplier. Supplier shall
indemnify, defend and hold the Company harmless from claims for such taxes. To
the extent such taxes, fees and levies are assessed against the Company,
Supplier shall reimburse the Company therefor within 5 business days of a
written presentation by the Company to Supplier of evidence of the incurrence
payment by Company and amount thereof. The Price does not include reimbursement
for, and the Company shall be liable for and shall pay, cause to be paid, or
reimburse Supplier if Supplier has paid for, all taxes, fees and levies upon the
Retained Assets Requirements and upon the Wholesale Transition Service at and
after delivery to the Company at the Delivery Point(s) within 5 business days of
a written presentation by Supplier to Company of evidence of the incurrence,
payment by Supplier, and amount thereof. Each Party, upon written request and
where available, shall provide the other with a certificate of exemption or
other reasonably satisfactory evidence of exemption if either Party is exempt
from taxes, and shall use reasonable efforts to obtain and cooperate with
obtaining any exemption from or reduction of any tax. Each Party shall use
reasonable efforts to administer this Agreement and implement its provisions in
accordance with the intent to minimize the imposition of taxes, fees and levies.
For any new taxes, fees and levies assessed with respect to services provided
under this Agreement by Supplier after the Closing
- 17 -
<PAGE>
Date, regardless of where assessed, the Company will fully support and pursue in
good faith the recovery of such new tax, fee and levy imposed on Supplier from
the Company's Retail Service or Standard Offer Service customers. To the extent
the Company is allowed to recover such new taxes, fees and levies from its
Retail Service or Standard Offer Service customers, the Company shall reimburse
Supplier for such taxes, fees and levies paid by Supplier.
ARTICLE 8. Security Guaranty
-----------------
At the time this Agreement is made and entered into, Supplier shall enter into
an operational security guaranty (the "Security Guaranty") with UI in an
aggregate amount equal to [$5 Million Dollars ($5,000,000)] to ensure timely
performance by Supplier of its obligation to provide Delivered Energy under this
Agreement. Such Security Guaranty requirement shall be met by a corporate
guaranty from Wisvest Corporation.
ARTICLE 9. Termination
-----------
The Company may terminate this Agreement, if:
1. The Company is prevented by any governmental or regulatory
agency of competent jurisdiction from recovering from
customers taking Retail Service or Standard Offer Service
the cost of the Wholesale Transaction Service provided by
Supplier.
2. Any governmental or regulatory agency with jurisdiction
over the Company orders, implements, requires or causes
what the Company determines to be a material modification
or amendment of Retail Service or Standard Offer Service.
The Supplier may terminate this Agreement, if
- 18 -
<PAGE>
1. Any governmental or regulatory agency with jurisdiction over
the Supplier orders, implements, requires or causes what the Supplier
determines to be a material modification or amendment of Wholesale
transition Service.
ARTICLE 10. Force Majeure
-------------
10.1 Performance Excused by Force Majeure
------------------------------------
Except as otherwise expressly limited by other provisions of this
Agreement, and subject to the provisions of Section 10.2, below, the Parties
shall be excused from performing their respective obligations hereunder and
shall not be liable in damages or otherwise for any such failure to perform, to
the extent, but only to the extent, that such performance is prevented by a
"Force Majeure," as that term is defined in Article 1 of this Agreement.
10.2 Obligation To Diligently Cure Force Majeure
-------------------------------------------
If any Party shall rely on the occurrence of a Force Majeure as
described in Section 10.1, as a basis for being excused from performance of its
obligations under this Agreement, then the Party relying on the Force Majeure
shall:
(a) provide written notice to the other Party promptly but in no event
later than five (5) days after the occurrence of the Force Majeure, including
the nature, cause and date of the commencement of the Force Majeure and giving
an estimation of its expected scope and duration and the probable impact on the
performance of the affected Party's obligations hereunder under this Agreement;
- 19 -
<PAGE>
(b) exercise all reasonable efforts to continue to perform its obligations
under this Agreement;
(c) expeditiously take reasonable action to correct or cure the Force
Majeure or the conditions caused thereby giving rise to its excuse from
performance; provided that settlement of strikes or other labor disputes will be
within the sole discretion of the Party affected by such strike or labor
dispute;
(d) exercise all reasonable efforts to mitigate or limit damages to the
other Party; and
(e) provide prompt notice to the other Party of the cessation of the Force
Majeure or the conditions caused thereby giving rise to its excuse from
performance.
ARTICLE 11. Assignment
----------
No assignment, pledge or transfer of this Agreement or a Party's rights
or obligations under this Agreement shall be made by either Party without the
prior written consent of the other Party, which shall not be unreasonably
withheld, except that no prior written consent shall be required for assignment,
pledge or other transfer to another company in the same holding company system
as the assignor, pledgor or transferor, provided the assignee, pledgee or
transferee expressly assumes and demonstrates, to the reasonable satisfaction of
the non-assigning Party, that it can meet the obligations of the assignor,
pledgor or transferor under this Agreement.
- 20 -
<PAGE>
ARTICLE 12. Successors and Assigns
----------------------
This Agreement shall be binding upon and shall inure to the benefit of
the Parties and their successors and assignees.
ARTICLE 13. Default and Termination:
-----------------------
13.1 Events of Default:
-----------------
(a) The Company shall be deemed to be in default hereunder if:
(i) any representation or warranty made by it hereunder
shall be false in any material respect at any time during the term of this
Agreement, or it shall fail in any material respect to comply with, observe or
perform any covenant to be performed by it hereunder (unless such failure is due
to Force Majeure or is the result of Supplier's negligent or willful failure to
perform its obligations hereunder), and such failure is not remedied within the
Cure Period (as defined below); or, if such failure cannot be cured within the
Cure Period, such further period as shall reasonably be required to effect such
cure, so long as the Company initiates actions to effect a cure during the Cure
Period and at all times thereafter proceeds diligently to complete such cure as
quickly as possible. For purposes hereof, the Cure Period shall mean forty-five
(45) days following written notice from the Supplier to the Company specifying
the nature of the default in the Company's performance of its obligations
hereunder;
(ii) a custodian, receiver, liquidator or trustee for the
Company is appointed or takes possession and such appointment or possession
remains uncontested or in effect for more than sixty (60) days; or the Company
makes an assignment for the benefit of creditors or admits in writing its
inability to pay its debts as they mature; or the Company is adjudicated
bankrupt or insolvent; or an order for relief is entered under the Federal
Bankruptcy Code against the
- 21 -
<PAGE>
Company; or any material property of the Company is sequestered by court order
and the order remains in effect for more than sixty (60) days; or a petition is
filed against the Company under any bankruptcy, insolvency, reorganization,
arrangement, readjustment of debt, dissolution or liquidation law of any
jurisdiction, whether now or subsequently in effect, and is not stayed or
dismissed within sixty (60) days after filing; or the Company files a petition
in voluntary bankruptcy or seeking relief under any provision of any bankruptcy,
insolvency, reorganization, arrangement, readjustment of debt, dissolution or
liquidation law of any jurisdiction, whether now or subsequently in effect; or
the Company consents to the filing of any petition against it under any such
law; or the Company consents to the appointment or taking possession by a
custodian, receiver, trustee or liquidator of the Company or any material
portion of its property.
(b) Supplier shall be deemed to be in default hereunder if:
(i) any representation or warranty made by it hereunder
shall be false in any material respect at any time during the term of this
Agreement, or it shall fail in any material respect to comply with, observe or
perform any covenant to be performed by it under this Agreement (unless such
failure is due to Force Majeure or is the result of the Company's negligent or
willful failure to perform its obligations under this Agreement), or such
failure is not remedied within the Cure Period (as defined below); or, if such
failure cannot be cured within the Cure Period, such further period as shall
reasonably be required to effect such cure, so long as the Supplier initiates
actions to effect a cure during the Supplier's Cure Period and at all times
thereafter proceeds diligently to complete such cure as quickly as possible. For
purposes hereof, the Supplier's Cure Period shall mean forty-five (45) days
following written notice from the Company specifying the nature of the default
in the Supplier's performance of its obligations hereunder; or
- 22 -
<PAGE>
(ii) a custodian, receiver, liquidator or trustee for the
Supplier is appointed or takes possession and such appointment or possession
remains uncontested or in effect for more than sixty (60) days; or the Supplier
makes an assignment for the benefit of creditors or admits in writing its
inability to pay its debts as they mature; or the Supplier is adjudicated a
bankrupt or insolvent; or an order for relief is entered under the Federal
Bankruptcy Code against the Supplier; or any material property of the Supplier
is sequestered by court order and the order remains in effect for more than
sixty (60) days; or a petition is filed against the Supplier under any
bankruptcy, insolvency, reorganization, arrangement, readjustment of debt,
dissolution or liquidation law of any jurisdiction, whether now or subsequently
in effect, and is not stayed or dismissed within sixty (60) days after filing;
or the Supplier files a petition in voluntary bankruptcy or seeking relief under
any provision of any bankruptcy, insolvency, reorganization, arrangement,
readjustment of debt, dissolution or liquidation law of any jurisdiction,
whether now or subsequently in effect; or the Supplier consents to the filing of
any petition against it under any such law; or the Supplier consents to the
appointment or taking possession by a custodian, receiver, trustee or liquidator
of the Supplier or any material portion of its property.
13.2 Remedies Upon Occurrence of a Default:
-------------------------------------
(a) Upon the occurrence of a default by the Company under Section
13.1(a), the Supplier shall be entitled to terminate this Agreement, subject to
Section 13.2(c), and shall have such additional rights as are specified in
Section 13.2(c).
(b) Upon the occurrence of a default by Supplier under Section 13.1(b),
the Company shall be entitled to terminate this Agreement, subject to Section
13.2(c), and shall have such additional rights as are specified in Section
13.2(c).
- 23 -
<PAGE>
(c) (1) Any termination arising out of the exercise of the termination
rights specified in Sections 13.2 (a) and (b) may not take effect unless and
until an arbitrator, pursuant to Article 15, has made a ruling that the exercise
of such termination right was valid. The fact that one Party alleged to be in
material breach of this Agreement complies with the request of the other to cure
an alleged material breach shall not be considered by the arbitrator as an
admission against the Party or evidence that such Party was or was not in
material breach.
(2) Nothing in this Section 13.2 shall be construed to limit
the right of any Party to seek any remedies for a breach by the other Party of
its obligations hereunder, whether or not such breach results in a termination
of this Agreement under this Section 13.2 and whether or not such breach is
cured within the Company's Cure Period with respect to the Company or the
Supplier's Cure Period with respect to the Supplier, or during any period during
which the non- breaching party elects not to exercise its right to terminate
this Agreement. In particular, each Party shall have the right to seek a
specific performance of any of the obligations of the other Party hereunder. The
provisions of this Article 13 are intended only to provide the process through
which one Party may exercise and effectuate its right to terminate this
Agreement on the ground of material breach and default of this Agreement.
ARTICLE 14. Indemnification, Limitation of Damages and Liability
----------------------------------------------------
14.1 Indemnification by Supplier
---------------------------
Subject to the limitations of Section 14.4, Supplier shall indemnify,
defend and hold harmless the Company and their officers, directors, agents,
employees and affiliates from and against any and all claims, demands,
liabilities (including reasonable attorneys' fees), judgments, fines,
settlements and other amounts ("Damages") arising from any and all civil,
criminal, administrative or investigative proceedings ("Actions") relating to or
arising out of:
- 24 -
<PAGE>
(a) Any material failure of Supplier to observe or perform any term or
provision of this Agreement which it is Supplier's obligation to observe or
perform; and
(b) Any failure of any representation or warranty made by Supplier
herein to be true in any material respect.
14.2 Indemnification by the Company:
------------------------------
Subject to the limitations of Section 14.4, the Company shall
indemnify, defend and hold harmless Supplier, its officers, directors, agents,
employees and affiliates from an against any and all Damages arising from any
and all Actions relating to or arising out of:
(a) Any material failure of the Company to observe or perform any term
or provision of this Agreement which it is the Company's obligation to observe
or perform; and
(b) Any failure of any representation or warranty made by the Company
herein to be true in any material respect.
14.3 Indemnification Procedures
--------------------------
If any Party intends to seek indemnification under this Article 14 from
the other Party with respect to any Damages or Actions, the Party seeking
indemnification shall give the other Party notice of such Damages or Action
within fifteen (15) days of the commencement of, or actual knowledge of, such
Damages or Action. Such party seeking indemnification shall have the right, at
its sole cost and expense, to participate in the defense of any such Damages or
Action. The
- 25 -
<PAGE>
party seeking indemnification shall not compromise or settle any such Damages or
Action without the prior consent of the other party, which consent shall not be
unreasonably withheld.
14.4 Limitation of Consequential, Incidental and Indirect Damages
------------------------------------------------------------
To the fullest extent permissible by law, neither the Company nor
Supplier, nor their respective officers, directors, agents, employees, parent or
Affiliates, successors or assigns, or their respective officers, directors,
agents or employees, successors or assigns, shall be liable to the other Party
or its parent, subsidiaries, Affiliates, officers, directors, agents, employees,
successors or assigns, for claims, suits, actions or causes or action for
incidental, indirect, special, punitive, multiple or consequential damages
(including attorneys' fees or litigation costs) connected with or resulting from
performance or non-performance of the Agreement, or any actions undertaken in
connection with or related to this Agreement, including without limitation any
such damages which are based upon causes of action for breach of contract, tort
(including negligence and misrepresentation), breach of warranty, strict
liability, statute, operation of law, or any other theory of recovery. The
provisions of this Section 14.4 shall apply regardless of fault and shall
survive termination, cancellation, suspension, completion or expiration of this
Agreement.
14.5 Scope of Liability for Load Estimating Errors
---------------------------------------------
The process of estimation of the portion of the Retail Service and
Standard Offer Service provided by Supplier may involve statistical calculations
and estimating errors. The Company shall not be responsible for any estimating
errors and shall not be liable to Supplier for any costs that are associated
with such estimating errors to the extent that the Company performs load
estimation in accordance with its applicable Estimation Process, approved by the
CDPUC and in effect from time to time.
- 26 -
<PAGE>
14.6 Liability for Direct Damages.
----------------------------
Notwithstanding the provisions of this Article 14 and
Section 14.4 limiting damages, and subject to the duty to mitigate damages as
provided under common law damages recovery, both the Company and Supplier shall
be entitled to recover their actual, direct damages (i) incurred as a result of
the other Party's breach of this Agreement, or (ii) incurred as a result of any
other claim arising out of any action undertaken in connection with or related
to this Agreement. For purposes of avoiding any disputes about the difference
between direct damages and consequential damages, the Parties agree as follows:
(a) Unless excused by Force Majeure or the Company's failure to receive
the Wholesale Transition Service, if Suppler fails to deliver all or part of the
required Wholesale Transition Service, Supplier shall pay the Company, on the
date payment would otherwise be due to Supplier, an amount equal to the product
of (i) any deficiency in the energy component of Wholesale Transition Service
delivered and (ii) the positive difference, if any, obtained by subtracting the
per unit Price from the per unit Replacement Price. "Replacement Price" means
the price at which the Company, acting in a commercially reasonable manner,
purchases substitute or replacement electric energy and generation requirements
or products for the Wholesale Transition Service not delivered by Supplier, plus
any additional transportation and handling charges incurred by the Company to
the Delivery Point(s), less any costs the Company avoids as a consequence of the
failure to perform.
(b) The Company shall be entitled to recover direct damages for a
breach of this Agreement, subject to an obligation to mitigate such damages to
the extent practicable. Such direct damages are limited to the amounts due under
Section 14.6(a) and reasonable additional administrative and legal expenses
incurred as a result of Supplier's failure to perform under this Agreement.
- 27 -
<PAGE>
(c) Supplier shall be entitled to recover direct damages for a breach
of this Agreement, subject to an obligation to mitigate such damages to the
extent practicable. Such direct damages are limited to reasonable additional
administrative and legal expenses and the negative difference, if any, obtained
by subtracting the per unit Price from the per unit Sale Price incurred as a
result of the Company's failure to perform hereunder. "Sale Price" means the
price at which the Supplier, acting in a commercially reasonable manner, sells
available electric energy and generation requirements or products for the
Wholesale Transition Service not delivered to Company.
ARTICLE 15. Resolution of Disputes
----------------------
15.1 Administrative Committee Procedure
----------------------------------
Any and all disputes, disagreements or differences pertaining to or
arising out of this Agreement, including whether a dispute or matter is subject
to the dispute resolution procedures set forth in this Article 15, shall be
referred to representatives of each Party, who shall attempt to timely resolve
the disagreement. If such representatives can resolve the disagreement, such
resolution shall be reported in writing to and shall be binding upon the
Parties. If a party fails to appoint a representative within ten (10) days of
written notice of the existence of a disagreement, or the Parties'
representatives cannot resolve the disagreement within thirty (30) days, then
the matter shall proceed to arbitration as provided in Section 15.2.
15.2 Arbitration
-----------
If pursuant to Section 15.1, the Parties are unable to resolve any
dispute, disagreement or difference pertaining to or arising out of this
Agreement, including any disagreement regarding
- 28 -
<PAGE>
whether a dispute or other matter is subject to the dispute resolution
procedures set forth in this Article 14, such disagreement shall be settled by
arbitration and any award issued pursuant to such arbitration may be enforced in
any court of competent jurisdiction. Either Party may commence arbitration by
serving written notice thereof on the other Party, which notice shall designate
the issue(s) to be arbitrated, the specific provisions of this Agreement under
which such issues arose, such Party's proposed resolution of such issue(s), and
the Party's arbitrator. Such arbitration will be held in New Haven, Connecticut,
and, except as otherwise provided herein, shall be conducted in accordance with
the provisions of the commercial arbitration rules of the American Arbitration
Association ("AAA") in effect on the date of such notice, in the absence of
contrary agreement by the Parties and as specifically modified herein.
If a Party requests arbitration pursuant to the preceding paragraph,
the other Party shall designate its arbitrator within fifteen (15) days. If no
arbitrator has been selected and designated within fifteen (15) days of the date
of notice, then an arbitrator shall be selected in accordance with the
commercial arbitration rules of the AAA. The two arbitrators so designated shall
designate a third arbitrator within ten (10) days thereafter. In the event that
the two arbitrators so designated cannot agree upon a third arbitrator within
such second 10-day period, the third arbitrator shall be selected in accordance
with the commercial arbitration rules of the AAA.
The three arbitrators so designated shall conduct a hearing within
thirty (30) days of completion of their selection, and within fifteen (15) days
thereafter (unless such time is extended by agreement of the Parties) shall
notify the Parties to this Agreement of their decision in writing, stating the
reasons therefor and separately listing their findings of fact, conclusions of
law and order. The arbitrators shall be bound by the provisions of this
Agreement, where applicable, and shall have no power to amend, modify or add to
this Agreement in any manner. All factual determinations made by the arbitrators
shall be conclusive and binding on the Parties and not subject to judicial
review. Any conclusions of law made by the arbitrators shall be subject to
review in any court of competent jurisdiction within the State of Connecticut;
provided, however,
- 29 -
<PAGE>
that the order issued by the arbitrators shall be effective unless and until a
stay thereof is issued by the arbitrators or by such court, or such court
suspends the effectiveness of such order; provided further, however, that any
decisions of the arbitrators that affect matters subject to the jurisdiction of
FERC pursuant to Section 205 of the Federal Power Act must be filed with and
accepted for filing by the Commission, and a Party affected by a binding
arbitration decision may request that the Commission vacate or modify the
judgment based upon a finding that the judgment is contrary to the statutes or
regulations administered by the Commission.
15.3 Confidentiality. The existence, contents or results of any
---------------
arbitration hereunder may not be disclosed without the prior written consent of
both Parties; provided, however, either Party may make disclosures as may be
necessary to fulfill regulatory obligations to any regulatory bodies having
jurisdiction, and may inform their lenders, affiliates, auditors and insurers,
as necessary, under pledge of confidentiality and can consult with experts as
required in connection with the arbitration under pledge of confidentiality. If
any Party seeks preliminary injunctive relief from any court to preserve the
status quo or avoid irreparable harm pending mediation or arbitration, the
Parties agree to use best efforts to keep the court proceedings confidential to
the maximum extent permitted by law.
15.4 FERC Jurisdiction Over Certain Disputes.
---------------------------------------
15.4.1 Nothing in this Agreement shall preclude, or be
construed to preclude, any Party from filing a petition or complaint with the
FERC with respect to any arbitrable claim over which the FERC has jurisdiction.
In such case, the other Party may request that the FERC reject or waive
jurisdiction. If the FERC rejects or waives jurisdiction, with respect to all or
a portion of the claim, the portion of the claim not so accepted by the FERC
shall be resolved through arbitration, as provided in this Agreement. To the
extent that the FERC asserts or accepts jurisdiction over the claim, the
decision, finding of fact or order of the FERC shall be final and binding,
subject to judicial review under the Federal Power Act, and any arbitration
- 30 -
<PAGE>
proceedings that may have commenced prior to the assertion or acceptance of
jurisdiction by the FERC shall be stayed, pending the outcome of the FERC
proceedings.
15.4.2 The arbitration panels shall have no authority to
modify, and shall be conclusively bound by, any decision, finding of fact or
order of the FERC. However, to the extent that a decision, finding of fact or
order of the FERC does not provide a final or complete remedy to the Party
seeking relief, such Party may proceed to arbitration under this Article 15 to
secure such remedy, subject to the FERC decision, finding or order.
15.5 Preliminary Injunctive Relief. Nothing in this Article 15 shall
-------------------------------
preclude, or be construed to preclude, the resort by either Party to a court of
competent jurisdiction solely for the purposes of securing a temporary or
preliminary injunction to preserve the status quo or avoid irreparable harm
pending arbitration pursuant to this Article 15.
15.6 Expense
-------
The expense of arbitration shall be borne equally by both parties,
unless the arbitrators determine that a different allocation is warranted by the
facts and circumstances.
ARTICLE 16. Interpretation
--------------
The interpretation and performance of this Agreement shall be in
accordance with and shall be controlled by the laws of the State of Connecticut
without regard to Connecticut conflict of law principles.
- 31 -
<PAGE>
ARTICLE 17. Severability
------------
If any provision of this Agreement shall be held invalid, illegal or
unenforceable, the validity, legality and enforceability of the remaining
provisions shall in no way be affected or impaired thereby.
ARTICLE 18. Auditing of Accounts and Records
--------------------------------
Within two (2) years following a calendar year, during normal business
hours, Supplier and Company shall have the right to audit each other's accounts
and records pertaining to transactions under this Agreement during the calendar
year at the offices where such accounts and records are maintained; provided
that appropriate notice shall be given prior to any audit, and provided that the
audit shall be limited to those portions of such accounts and records that
relate to services provided to the other Party under this Agreement for said
calendar year. The Party being audited will be entitled to review the audit
report and any supporting materials. To the extent that audited information
includes confidential information, the auditing Party shall designate an
independent auditor to perform such audit.
ARTICLE 19: Regulation
----------
(a) This Agreement and all rights, obligations and performances of the
Parties hereunder, are subject to all applicable state and federal laws, and to
all duly promulgated orders and other duly authorized actions of governmental
authority having jurisdiction; provided, however, that Supplier and Company
agree that neither Party will seek to change or amend this Agreement in any way
through making application to the FERC under Sections 205 and 206 of the Federal
Power Act, and that this Agreement shall not be subject to change through
unilateral application by either Party under Sections 205 and 206 of the Federal
Power Act.
- 32 -
<PAGE>
(b) This Agreement must comply with all NEPOOL rules, criteria and
standards applicable now or in the future ("Rule(s)"). If, during the term of
this Agreement, the Restated NEPOOL Agreement is terminated or amended in a
manner that would eliminate or materially alter a Rule affecting a right or
obligation of a Party hereunder; or if such a Rule is eliminated or materially
altered by NEPOOL or the ISO, the Parties agree to negotiate in good faith in an
attempt to amend this Agreement to incorporate such changes as they deem
necessary to reflect the elimination or alteration of such Rule. The intent of
the Parties is that any such amendment reflect, as closely as possible, the
intent and substance of the Rule being replaced as was in effect prior to such
termination or amendment of the Restated NEPOOL Agreement or elimination or
alteration of the Rule. If the Parties are unable to reach agreement on such an
amendment, the Parties agree to submit the matter to arbitration under the terms
of Article 15 of this Agreement, and to seek a resolution of the matter
consistent with the above stated intent.
ARTICLE 20. Notices
-------
Any notice, demand or request permitted or required under this
Agreement shall be delivered in person or mailed by certified mail, postage
prepaid, return receipt requested or otherwise confirmed receipt, to a Party at
the applicable address set forth below:
To Supplier:
-----------
Derek Price
Wisvest-Connecticut, LLC
157 Chruch Street
New Haven, CT 06510
- 33 -
<PAGE>
To Company:
----------
Anthony J. Vallillo
Group Vice President - Client Services
The United Illuminating Company
157 Church Street
New Haven, CT 06506
Such addresses may be changed from time to time by written notice by
either Party to the other Party.
ARTICLE 21. Miscellaneous
-------------
(a) Each Party shall prepare, execute and deliver to the other Party
any documents reasonably required to implement any provision of this Agreement.
(b) Each Party represents to the other Party that this Agreement and
such Party's performance thereof are within the corporate powers of such Party
and have been duly authorized by proper corporate action on the part of such
Party.
(c) Any number of counterparts to this Agreement may be executed and
each shall have the same force and effect as the original.
(d) This Agreement shall constitute the entire understanding between
the Parties and shall supersede all prior correspondence and understandings
pertaining to the subject matter of this Agreement.
(e) Failure of either Party to enforce any provision of this Agreement
or to require performance by the other Party of any of the provisions hereof
shall not be construed as a waiver
- 34 -
<PAGE>
of such provisions or affect the validity of this Agreement, any part hereof, or
the right of either Party to thereafter enforce each and every provision.
(f) Article and Section headings used throughout this
Agreement are for the convenience of the Parties only and are not
to be construed as part of this Agreement.
IN WITNESS WHEREOF, Supplier and the Company have caused this Agreement
to be signed by their respective duly authorized representatives as of the date
first above written.
On Behalf of the Supplier WISVEST CORPORATION, SOLE MEMBER OF
WISVEST-CONNECTICUT, LLC
By /s/Francis Brzezinski
---------------------------------------
Francis Brzezinski
President
On Behalf of the Comapany THE UNITED ILLUMINATING COMPANY
By /s/Robert L. Fiscus
---------------------------------------
Robert L. Fiscus
Vice Chairman of the Board of Directors
And Chief Financial Officer
- 35 -
<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,
-------------------------------------------------------------------------
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $46,795 $50,393 $39,096 $45,791 $47,043 $43,129
Federal income taxes 34,551 41,951 35,252 30,186 31,342 40,439
State income taxes 6,216 12,976 8,506 8,651 9,001 10,544
Fixed charges 88,093 83,994 80,097 78,016 75,187 67,510
------------ ----------- ------------ ----------- ----------- ------------
Earnings available for fixed charges $175,655 $189,314 $162,951 $162,644 $162,573 $161,622
============ =========== ============ =========== =========== ============
FIXED CHARGES
Interest on long-term debt $73,772 $63,431 $66,305 $63,063 $60,214 $48,834
Other interest 10,301 16,723 9,534 10,881 10,931 14,807
One third of rental charges 4,020 3,840 4,258 4,072 4,042 3,869
------------ ----------- ------------ ----------- ----------- ------------
$88,093 $83,994 $80,097 $78,016 $75,187 $67,510
============ =========== ============ =========== =========== ============
RATIO OF EARNINGS TO FIXED
CHARGES 1.99 2.25 2.03 2.08 2.16 2.39
============ =========== ============ =========== =========== ============
</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,
--------------------------------------------------------------------
1994 1995 1996 1997 1998 1999
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
EARNINGS
Net income $46,795 $50,393 $39,096 $45,791 $47,043 $43,129
Federal income taxes 34,551 41,951 35,252 30,186 31,342 40,439
State income taxes 6,216 12,976 8,506 8,651 9,001 10,544
Fixed charges 88,093 83,994 80,097 78,016 75,187 67,510
----------- ---------- ----------- ---------- ---------- -----------
Earnings available for combined fixed
charges and preferred stock
dividend requirements $175,655 $189,314 $162,951 $162,644 $162,573 $161,622
=========== ========== =========== ========== ========== ===========
FIXED CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS
Interest on long-term debt $ 73,772 $ 63,431 $ 66,305 $ 63,063 $60,214 $48,834
Other interest 10,301 16,723 9,534 10,881 10,931 14,807
One third of rental charges 4,020 3,840 4,258 4,072 4,042 3,869
Preferred stock dividend requirements (1) 6,223 2,778 699 379 381 439
----------- ---------- ----------- ---------- ---------- -----------
$94,316 $86,772 $80,796 $78,395 $75,568 $67,949
=========== ========== =========== ========== ========== ===========
RATIO OF EARNINGS TO FIXED
CHARGES AND PREFERRED
STOCK DIVIDEND REQUIREMENTS 1.86 2.18 2.02 2.07 2.15 2.38
=========== ========== =========== ========== ========== ===========
</TABLE>
(1) Preferred Stock Dividends increased to reflect the pre-tax earnings required
to cover such dividend requirements.
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,213,320
<OTHER-PROPERTY-AND-INVEST> 38,507
<TOTAL-CURRENT-ASSETS> 173,657
<TOTAL-DEFERRED-CHARGES> 360,924
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 1,786,408
<COMMON> 282,034
<CAPITAL-SURPLUS-PAID-IN> (74)
<RETAINED-EARNINGS> 163,587
<TOTAL-COMMON-STOCKHOLDERS-EQ> 445,547
0
4,299
<LONG-TERM-DEBT-NET> 643,173
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 82,172
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 6,806
0
<CAPITAL-LEASE-OBLIGATIONS> 16,415
<LEASES-CURRENT> 354
<OTHER-ITEMS-CAPITAL-AND-LIAB> 587,642
<TOT-CAPITALIZATION-AND-LIAB> 1,786,408
<GROSS-OPERATING-REVENUE> 168,667
<INCOME-TAX-EXPENSE> 15,525
<OTHER-OPERATING-EXPENSES> 129,935
<TOTAL-OPERATING-EXPENSES> 145,460
<OPERATING-INCOME-LOSS> 23,207
<OTHER-INCOME-NET> 435
<INCOME-BEFORE-INTEREST-EXPEN> 23,642
<TOTAL-INTEREST-EXPENSE> 12,538
<NET-INCOME> 9,901
51
<EARNINGS-AVAILABLE-FOR-COMM> 9,850
<COMMON-STOCK-DIVIDENDS> 10,110
<TOTAL-INTEREST-ON-BONDS> 41,014
<CASH-FLOW-OPERATIONS> 18,796
<EPS-PRIMARY> 0.70
<EPS-DILUTED> 0.70
</TABLE>
